COVER PAGE
COVER PAGE - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Feb. 22, 2021 | Jun. 30, 2020 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2020 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Transition Report | false | ||
Entity File Number | 001-19514 | ||
Entity Registrant Name | Gulfport Energy Corp | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 73-1521290 | ||
Entity Address, Address Line One | 3001 Quail Springs Parkway | ||
Entity Address, City or Town | Oklahoma City, | ||
Entity Address, State or Province | OK | ||
Entity Address, Postal Zip Code | 73134 | ||
City Area Code | 405 | ||
Local Phone Number | 252-4600 | ||
Trading Symbol | GPORQ | ||
Title of 12(g) Security | Common Stock | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 174.4 | ||
Entity Common Stock, Shares Outstanding (in shares) | 160,762,186 | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of Gulfport Energy Corporation’s Proxy Statement for the 2021 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K. | ||
Amendment Flag | false | ||
Entity Central Index Key | 0000874499 | ||
Document Fiscal Year Focus | 2020 | ||
Document Fiscal Period Focus | FY |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Current assets: | ||
Cash and cash equivalents | $ 89,861 | $ 6,060 |
Accounts receivable—oil and natural gas sales | 119,879 | 121,210 |
Accounts receivable—joint interest and other | 12,200 | 47,975 |
Prepaid expenses and other current assets | 160,664 | 4,431 |
Short-term derivative instruments | 27,146 | 126,201 |
Total current assets | 409,750 | 305,877 |
Property and equipment: | ||
Oil and natural gas properties, full-cost accounting, $1,457,043 and $1,686,666 excluded from amortization in 2020 and 2019, respectively | 10,816,909 | 10,595,735 |
Other property and equipment | 88,538 | 96,719 |
Accumulated depletion, depreciation, amortization and impairment | (8,819,178) | (7,228,660) |
Property and equipment, net | 2,086,269 | 3,463,794 |
Other assets: | ||
Equity investments | 24,816 | 32,044 |
Long-term derivative instruments | 322 | 563 |
Deferred tax asset | 0 | 7,563 |
Operating lease assets | 342 | 14,168 |
Operating lease assets - related parties | 0 | 43,270 |
Other assets | 18,372 | 15,540 |
Total other assets | 43,852 | 113,148 |
Total assets | 2,539,871 | 3,882,819 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 244,903 | 415,218 |
Short-term derivative instruments | 11,641 | 303 |
Current portion of operating lease liabilities | 0 | 13,826 |
Current portion of operating lease liabilities - related parties | 0 | 21,220 |
Current maturities of long-term debt | 253,743 | 631 |
Total current liabilities | 510,287 | 451,198 |
Non-current liabilities: | ||
Long-term derivative instruments | 36,604 | 53,135 |
Asset retirement obligation—long-term | 0 | 60,355 |
Uncertain tax position liability | 0 | 3,127 |
Non-current operating lease liabilities | 0 | 342 |
Non-current operating lease liabilities - related parties | 0 | 22,050 |
Long-term debt, net of current maturities | 0 | 1,978,020 |
Total non-current liabilities | 36,604 | 2,117,029 |
Liabilities subject to compromise | 2,293,480 | 0 |
Total liabilities | 2,840,371 | 2,568,227 |
Commitments and contingencies (Notes 17 and 18) | ||
Preferred stock, $0.01 par value; 5,000,000 authorized (30,000 authorized as redeemable 12% cumulative preferred stock, Series A), and none issued and outstanding | 0 | 0 |
Stockholders’ (deficit) equity: | ||
Common stock - $0.01 par value, 200,000,000 shares authorized, 160,762,186 issued and outstanding in 2020 and 159,710,955 in 2019 | 1,607 | 1,597 |
Paid-in capital | 4,213,752 | 4,207,554 |
Accumulated other comprehensive loss | (43,000) | (46,833) |
Accumulated deficit | (4,472,859) | (2,847,726) |
Total stockholders’ (deficit) equity | (300,500) | 1,314,592 |
Total liabilities and stockholders’ (deficit) equity | $ 2,539,871 | $ 3,882,819 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Financial Position [Abstract] | ||
Capitalized costs of oil and natural gas properties excluded from amortization | $ 1,457,043 | $ 1,686,666 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized (in shares) | 5,000,000 | 5,000,000 |
Redeemable 12% cumulative preferred stock, shares authorized (in shares) | 30,000 | 30,000 |
Preferred Stock, dividend rate, percentage | 12.00% | 12.00% |
Preferred stock Series A, issued (in shares) | 0 | 0 |
Preferred stock Series A, outstanding (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 200,000,000 | 200,000,000 |
Common stock, shares issued (in shares) | 160,762,186 | 159,710,955 |
Common stock, shares outstanding (in shares) | 160,762,186 | 159,710,955 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
REVENUES: | |||
Net gain (loss) on natural gas, oil, and NGL derivatives | $ 65,291,000 | $ 208,360,000 | $ (123,479,000) |
Total Revenues | 866,542,000 | 1,563,126,000 | 1,551,701,000 |
OPERATING EXPENSES: | |||
Lease operating expenses | 54,235,000 | 73,496,000 | 79,716,000 |
Taxes other than income | 28,509,000 | 40,510,000 | 48,298,000 |
Midstream gathering and processing expenses | 456,318,000 | 508,843,000 | 486,845,000 |
Depreciation, depletion and amortization | 239,744,000 | 550,108,000 | 486,664,000 |
Impairment of oil and natural gas properties | 1,357,099,000 | 2,039,770,000 | 0 |
General and administrative expenses | 59,329,000 | 45,542,000 | 47,100,000 |
Restructuring and liability management expenses | 30,847,000 | 4,611,000 | 0 |
Accretion expense | 3,066,000 | 3,939,000 | 4,119,000 |
Total Operating Expenses | 2,229,147,000 | 3,266,819,000 | 1,152,742,000 |
(LOSS) INCOME FROM OPERATIONS | (1,362,605,000) | (1,703,693,000) | 398,959,000 |
OTHER EXPENSE (INCOME): | |||
Interest expense | 120,079,000 | 141,786,000 | 141,912,000 |
Interest income | (414,000) | (801,000) | (314,000) |
Gain on debt extinguishment | (49,579,000) | (48,630,000) | 0 |
Gain on sale of equity method investments | 0 | 0 | (124,768,000) |
Loss (income) from equity method investments, net | 11,055,000 | 210,148,000 | (49,904,000) |
Reorganization items, net | 152,359,000 | 0 | 0 |
Other expense, net | 21,738,000 | 3,725,000 | 1,542,000 |
Total Other Expense (Income) | 255,238,000 | 306,228,000 | (31,532,000) |
(LOSS) INCOME BEFORE INCOME TAXES | (1,617,843,000) | (2,009,921,000) | 430,491,000 |
INCOME TAX EXPENSE (BENEFIT) | 7,290,000 | (7,563,000) | (69,000) |
NET (LOSS) INCOME | $ (1,625,133,000) | $ (2,002,358,000) | $ 430,560,000 |
NET (LOSS) INCOME PER COMMON SHARE: | |||
Basic (in dollars per share) | $ (10.14) | $ (12.49) | $ 2.46 |
Diluted (in dollars per share) | $ (10.14) | $ (12.49) | $ 2.45 |
Weighted average common shares outstanding - Basic (shares) | 160,231,335 | 160,341,125 | 174,675,840 |
Weighted average common shares outstanding - Diluted (shares) | 160,231,335 | 160,341,125 | 175,398,706 |
Natural gas sales | |||
REVENUES: | |||
Revenue from contracts with customers | $ 671,535,000 | $ 1,135,381,000 | $ 1,318,472,000 |
Oil and condensate sales | |||
REVENUES: | |||
Revenue from contracts with customers | 62,902,000 | 117,937,000 | 177,793,000 |
Natural gas liquid sales | |||
REVENUES: | |||
Revenue from contracts with customers | $ 66,814,000 | $ 101,448,000 | $ 178,915,000 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive (Loss) Income - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | ||
Statement of Comprehensive Income [Abstract] | ||||
Net (loss) income | $ (1,625,133) | $ (2,002,358) | $ 430,560 | |
Foreign currency translation adjustment | [1] | 3,833 | 9,193 | (15,487) |
Other comprehensive income (loss) | 3,833 | 9,193 | (15,487) | |
Comprehensive (loss) income | $ (1,621,300) | $ (1,993,165) | $ 415,073 | |
[1] | No taxes were recorded for the years ended December 31, 2020, 2019 and 2018. |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive (Loss) Income (Parenthetical) - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Statement of Comprehensive Income [Abstract] | |||
Foreign currency translation adjustment, tax | $ 0 | $ 0 | $ 0 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' (Deficit) Equity - USD ($) $ in Thousands | Total | Common Stock | Paid-in Capital | Accumulated Other Comprehensive Loss | Accumulated Deficit |
Balance (in shares) at Dec. 31, 2017 | 183,105,910 | ||||
Balance, value at Dec. 31, 2017 | $ 3,101,614 | $ 1,831 | $ 4,416,250 | $ (40,539) | $ (1,275,928) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net (loss) income | 430,560 | 430,560 | |||
Other Comprehensive Income (loss) | (15,487) | (15,487) | |||
Stock-based Compensation | $ 11,332 | 11,332 | |||
Stock Repurchased (in shares) | (20,700,000) | (20,746,536) | |||
Shares Repurchased | $ (200,251) | $ (207) | (200,044) | ||
Issuance of Restricted Stock (in shares) | 626,671 | ||||
Issuance of Restricted Stock | 0 | $ 6 | (6) | ||
Balance (in shares) at Dec. 31, 2018 | 162,986,045 | ||||
Balance, value at Dec. 31, 2018 | 3,327,768 | $ 1,630 | 4,227,532 | (56,026) | (845,368) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net (loss) income | (2,002,358) | (2,002,358) | |||
Other Comprehensive Income (loss) | 9,193 | 9,193 | |||
Stock-based Compensation | 10,677 | 10,677 | |||
Stock Repurchased (in shares) | (3,951,198) | ||||
Shares Repurchased | (30,688) | $ (40) | (30,648) | ||
Issuance of Restricted Stock (in shares) | 676,108 | ||||
Issuance of Restricted Stock | $ 0 | $ 7 | (7) | ||
Balance (in shares) at Dec. 31, 2019 | 159,710,955 | 159,710,955 | |||
Balance, value at Dec. 31, 2019 | $ 1,314,592 | $ 1,597 | 4,207,554 | (46,833) | (2,847,726) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net (loss) income | (1,625,133) | (1,625,133) | |||
Other Comprehensive Income (loss) | 3,833 | 3,833 | |||
Stock-based Compensation | 6,444 | 6,444 | |||
Stock Repurchased (in shares) | (243,054) | ||||
Shares Repurchased | (236) | $ (3) | (233) | ||
Issuance of Restricted Stock (in shares) | 1,294,285 | ||||
Issuance of Restricted Stock | $ 0 | $ 13 | (13) | ||
Balance (in shares) at Dec. 31, 2020 | 160,762,186 | 160,762,186 | |||
Balance, value at Dec. 31, 2020 | $ (300,500) | $ 1,607 | $ 4,213,752 | $ (43,000) | $ (4,472,859) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Cash flows from operating activities: | |||
Net (loss) income | $ (1,625,133,000) | $ (2,002,358,000) | $ 430,560,000 |
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | |||
Depletion, depreciation and amortization | 239,744,000 | 550,108,000 | 486,664,000 |
Impairment of oil and natural gas properties | 1,357,099,000 | 2,039,770,000 | 0 |
Loss (income) from equity method investments | 11,055,000 | 210,289,000 | (49,625,000) |
Gain on debt extinguishment | (49,579,000) | (48,630,000) | 0 |
Net loss (gain) on derivative instruments | (65,291,000) | (208,360,000) | 123,479,000 |
Net cash receipts on settled derivative instruments | 159,394,000 | 123,130,000 | (58,428,000) |
Non-cash reorganization items, net | 21,956,000 | 0 | 0 |
Deferred income tax expense (benefit) | 7,290,000 | (7,563,000) | 1,208,000 |
Gain on sale of equity method investments and other assets | 0 | (220,000) | (124,768,000) |
Distributions from equity method investments | 0 | 2,457,000 | 3,206,000 |
Other, net | 31,984,000 | 15,178,000 | 17,039,000 |
Changes in operating assets and liabilities, net | 6,785,000 | 50,192,000 | (43,064,000) |
Net cash provided by operating activities | 95,304,000 | 723,993,000 | 786,271,000 |
Cash flows from investing activities: | |||
Additions to oil and natural gas properties | (367,287,000) | (720,057,000) | (899,083,000) |
Proceeds from sale of oil and gas properties | 50,971,000 | 48,527,000 | 5,114,000 |
Proceeds from sale of equity method investments | 0 | 0 | 226,487,000 |
Other, net | 1,729,000 | (3,241,000) | (9,392,000) |
Net cash used in investing activities | (314,587,000) | (674,771,000) | (676,874,000) |
Cash flows from financing activities: | |||
Principal payments on pre-petition revolving credit facility | (383,290,000) | (877,000,000) | (220,000,000) |
Borrowings on pre-petition revolving credit facility | 713,701,000 | 952,000,000 | 265,000,000 |
Principal payments on DIP credit facility | (90,000,000) | 0 | 0 |
Borrowings on DIP credit facility | 90,000,000 | 0 | 0 |
Repurchase of senior notes | (22,827,000) | (138,786,000) | 0 |
DIP credit facility financing fees | (2,988,000) | 0 | 0 |
Payments on repurchase of stock under approved stock repurchase programs | 0 | (30,000,000) | (200,251,000) |
Other, net | (1,512,000) | (1,673,000) | (1,406,000) |
Net cash provided (used in) by financing activities | 303,084,000 | (95,459,000) | (156,657,000) |
Net increase (decrease) in cash, cash equivalents and restricted cash | 83,801,000 | (46,237,000) | (47,260,000) |
Cash, cash equivalents and restricted cash at beginning of period | 6,060,000 | 52,297,000 | 99,557,000 |
Cash, cash equivalents and restricted cash at end of period | $ 89,861,000 | $ 6,060,000 | $ 52,297,000 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business Gulfport Energy Corporation, a Delaware corporation formed in 1997, is an independent natural gas-weighted exploration and production company focused on the production of natural gas, crude oil and NGL in the United States. The Company's principal properties are located in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code On November 13, 2020, Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC filed voluntary petitions of relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases are being administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The debtors continue to operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. The commencement of a voluntary proceeding in bankruptcy constituted an event of default that accelerated the Company's obligations under the Company's Pre-Petition Revolving Credit Facility and the indentures governing the Company's senior notes, resulting in the principal and interest due thereunder becoming immediately due and payable. Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code. The Company has applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements, which specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings have been classified as liabilities subject to compromise on the consolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness are recorded as reorganization items, net in the consolidated statements of operations for the year ended December 31, 2020. Refer to Note 2 for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization. Ability to Continue as a Going Concern The accompanying consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As discussed above, the filing of the Chapter 11 Cases constituted an event of default under the Company’s Pre-Petition Revolving Credit Facility and the indentures governing the Company's senior notes (the "Default"), resulting in the principal and interest due thereunder becoming immediately due and payable. The Company does not have sufficient cash on hand or available liquidity to repay these amounts due. These conditions and events raise substantial doubt about the Company’s ability to continue as a going concern. As part of the Chapter 11 Cases, the Company submitted the Plan to the Bankruptcy Court. The Company’s operations and its ability to develop and execute its business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is subject to a high degree of uncertainty and is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. There can be no assurance that the Company will confirm and consummate the plan of reorganization as contemplated by the RSA with certain holders of the Company’s senior notes or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern. While operating as a debtor-in-possession, the Company may settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business, for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan or other bankruptcy proceedings could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements, including liabilities subject to compromise which will be resolved in connection with the Chapter 11 Cases. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Company be unable to continue as a going concern or as a consequence of the Chapter 11 Cases. Risks and Uncertainties I n March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The measures have led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world have imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions. Gulfport remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations. The Company implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. Additionally, the Company has a crisis management team for health, safety and environmental matters and personnel issues, and has established a COVID-19 Response Team to address various impacts of the situation, as they have been developing. Gulfport has modified certain business practices (including remote working for its corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities. In May 2020, the Company began its phased transition back to the office for its corporate employees. As part of this transition, the Company put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. As of the date of this filing, Gulfport has transitioned the vast majority of its employees back to the corporate office; however, the Company continues to provide a balanced work schedule that allows for a significant portion of the work week to be performed remotely. The Company will continue to monitor trends and governmental guidelines and may adjust its return to office plans accordingly to ensure the health and safety of its employees. As a result of its business continuity measures, the Company has not experienced significant disruptions in executing its business operations in 2020. On March 27, 2020, the U.S. government enacted the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”). The CARES Act did not have a material impact on the Company’s consolidated financial statements. Gulfport is closely monitoring the impact of COVID-19 on all aspects of its business and the current commodity price environment and is unable to predict the impact it will have on its future financial position or operating results. Decreased demand for oil and natural gas as a result of the COVID-19 pandemic has put further downward pressure on commodity pricing. In the current depressed commodity price environment and period of economic uncertainty, the Company has taken the following operational and financial measures in 2020 to improve its balance sheet and preserve liquidity: • Reduced 2020 capital spending by more than 50% as compared to 2019 • Focused on operational efficiencies to reduce operating costs; including significant improvements in development and completion costs per lateral foot • Repurchased $73.3 million of unsecured notes at a discount • Evaluated economics across our portfolio and shut-in certain non-economical production in the second quarter of 2020 • Reduced recurring corporate general and administrative costs significantly through pay reductions, furloughs and reductions in force. Although management’s actions listed above have helped to improve the Company's liquidity and leverage profile, continued macro headwinds including the depressed state of energy capital markets and the extraordinarily low commodity price environments resulted in the Company filing for protection under Bankruptcy Rules as noted above. Principles of Consolidation The consolidated financial statements include the Company and its wholly-owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC, Puma Resources, Inc., Gulfport Appalachia LLC, Gulfport Midstream Holdings, LLC, Gulfport MidCon, LLC and Mule Sky LLC. All intercompany balances and transactions are eliminated in consolidation. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the consolidated financial statements. Accounts Receivable The Company sells oil and natural gas to various purchasers and participates in drilling, completion and operation of oil and natural gas wells with joint interest owners on properties the Company operates. The related receivables are classified as accounts receivable—oil and natural gas sales and accounts receivable—joint interest and other, respectively. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. No material allowance was deemed necessary at December 31, 2020 and December 31, 2019. Oil and Gas Properties The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Additionally, interest is capitalized on the cost of unproved oil and natural gas properties that are excluded from amortization for which exploration and development activities are in process or expected within the next 12 months. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue (only to the extent that the derivative instruments are treated as cash flow hedges for accounting purposes), and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of unproved properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can result in a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. As a result of the decline in commodity prices throughout 2020, the Company recognized ceiling test impairments of $1.4 billion for the year ended December 31, 2020. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties, are depleted by an equivalent units-of-production method, converting barrels to gas at the ratio of one barrel of oil to six Mcf of gas. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proved oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled approximately $1.5 billion and $1.7 billion at December 31, 2020 and December 31, 2019, respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. The Company accounts for its abandonment and restoration liabilities by recording a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. Other Property and Equipment Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years. Foreign Currency The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented and equity contributions are translated at the current exchange rate in effect at the date of the contribution. In addition, the Company has an equity investment in a U.S. company that has a subsidiary that is a Canadian entity whose functional currency is the Canadian dollar. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ (deficit) equity. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive loss, exclusive of taxes. (In thousands) December 31, 2017 (39,190) December 31, 2018 (54,677) December 31, 2019 (45,484) December 31, 2020 (41,651) Net (Loss) Income per Common Share Basic net (loss) income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net (loss) income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net (loss) income per common share are illustrated in Note 12 . Income Taxes Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 2003 – 2019 U.S. federal and 2009 - 2019 state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2020, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. Revenue Recognition The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. Sales of natural gas, oil and condensate and NGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to (i) whether the purchaser can direct the use of the product, (ii) the transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title. Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as midstream, gathering and processing expense in the accompanying consolidated statements of operations. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. The recognition of gains or losses on derivative instruments is outside the scope of ASC 606, Revenue from Contracts with Customers and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales. The Company has elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer, such as sales tax, use tax, value-added tax and similar taxes. See Note 9 for additional discussion of revenue from contracts with customers. Investments—Equity Method Investments in entities in which the Company owns an equity interest greater than 20% and less than 50% and/or investments in which it has significant influence are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the consolidated statements of operations. The Company reviews its investments annually to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. The Company did not record any impairment charges related to its investments in Mammoth and Grizzly for the year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded impairments of $160.8 million related to its investment in Mammoth Energy and $32.4 million related to its investment in Grizzly. There were no impairment charges recorded for the year ended December 31, 2018. See Note 5 for further discussion of Mammoth Energy and Grizzly impairments. Accounting for Stock-based Compensation Share-based payments to employees, including grants of restricted stock, are recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for restricted shares range between one Derivative Instruments The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and NGL production. All derivative instruments are recognized as assets or liabilities in the consolidated balance sheets, measured at fair value. The Company does not apply hedge accounting to derivative instruments. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets, the fair value determination of acquired assets and liabilities and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties. Supplemental cash flow and non-cash information Year Ended December 31, 2020 2019 2018 Supplemental disclosure of cash flow information: (In thousands) Cash paid for reorganization items, net $ 24,553 $ — $ — Interest payments $ 84,823 $ 142,664 $ 132,995 Income tax receipts $ — $ (1,794) $ — Supplemental disclosure of non-cash transactions: Capitalized stock-based compensation $ 2,860 $ 5,766 $ 4,533 Asset retirement obligation capitalized $ 2,358 $ 6,883 $ 1,452 Asset retirement obligation removed due to divestiture $ (2,213) $ (30,146) $ — Interest capitalized $ 907 $ 3,372 $ 4,470 Pre-petition revolver principal transfer to DIP credit facility $ 157,500 $ — $ — Fair value of contingent consideration asset on date of divestiture $ 23,090 $ (1,137) $ — Foreign currency translation gain (loss) on equity method investments $ 3,833 $ 9,193 $ (15,487) Reclassifications In the fourth quarter of 2020, the Company updated the presentation of certain costs on its consolidated statements of operations to better align its cost reporting with industry peers. In particular, the Company created a new expense line item titled “Taxes other than income” in its consolidated statement of operations. This new line item includes production taxes, property taxes and certain other non-income tax related costs incurred. Prior period amounts have been reclassified to align to this new approach. The reclassifications have no impact on previously reported total assets, liabilities, net (loss) income or total operating cash flows. Impact on Previously Reported Results During the third quarter of 2020, the Company identified that certain transportation activities during the years ended December 31, 2019 and 2018 were misclassified between "natural gas sales" and "midstream gathering and processing expenses" on its consolidated statements of operations. The Company assessed the materiality of this presentation on prior periods’ consolidated financial statements in accordance with the SEC Staff Accounting Bulletin No. 99, “Materiality”, codified in Accounting Standards Codification Topic 250, “Accounting Changes and Error Corrections". Based on this assessment, the Company concluded that the correction is not material to any previously issued financial statements. The correction had no impact on its consolidated balance sheets, consolidated statements of comprehensive income, consolidated statements of stockholders' equity or consolidated statements of cash flows. Additionally, the error had no impact on net loss or net loss per share. The Company will conform presentation of previously reported consolidated statements of operations in future filings. The following tables present the effect of the correction on all affected line items of our previously issued consolidated financial statements of operations for the years ended December 31, 2019 and 2018. Year Ended December 31, 2019 As Reported Adjustments As Revised (In thousands) Natural gas sales $ 918,263 $ 217,118 $ 1,135,381 Total Revenues $ 1,346,008 $ 217,118 $ 1,563,126 Midstream gathering and processing expenses $ 291,725 $ 217,118 $ 508,843 Total Operating Expenses $ 3,049,701 $ 217,118 $ 3,266,819 Year Ended December 31, 2018 As Reported Adjustments As Revised (In thousands) Natural gas sales $ 1,121,815 $ 196,657 $ 1,318,472 Total Revenues $ 1,355,044 $ 196,657 $ 1,551,701 Midstream gathering and processing expenses $ 290,188 $ 196,657 $ 486,845 Total Operating Expenses $ 956,085 $ 196,657 $ 1,152,742 Recent Adopted Accounting Pronouncements On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments , which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of the reported amount. The Company adopted the new standard using the prospective transition method, and it did not have a material impact on the Company's consolidated financial statements and related disclosures. |
Chapter 11 Proceedings
Chapter 11 Proceedings | 12 Months Ended |
Dec. 31, 2020 | |
Reorganizations [Abstract] | |
Chapter 11 Proceedings | CHAPTER 11 PROCEEDINGS Restructuring Support Agreement On November 13, 2020, the Debtors commenced the Chapter 11 Cases as described in Note 1 above. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for certain "first day" motions, including motions to obtain customary relief intended to continue ordinary course operations after the Petition Date. In addition, the Debtors have received authority to use cash collateral of the lenders under the DIP Credit Facility. On November 13, 2020, the Debtors entered into a restructuring support agreement with (i) over 95% of the lenders (the “Consenting RBL Lenders”) party to the Pre-Petition Revolving Credit Facility, dated as of December 27, 2013, by and among the Company, as borrower, each of the lenders party thereto, the Bank of Nova Scotia, as administrative agent and issuing bank, the joint lead arrangers and joint bookrunners, the co-syndication agents, and the co-documentation agents and (ii) certain holders (the “Consenting Noteholders,” and, together with the Consenting RBL Lenders, the “Consenting Stakeholders”) holding over two-thirds of the Company’s (a) 6.625% senior notes due 2023, issued under that certain Indenture, dated as of April 21, 2015, (b) 6.000% senior notes due 2024, issued under that certain Indenture, dated as of October 14, 2016, (c) 6.375% senior notes due 2025, issued under that certain Indenture, dated as of December 21, 2016, and (d) 6.375% senior notes due 2026, issued under that certain Indenture, dated as of October 11, 2017 (collectively, the “Unsecured Notes”), each by and among the Company, the subsidiary guarantors party thereto, and UMB Bank, N.A. as successor trustee. The RSA outlines the key elements and actions the Company plans to take as part of Chapter 11 process, including equitizing a significant portion of its prepetition indebtedness and rejecting or renegotiating certain contracts which will result in a materially improved balance sheet and cost structure. The RSA contains certain covenants on the part of each of Gulfport and the Consenting Stakeholders, including commitments by the Consenting Stakeholders to vote in favor of the Plan and commitments of Gulfport and the Consenting Stakeholders to negotiate in good faith to finalize the documents and agreements governing the Restructuring. The RSA also places certain conditions on the obligations of the parties and provides that the RSA may be terminated upon the occurrence of certain events, including, without limitation, the failure to achieve certain milestones and certain breaches by the parties under the RSA. One such condition is the requirement to obtain sufficient savings on certain midstream obligations (as set forth in the RSA) through rejection of such contracts and/or renegotiation of their terms. Although Gulfport intends to pursue the Restructuring in accordance with the terms set forth in the RSA, there can be no assurance that Gulfport will be successful in completing a restructuring or any other similar transaction on the terms set forth in the RSA, on different terms, or at all. Plan of Reorganization The Restructuring contemplated under the RSA will be pursued by Gulfport pursuant to a prearranged joint plan of reorganization (the “Plan”). Capitalized terms used under this heading titled “Joint Prearranged Chapter 11 Plan of Reorganization” but not otherwise defined herein shall have the meaning given to such terms in the Plan. The Plan can be found as an exhibit to this Form 10-K. Below is a summary of the treatment that the stakeholders of the Company would receive under the Plan: • each Holder of an Allowed Other Secured Claim shall receive, at the option of the applicable Debtor and with the consent of the Required Consenting Stakeholders (such consent not to be unreasonably withheld): (a) payment in full in Cash of its Allowed Other Secured Claim; (b) the collateral securing its Allowed Other Secured Claim; (c) Reinstatement of its Allowed Other Secured Claim; or (d) such other treatment rendering its Allowed Other Secured Claim unimpaired in accordance with section 1124 of the Bankruptcy Code; • each Holder of an Allowed Other Priority Claim shall receive treatment in a manner consistent with section 1129(a)(9) of the Bankruptcy Code; • each Holder of an Allowed RBL Claim shall receive, at the option of each such Holder, either (a) its Pro Rata share of the Exit RBL/Term Loan A Facility, if such Holder elects to participate in the Exit RBL/Term Loan A Facility or (b) its Pro Rata share of the Exit Term Loan B Facility, if such Holder does not elect to participate in the Exit RBL/Term Loan A Facility (including by not making any election with respect to the Exit Facility on the ballot); • each Holder of an Allowed General Unsecured Claim against Gulfport Parent shall receive in full and final satisfaction of such Claim, its Pro Rata share of the Gulfport Parent Equity Pool; provided, however, that once the Holders of Notes Claims receive distributions of 94% of the New Common Stock (prior to and not including any dilution by the Management Incentive Plan or any conversion of New Preferred Stock into New Common Stock) in the aggregate on account of their Notes Claims against all Debtors, the Holders of Notes Claims shall waive any excess recovery on account of their Pro Rata share of the Gulfport Parent Equity Pool until Holders of Allowed General Unsecured Claims against Gulfport Parent have received New Common Stock with a value sufficient to satisfy their Allowed General Unsecured Claims against Gulfport Parent in full (based on Plan Value); • each Holder of an Allowed General Unsecured Claim against Gulfport Subsidiaries shall receive in full and final satisfaction of such Claim, its Pro Rata share of: (a) the Gulfport Subsidiaries Equity Pool; (b) the Rights Offering Subscription Rights; and (c) the New Unsecured Notes; • each Holder of an Allowed Notes Claim against Gulfport Parent shall receive, in full and final satisfaction of such Claim, its Pro Rata share of the Gulfport Parent Equity Pool; provided, however, that once the Holders of Notes Claims receive distributions of 94% of the New Common Stock (prior to and not including any dilution by the Management Incentive Plan or any conversion of New Preferred Stock into New Common Stock) in the aggregate on account of their Notes Claims against all Debtors, the Holders of Notes Claims shall waive any excess recovery on account of their Pro Rata share of the Gulfport Parent Equity Pool until Holders of Allowed General Unsecured Claims against Gulfport Parent have received New Common Stock with a value sufficient to satisfy their Allowed General Unsecured Claims against Gulfport Parent in full (based on Plan Value); provided further, however, distributions to any Holder of a Notes Claim against Gulfport Parent shall be subject to the rights and terms of the Notes Indentures and the rights of the Notes Trustee to assert the Notes Trustee Charging Lien; • each Holder of an Allowed Notes Claim against Gulfport Subsidiaries shall receive, in full and final satisfaction of such Claim, its Pro Rata share of the: (i) Gulfport Subsidiaries Equity Pool, (ii) Rights Offering Subscription Rights, and (iii) New Unsecured Notes; provided, however, distributions to any Holder of a Notes Claim against Gulfport Subsidiaries shall be subject to the rights and terms of the Notes Indentures and the rights of the Notes Trustee to assert the Notes Trustee Charging Lien; • each Intercompany Claim shall be cancelled in exchange for the distributions contemplated by the Plan to Holders of Claims against and Interests in the respective Debtor entities and shall be considered settled pursuant to Bankruptcy Rule 9019; • each Holder of an Intercompany Interest shall receive no recovery or distribution and shall be Reinstated solely to the extent necessary to maintain the Debtors’ prepetition corporate structure for the ultimate benefit of the Holders of New Common Stock and New Preferred Stock; and • all Existing Interests (i.e. equity) in Gulfport Parent and all Allowed Section 510(b) Claims, if any, shall be cancelled, released, extinguished, and of no further force or effect. DIP Credit Facility Pursuant to the RSA, the Consenting RBL Lenders have agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of (a) $105 million of new money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations. In the current period, the Company incurred $3.0 million of fees related to the arrangement and funding of the DIP Credit Facility. The DIP Credit Facility was approved by the Bankruptcy Court on a final basis on December 18, 2020. See Note 6 for additional information. Executory Contracts Subject to certain exceptions, under the Bankruptcy Code, the Company may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company from performing its future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the Company's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Company to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Company, including where applicable a quantification of the Company's obligations under any such executory contract or unexpired lease of the Company, is qualified by any overriding rejection rights it has under the Bankruptcy Code. Potential Claims The Company has filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Company and each of its subsidiaries, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, which was set by the Bankruptcy Court as January 26, 2021. Governmental units are required to file proof of claims by May 12, 2021, the deadline that was set by the Bankruptcy Court. As of February 25, 2021, the Debtors have received approximately 2,200 proofs of claim for an aggregate amount of approximately $12.5 billion. The Company will continue to evaluate these claims throughout the Chapter 11 process and recognize or adjust amounts in future financial statements as necessary using the best information available at such time. Differences between amounts scheduled by the Company and claims by creditors will ultimately be reconciled and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and likely will continue after the Company emerges from bankruptcy. Financial Statement Classification of Liabilities Subject to Compromise The accompanying audited consolidated balance sheet as of December 31, 2020, includes amounts classified as liabilities subject to compromise, which represent liabilities the Company anticipates will be allowed as claims in the Chapter 11 Cases. These amounts represent the Company's current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material. Liabilities subject to compromise includes amounts related to the rejection of various executory contracts. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and/or unexpired leases are rejected. The nature of many of the potential claims arising under the Company's executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material. Damages related to rejected contracts are accounted for after they have been approved for rejection by the Bankruptcy Court. The following table summarizes the components of liabilities subject to compromise included on the Company's audited consolidated balance sheet as of December 31, 2020: December 31, 2020 (in thousands) Debt subject to compromise $ 2,005,219 Accounts payable and accrued liabilities 164,939 Asset retirement obligations 63,566 Accrued interest on debt subject to compromise 55,634 Other liabilities 4,122 Liabilities subject to compromise $ 2,293,480 Interest Expense The Company has discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest expense on liabilities subject to compromise not accrued in the consolidated statements of operations was approximately $15.3 million from the Petition Date through December 31, 2020. Reorganization Items, Net The Company has incurred and will continue to incur significant expenses, gains and losses associated with the reorganization, primarily the write-off of unamortized debt issuance costs, debt and equity financing fees, adjustments to allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The amount of these items, which are being incurred in reorganization items, net within the Company's accompanying audited consolidated statements of operations, are expected to significantly affect the Company's statements of operations. The Company has incurred adjustments for allowable claims related to its legal proceedings and executory contracts approved for rejections by the Bankruptcy Court, with additional adjustments possible in future periods. The following table summarizes the components in reorganization items, net included in the Company's audited consolidated statements of operations for the year ended December 31, 2020: Year Ended December 31, 2020 (in thousands) Adjustment to allowed claims $ 104,943 Legal and professional fees 24,905 Write off of unamortized issuance costs on debt subject to compromise 21,956 DIP credit facility financing fees 2,988 Gain on settlement of pre-petition accounts payable (2,433) Reorganization items, net $ 152,359 |
Divestitures
Divestitures | 12 Months Ended |
Dec. 31, 2020 | |
Business Combinations [Abstract] | |
Divestitures | DIVESTITURES Sale of Water Infrastructure Assets On January 2, 2020, the Company closed on the sale of its SCOOP water infrastructure assets to a third-party water service provider. The Company received $50.0 million in cash proceeds upon closing and has an opportunity to earn potential additional incentive payments over the next 15 years, subject to the Company's ability to meet certain thresholds which will be driven by, among other things, the Company's future development program and water production levels. The agreement contained no minimum volume commitments. The fair value of the contingent consideration as of the closing date was $23.1 million. See Note 15 for additional discussion of the fair value of the contingent consideration. The divested assets were included in the amortization base of the full cost pool and no gain or loss was recognized in the accompanying consolidated statements of operations as a result of the sale. Sale of Non-operated Utica Interests In December 2019, the Company entered into an agreement to divest certain non-operated interests in the Utica for approximately $29.0 million in cash subject to customary closing terms and adjustments. This sale closed on December 30, 2019. Sale of Bakken Overriding Royalty Interests During 2019, the Company announced the sale of certain overriding royalty interests associated with assets the Company held in the Bakken. The sale closed on December 11, 2019 and, net of purchase price adjustments, the Company received approximately $7.0 million of total proceeds. Sale of Southern Louisiana Assets In December 2018, the Company entered into an agreement to sell its non-core assets located in the West Cote Blanche Bay and Hackberry fields of southern Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions, with an effective date of August 15, 2018. The Company received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 13 for further discussion of the contingent consideration arrangement, which was determined to be an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | PROPERTY AND EQUIPMENT The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2020 and 2019 are as follows: December 31, 2020 2019 (In thousands) Oil and natural gas properties $ 10,816,909 $ 10,595,735 Other depreciable property and equipment 85,530 91,198 Land 3,008 5,521 Total property and equipment 10,905,447 10,692,454 Accumulated depletion, depreciation, amortization and impairment (8,819,178) (7,228,660) Property and equipment, net $ 2,086,269 $ 3,463,794 Under the full cost method of accounting, capitalized costs of oil and natural gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1 . During the years ended December 31, 2020 and 2019, the Company incurred $1.4 billion and $2.0 billion of impairments, respectively, as a result of its oil and natural gas properties exceeding its calculated ceiling. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for natural gas, oil and NGL, which significantly reduced proved reserves values and proved reserves. No impairment of oil and natural gas properties was required under the ceiling test for the year ended December 31, 2018. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $25.0 million, $30.1 million and $37.7 million for the years ended December 31, 2020, 2019 and 2018, respectively. The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $0.61, $1.08 and $0.96 per Mcfe for the years ended December 31, 2020, 2019 and 2018, respectively. The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2020: Costs Incurred in 2020 2019 2018 Prior to 2018 Total (In thousands) Acquisition costs $ 18,485 $ 8,067 $ 98,876 $ 1,330,895 $ 1,456,323 Exploration costs — — — — — Development costs — — — — — Capitalized interest — 121 172 427 720 Total oil and natural gas properties not subject to amortization $ 18,485 $ 8,188 $ 99,048 $ 1,331,322 $ 1,457,043 The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2020: December 31, 2020 (In thousands) Utica $ 793,441 SCOOP 662,614 Other 988 $ 1,457,043 As of December 31, 2019, approximately $1.7 billion of non-producing property costs were subject to amortization. The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2020 and 2019 is as follows: December 31, 2020 2019 (In thousands) Asset retirement obligation, beginning of period $ 60,355 $ 79,952 Liabilities incurred 2,358 5,935 Liabilities settled — (273) Liabilities removed due to divestitures (2,213) (30,146) Accretion expense 3,066 3,939 Revisions in estimated cash flows — 948 Total asset retirement obligation as of end of period 63,566 60,355 Less: amounts reclassified to liabilities subject to compromise (63,566) — Total asset retirement obligation reflected as non-current liabilities $ — $ 60,355 |
Equity Investments
Equity Investments | 12 Months Ended |
Dec. 31, 2020 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Investments | EQUITY INVESTMENTS Investments accounted for by the equity method consist of the following as of December 31, 2020 and 2019: Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2020 2019 2020 2019 2018 (In thousands) Investment in Grizzly Oil Sands ULC 24.5 % $ 24,816 $ 21,000 $ 377 $ 32,710 $ 510 Investment in Mammoth Energy Services, Inc. 21.5 % — 11,005 10,646 179,524 (49,969) Investment in Tatex Thailand II, LLC 23.5 % — — — (2,086) (241) Other equity investments (1) — % — 39 32 — (204) $ 24,816 $ 32,044 $ 11,055 $ 210,148 $ (49,904) _____________________ (1) Consists of sold/dissolved investments, including Windsor Midstream, LLC, which was dissolved as of December 31, 2020. Additionally, this includes the Company's investment in Strike Force that was sold in 2018, from which the Company recognized a gain of $96.4 million net of transaction fees, which is included in gain on sale of equity method investments in the accompanying consolidated statement of operations for the year ended December 31, 2018. The tables below summarize financial information for the Company's equity investments, as of December 31, 2020 and 2019. Summarized balance sheet information: December 31, 2020 2019 (In thousands) Current assets $ 483,303 $ 421,326 Noncurrent assets $ 1,092,495 $ 1,260,075 Current liabilities $ 132,978 $ 132,569 Noncurrent liabilities $ 148,240 $ 163,241 Summarized results of operations: December 31, 2020 2019 2018 (In thousands) Gross revenue $ 313,076 $ 625,012 $ 1,729,778 Net (loss) income $ (106,072) $ (76,523) $ 253,451 Grizzly Oil Sands ULC The Company, through its wholly owned subsidiary Grizzly Holdings, owns a 24.5% interest in Grizzly, a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. As of December 31, 2020, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company reviewed its investment in Grizzly at December 31, 2020 and December 31, 2019 for impairment based on certain qualitative and quantitative factors. This resulted in recording no impairment losses and $32.4 million for the years ended December 31, 2020 and 2019, respectively, which is included in loss from equity method investments, net in the accompanying consolidated statements of operations. The Company reviewed its investment in Grizzly for impairment at December 31, 2018 and determined no impairment was required. The Company did not pay any cash calls during 2020 as a result of its election to cease funding further capital calls in 2019. The Company paid $0.4 million in cash calls during the year ended December 31, 2019 prior to this election. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was increased by a $4.2 million foreign currency translation gain, increased by a $9.0 million foreign currency translation gain and decreased by a $15.2 million foreign currency translation loss for the years ended December 31, 2020, 2019 and 2018, respectively. The Company had $40.6 million and $44.8 million in accumulated other comprehensive loss in its accompanying consolidated balance sheets related to Grizzly at December 31, 2020 and December 31, 2019, respectively, that will be included in the calculations of future charge related to a sale or abandonment. Mammoth Energy Services, Inc. On June 29, 2018, the Company sold 1,235,600 shares of its Mammoth Energy common stock in an underwritten public offering for net proceeds of approximately $47.0 million. In connection with the Company's public offering of a portion of its shares of Mammoth Energy common stock, the Company granted the underwriters an option to purchase additional shares of its Mammoth Energy common stock. On July 26, 2018, the underwriters exercised this option, in part, and on July 30, 2018, the Company sold an additional 118,974 shares for net proceeds of a pproximately $4.5 million. Following the sales of these shares, the Company owned 9,829,548 shares, or 21.5% at December 31, 2018, of Mammoth Energy's outstanding common stock. As a result of the sales, the Company recorded a gain of $28.3 million, which is included in gain on sale of equity method investments in the accompanying consolidated statements of operations. The approximate fair value of the Company's investment in Mammoth Energy's common stock at December 31, 2019 was $21.6 million based on the quoted market price of Mammoth Energy's common stock. At December 31, 2020, the Company owned 9,829,548 shares, or 21.5%, of the outstanding common stock of Mammoth Energy. As a result of the net loss Mammoth sustained in the first quarter of 2020, we recorded a loss of $10.6 million for the year ended December 31, 2020 which reduced the Company's investment balance in Mammoth to zero. This is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. The Company's investment in Mammoth Energy was increased by a $0.2 million foreign currency gain and decreased by a $0.4 million foreign currency loss resulting from Mammoth Energy's foreign subsidiary for the years ended December 31, 2019 and 2018, respectively. During the year ended December 31, 2019, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of dividends in February 2019 and May 2019. The approximate fair value of the Company's investment in Mammoth Energy's common stock at December 31, 2020 was $43.7 million based on the quoted market price of Mammoth Energy's common stock. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations. Tatex Thailand II, LLC The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex") and received no distributions from Tatex during the year ended December 31, 2020. The Company received $2.1 million in distributions from Tatex during the year ended December 31, 2019. Tatex previously held an 8.5% interest in an entity holding a reserve base in Southeast Asia, including the Phu Horm Field, before selling its interest in June 2019. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2020 | |
Long-term Debt, Unclassified [Abstract] | |
Long-term Debt | LONG-TERM DEBT Long-term debt consisted of the following items as of December 31: 2020 2019 (In thousands) DIP credit facility $ 157,500 $ — Pre-petition revolving credit facility 292,910 120,000 6.625% senior unsecured notes due 2023 324,583 329,467 6.000% senior unsecured notes due 2024 579,568 603,428 6.375% senior unsecured notes due 2025 507,870 529,525 6.375% senior unsecured notes due 2026 374,617 397,529 Building loan 21,914 22,453 Net unamortized debt issuance costs — (23,751) Total Debt, net 2,258,962 1,978,651 Less: current maturities of long term debt (253,743) (631) Less: amounts reclassified to liabilities subject to compromise (2,005,219) — Total Debt reflected as long term $ — $ 1,978,020 Chapter 11 Proceedings Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our secured and unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, Section 362 of the Bankruptcy Code stays the creditors from taking any action as a result of the default. The principal amounts from the Senior Notes, Building Loan and Pre-Petition Revolving Credit Facility, other than letters of credit drawn on the Pre-Petition Revolving Credit Facility after the Petition Date, have been classified as liabilities subject to compromise on the accompanying audited consolidated balance sheet as of December 31, 2020. Additionally, non-cash adjustments were made to write off all of the related unamortized debt issuance costs of $22.0 million, which are included in reorganization items, net in the accompanying audited consolidated statements of operations for the year ended December 31, 2020, as discussed in Note 2 . Debtor-in-Possession Credit Agreement Pursuant to the RSA, the Consenting RBL Lenders have agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of (a) $105 million of new money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The terms and conditions of the DIP Credit Facility are set forth in that certain form of credit agreement governing the DIP Credit Facility. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations. In the current period, the Company incurred $3.0 million of fees related to the arrangement and funding of the DIP Credit Facility. The DIP Credit Facility was approved by the Bankruptcy Court on a final basis on December 18, 2020. Borrowings under the DIP Credit Facility will mature, and the lending commitments thereunder will terminate, upon the earliest to occur of: (a) August 30, 2021; (b) three (3) business days after the Petition Date, if the Interim Order and Hedging Order have not been entered prior to the expiration of such period; (c) thirty five (35) days (or a later date consented to by the Administrative Agent and the Majority Lenders in their sole discretion) after the entry of the Interim Order, if the Bankruptcy Court has not entered the Final Order on or prior to such date; (d) the effective date of an Approved Plan of Reorganization, (e) the consummation of a sale of all or substantially all of the equity and/or assets of the Debtors and budgeted and necessary expenses of the estates; (f) the date of the payment in full, in cash, of all Obligations (and the termination of all Commitments in accordance with the terms hereof); and (g) the date of termination of all Commitments and/or the acceleration of all of the Obligations under the Agreement and the other Loan Documents following the occurrence and during the continuance of an Event of Default. Borrowings under the DIP Credit Facility bear interest at a eurodollar rate or base rate, at our election, plus an applicable margin of 4.50% per annum for eurodollar loans and 3.50% per annum for base rate loans. At December 31, 2020, amounts borrowed under the DIP credit facility bore interest at a weighted average rate of 5.50%. In addition to paying interest on outstanding principal and letters of credit posted under the DIP Credit Facility, we are required to pay a commitment fee of 0.50% per annum to the lenders of the DIP Credit Facility in respect of the unutilized DIP commitments thereunder and a letter of credit fee equal to 0.20% per annum. The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit the Company's ability and the ability of its restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity hedging contracts with terms approved by the Bankruptcy Court in the hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by the Company's DIP Credit Facility lenders. Pre-Petition Revolving Credit Facility The Company has entered into a senior secured revolving credit facility agreement, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. On May 1, 2020, the Company entered into the fifteenth amendment to the Amended and Restated Credit Agreement. As part of the amendment, the Company's borrowing base and elected commitment were reduced from $1.2 billion and $1.0 billion, respectively, to $700.0 million. Additionally, the amendment added a requirement to maintain a ratio of Net Secured Debt to EBITDAX (as defined under the revolving credit agreement) not exceeding 2.00 to 1.00, deferred the requirement to maintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021, and added a limitation on the repurchase of unsecured notes, among other amendments. On July 27, 2020, the Company entered into the sixteenth amendment to the Amended and Restated Credit Agreement. Among other changes, the Sixteenth Amendment amends the Credit Agreement to: (i) require that, in the event of any issuances of Senior Notes, including Second Lien Notes, after the effective date, the then effective borrowing base will be reduced by a variable amount prescribed in the Credit Agreement to the extent the proceeds are not used to satisfy previously issued senior notes within 90 days of such issuance; (ii) require that each Loan Notice specify the amount of the then effective Borrowing Base and Pro Forma Borrowing Base, the Aggregate Elected Commitment Amount, and the current Total Outstandings, both with and without regard to the requested Borrowing; (iii) permit the Borrower or any Restricted Subsidiary to enter into obligations in connection with a Permitted Bond Hedge Transaction or Permitted Warrant Transaction; (iv) permit the Borrower to make any payments of Senior Notes and Subordinated Obligation prior to their scheduled maturity, in any event not to exceed $750 million or, if lesser, the net cash proceeds of any Senior Notes issued within 90 days before such payment; (v) require that the Senior Notes have a stated maturity date of no earlier than March 13, 2024, as well as not require payment of principal prior to such date, in order for the Borrower to be permitted to secure indebtedness under the Senior Notes; (vi) permit certain additional liens securing obligations in respect of the incurrence or issuance of any Permitted Refinancing Notes (as such term is defined in the Credit Agreement) not to exceed $750 million, subject to the terms of an intercreditor agreement; and (vii) amend and restate the Applicable Rate Grid. On October 8, 2020, the Company's borrowing base under its Pre-Petition Revolving Credit Facility was reduced for the second time in 2020 from $700 million to $580 million, thereby significantly reducing the Company's available liquidity. On October 15, 2020, the Company elected to not pay interest on certain Senior Notes outstanding triggering a default under the credit agreement. There was $292.9 million of outstanding borrowings under the Pre-Petition Revolving Credit Facility as of December 31, 2020 that were not rolled up into the DIP Credit Facility. This amount of indebtedness will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest at the default interest rate on amounts drawn after the Petition Date. The Company made certain adequate protection payments of $1.3 million on its Pre-Petition Revolving Credit Facility between the Petition Date and December 31, 2020 which reduced the amount of outstanding borrowings under the Pre-Petition Revolving Credit Facility classified as liabilities subject to compromise as of December 31, 2020 in the accompanying consolidated balance sheets. Additionally, as of December 31, 2020, we had an aggregate of $147.5 million of letters of credit outstanding under our Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of our assets. All of our wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit facility. During the fourth quarter of 2020, $171.8 million was drawn on letters of credit secured by the Company's Pre-Petition Revolving Credit Facility by its firm transportation providers. Of these drawn letters of credit, $96.2 million were drawn after the Petition Date. As these were post-petition activities, the post-petition letters of credit drawn are included in current portion of long-term debt, in the accompanying consolidated balance sheets. The pre-petition amounts are included in borrowings outstanding as of December 31, 2020 which are included in liabilities subject to compromise in the accompanying consolidated balance sheets. At December 31, 2020 the Company included $111.8 million in prepaid and other current assets in the accompanying consolidated balance sheets as an offset for the drawn letters of credit. A portion of the drawn letters of credit were netted against pre-petition accounts payable to the Company's firm transportation providers and another portion was charged to reorganization items, net in the accompanying consolidated statements of operations. As of December 31, 2020, amounts borrowed under the Pre-Petition Revolving Credit Facility bore interest at the weighted average rate of 3.15%. Senior Unsecured Notes Loan issuance costs related to the Senior Notes have been presented as a reduction to the principal amount of the Senior Notes at December 31, 2019. At December 31, 2020, there were no remaining unamortized loan issuance costs related to the Senior Notes. The Company expensed approximately $22.0 million in unamortized loan issuance costs related to the Senior Notes to reorganization items, net as a result of the Chapter 11 filing and the application of ASC 852. Building Loan In June 2015, the Company entered into a loan for the construction of its corporate headquarters in Oklahoma City, which was substantially completed in December 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum. The building loan matures on June 4, 2025. As of December 31, 2020, the total borrowings under the building loan were approximately $21.9 million, which has been classified as liabilities subject to compromise in the accompanying consolidated balance sheets as of December 31, 2020. Debt Repurchases In July of 2019, the Company's Board of Directors authorized $100 million of cash to be used to repurchase its Senior Notes in the open market at discounted values to par. In December 2019, the Company's Board of Directors increased the authorized size of its senior note repurchase program to $200 million in total. During the year ended December 31, 2020, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $73.3 million aggregate principal amount of its outstanding Notes for $22.8 million in cash and recognized a $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt. This gain is included in gain on debt extinguishment in the accompanying consolidated statements of operations. Interest Expense The following schedule shows the components of interest expense for the year ended December 31: 2020 2019 2018 (In thousands) Cash paid for interest $ 84,823 $ 142,664 $ 132,995 Change in accrued interest 30,600 (3,834) 7,266 Capitalized interest (907) (3,372) (4,470) Amortization of loan costs 5,563 6,328 6,121 Total interest expense $ 120,079 $ 141,786 $ 141,912 The Company capitalized approximately $0.9 million and $3.4 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2020 and 2019, respectively. Fair Value of Debt At December 31, 2020, the carrying value of the outstanding debt represented by the Notes was approximately $1.8 billion. Based on the quoted market prices (Level 1), the fair value of the Notes was determined to be approximately $1.2 billion at December 31, 2020. |
Changes in Capitalization
Changes in Capitalization | 12 Months Ended |
Dec. 31, 2020 | |
Stockholders' Equity Note [Abstract] | |
Changes in Capitalization | CHANGES IN CAPITALIZATION Stock Repurchases In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the Company's outstanding stock during 2018. In May 2018, the Company's board of directors authorized the expansion of its stock repurchase program, authorizing the Company to acquire up to an additional $100 million of its outstanding common stock during 2018 for a total of up to $200 million. This repurchase program was authorized to extend through December 31, 2018 and the Company repurchased 20.7 million shares of common stock in 2018 for $200.0 million in aggregate consideration. In January 2019, the board of directors of the Company approved a new stock repurchase program to acquire a portion of the Company's outstanding common stock within a 24-month period. During 2019, the Company repurchased 3.8 million shares for a cost of approximately $30 million under this board approved program. The program was suspended in the fourth quarter of 2019, and no further repurchases were made under this program. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement, Noncash Expense [Abstract] | |
Stock-Based Compensation | STOCK-BASED COMPENSATION The Company adopted the 2005 Plan in January 2005. The 2005 Plan was amended and restated in April 2013 with the 2013 Plan. During 2019, the Company further amended and restated the 2013 Plan with the 2019 Plan. The 2019 Plan provides for grants of options, stock appreciation rights, restricted awards (restricted stock and restricted stock units) and performance awards to employees, consultants and directors of the Company that, in aggregate, do not exceed 12,500,000 shares. The 2019 Plan is administered by the Compensation Committee of the Company's board of directors (the "Committee"). Among other responsibilities, the Committee selects individuals to receive awards and establishes the terms of awards. As of December 31, 2020, the Company has awarded an aggregate of 7,630,554 restricted stock units and 840,595 performance vesting restricted stock units under the 2019 Plan. During the years ended December 31, 2020, 2019 and 2018 the Company’s stock-based compensation cost was $16.3 million, $10.7 million and $11.3 million, respectively, of which the Company capitalized $2.9 million, $5.8 million and $4.5 million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations. The following table summarizes restricted stock unit and performance vesting restricted stock unit activity for the twelve months ended December 31, 2020, 2019 and 2018: Number of Weighted Number of Weighted Unvested shares as of January 1, 2018 976,027 $ 18.71 — $ — Granted 1,579,911 9.90 — — Vested (626,671) 18.05 — — Forfeited (393,456) 12.23 — — Unvested shares as of December 31, 2018 1,535,811 $ 11.57 — $ — Granted 4,011,073 $ 3.74 2,009,144 2.85 Vested (676,108) 12.89 — — Forfeited (772,458) 6.05 (225,484) 1.98 Unvested shares as of December 31, 2019 4,098,318 $ 4.73 1,783,660 $ 2.96 Granted 3,069,521 0.85 — — Vested (1,294,285) 5.73 — — Forfeited (4,171,041) 1.68 (943,065) 1.98 Unvested shares as of December 31, 2020 1,702,513 $ 4.74 840,595 $ 4.07 Restricted Stock Units Restricted stock units awarded under the 2019 Plan generally vest over a period of one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of December 31, 2020 related to outstanding restricted stock units was $5.2 million. The expense is expected to be recognized over a weighted average period of 1.31 years. Performance Vesting Restricted Stock Units During the year ended December 31, 2019, the Company awarded performance vesting restricted stock units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on Relative Total Shareholder Return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR of the companies in the Company’s designated peer group at the end of the performance period. Awards will be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately two years. The risk-free interest rates were based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a range of risk-free interest rates of 1.56% to 2.42% and a range of expected volatilities of 29.1% to 85.1% to estimate the fair value of performance vesting units granted during the year ended December 31, 2020. Unrecognized compensation expense as of December 31, 2020 related to performance vesting restricted stock units was $1.4 million. The expense is expected to be recognized over a weighted average period of 1.27 years. Cash Incentive Awards On March 16, 2020, the Board of Directors of the Company approved the Company's 2020 Incentive Plan (the "2020 Incentive Plan"). The 2020 Incentive Plan provided for incentive compensation opportunities ("Incentive Awards") for select employees of the Company that were tied to the achievement of one or more performance goals relating to certain financial and operational metrics over a period of time. During March 2020, the Company awarded Incentive Awards to certain of its executive officers under the 2020 Incentive Plan. The cash amount of each award to be ultimately received was based on the attainment of certain financial, operational and total shareholder return performance targets and was subject to the recipient's continuous employment. The Incentive Awards were considered liability awards as the ultimate amount of the award was based, at least in part, on the price of the Company's shares, and as such, were remeasured to fair value at the end of each reporting period. In August 2020 all previous unpaid amounts related to the Incentive Awards issued under the 2020 Incentive Plan were canceled and replaced with cash retention incentives, as discussed below. 2020 Compensation Adjustments On August 4, 2020, the Company's Board of Directors authorized a redesign of the incentive compensation program for the Company's workforce, including for its current named executive officers. In connection with a comprehensive review of the Company’s compensation programs and in consultation with its independent compensation consultant and legal advisors, the Board of Directors determined that significant changes were appropriate to retain and motivate the Company’s employees as a result of the ongoing uncertainty and unprecedented disruption in the oil and gas industry. All unpaid amounts previously awarded pursuant to the 2020 Incentive Plan and all restricted stock units granted in March 2020 to the Company's named executive officers were cancelled and replaced with cash retention incentives. These cash retention incentives are equally weighted between achievement of certain specified performance metrics and a service period. Of the cash retention incentives, 50% may be clawed back on an after-tax basis if an executive officer terminates employment for any reason other than a qualifying termination prior to the earlier of July 31, 2021, a change in control or completion of a restructuring, and the remaining 50% will be subject to repayment on an after-tax basis if established performance metrics are not met over performance periods from August 1, 2020 through July 31, 2021. In total, $13.5 million in cash retention incentives were paid to the Company's executives in August 2020. The transactions were considered a modification to the previously issued equity- and liability-classified awards, and the previously issued equity-classified awards were reclassified as liability awards. The after-tax value of the cash incentives paid to the Company's executives of $3.6 million as of December 31, 2020 was capitalized to prepaid expenses and other current assets in the accompanying consolidated balance sheets and will be amortized over the remaining service period. The Company immediately expensed the difference between the cash and after-tax value of the prepaid cash incentives of $4.8 million, which is not subject to the clawback provisions, and recognized an additional $1.5 million in stock compensation expense to adjust for the difference in cash retention amounts paid and expense previously recognized on the modified awards at the modification date. |
Revenue From Contracts With Cus
Revenue From Contracts With Customers | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customers | REVENUE FROM CONTRACTS WITH CUSTOMERS Revenue Recognition The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. Sales of natural gas, oil and condensate and NGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at the time control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. Transaction Price Allocated to Remaining Performance Obligations A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less. These contracts typically automatically renew under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the new revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally 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. Currently, the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration. Contract Balances Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $119.9 million and $121.2 million as of December 31, 2020 and December 31, 2019, respectively, and are reported in accounts receivable - oil and natural gas sales in the accompanying consolidated balance sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments. Prior-Period Performance Obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For the year ended December 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Leases | LEASES Nature of Leases The Company has operating leases on certain equipment and field offices with remaining lease durations in excess of one year. The Company recognizes a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized. The Company has entered into contracts for drilling rigs with varying terms with third parties to ensure operational continuity, cost control and rig availability in its operations. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year to two years, although at December 31, 2020, the Company did not have any active long-term drilling rig contracts in place. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at contract commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments, when applicable, are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of drilling costs are borne by other interest owners in our wells. Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray, a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective July 1, 2018, Stingray has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company through 2021 and the Company has agreed to pay Stingray a monthly service fee plus the associated costs of the services provided. As discussed further in Note 18 , the Company terminated the Master Services Agreement for pressure pumping with Stingray. As a result, in the first quarter of 2020, Gulfport removed the related right of use assets and lease liabilities associated with the terminated contract. The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. These agreements are typically structured with non-cancelable terms of one As of December 31, 2020, all lease liabilities have been classified as liabilities subject to compromise in the accompanying consolidated balance sheet. Discount Rate As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. Future amounts due under operating lease liabilities as of December 31, 2020 were as follows: (In thousands) 2021 $ 129 2022 115 2023 90 2024 30 Total lease payments 364 Less: Imputed interest (22) Less: amounts reclassified to liabilities subject to compromise (342) Total lease liabilities $ — Lease costs incurred for the years ended December 31, 2020 and 2019 consisted of the following: For the Year Ended December 31, 2020 2019 (In thousands) Operating lease cost $ 9,658 $ 24,960 Operating lease cost - related party — 22,440 Variable lease cost 586 2,172 Variable lease cost - related party — 66,924 Short-term lease cost 9,361 834 Total lease cost (1) $ 19,605 $ 117,330 _____________________ (1) The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations. Supplemental cash flow information for the years ended December 31, 2020 and 2019 related to leases was as follows: For the Year Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities (In thousands) Operating cash flows from operating leases 140 182 Investing cash flow from operating leases 10,272 24,263 Investing cash flow from operating leases - related party 6,800 84,750 The weighted-average remaining lease term as of December 31, 2020 was 3.03 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, 2020 was 4.22%. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES The income tax provision consists of the following: 2020 2019 2018 (In thousands) Current: State $ — $ — $ (1,530) Federal (273) (7) 253 Deferred: State 7,563 (7,556) 1,530 Federal — — (322) Total income tax expense (benefit) provision $ 7,290 $ (7,563) $ (69) A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2020 2019 2018 (In thousands) (Loss) income before federal income taxes $ (1,617,843) $ (2,009,921) $ 430,491 Expected income tax at statutory rate (339,747) (422,083) 90,403 State income taxes (14,696) (28,316) (511) Other differences 10,800 3,372 1,078 Change in valuation allowance due to current year activity 350,933 439,464 (91,039) Income tax expense (benefit) recorded $ 7,290 $ (7,563) $ (69) The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2020, 2019 and 2018 are estimated as follows: 2020 2019 2018 (In thousands) Deferred tax assets: Net operating loss carryforward $ 392,318 $ 269,851 $ 164,363 Oil and gas property basis difference 463,705 289,850 3,595 Investment in pass through entities 61,078 58,951 8,620 Stock-based compensation expense 1,223 1,440 616 Business energy investment tax credit 370 370 369 Charitable contributions carryover 318 297 269 Change in fair value of derivative instruments 7,656 11,219 2,761 Foreign tax credit carryforwards 523 943 2,009 Accrued liabilities 868 669 834 ARO liability 13,414 12,744 16,923 Non-oil and gas property basis difference — — 104 Lease liability 72 12,128 — Reorganization items 25,714 — — State net operating loss carryover 22,191 13,258 11,526 Interest expense carryforward — 23,818 — Total deferred tax assets 989,450 695,538 211,989 Valuation allowance for deferred tax assets (985,528) (647,575) (211,987) Deferred tax assets, net of valuation allowance 3,922 47,963 2 Deferred tax liabilities: Non-oil and gas property basis difference 575 1,859 — Change in fair value of derivative instruments 3,272 26,410 2 Right of use asset 72 12,128 — Other 3 3 — Total deferred tax liabilities 3,922 40,400 2 Net deferred tax asset $ — $ 7,563 $ — The company recognized income tax expense of $7.3 million in 2020 and an income tax benefit of $7.6 million in 2019. The net change is primarily related to the recognition of the valuation allowance against the Oklahoma state tax deferred asset that was not realized as a result of the Oklahoma water asset sale as previously expected. The Company has an available federal tax net operating loss carryforward estimated at approximately $1.9 billion as of December 31, 2020. These federal net operating loss carryforwards generated in tax years prior to 2018 will begin to expire in 2023. As a result of the Tax Cuts and Jobs Act, the 2018 through 2020 federal NOL carryforwards have no expiration. The Company also has state net operating loss carryovers of $441.0 million that began to expire in 2019 and federal foreign tax credit carryovers of $0.5 million that will expire in 2021. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. As a result of this analysis at December 31, 2020, the Company determined a valuation allowance was necessary with respect to its net deferred tax assets totaling $985.5 million. There was an increase of $338.0 million, an increase of $439.5 million and a decrease of $86.8 million to the valuation allowance during 2020, 2019 and 2018, respectively. The increase in the valuation allowance in 2020 and 2019 was primarily due to increases in net deferred tax assets from pre-tax losses resulting from impairments in the Company's oil and natural gas properties. The decrease in the valuation allowance in 2018 was primarily due to decreases in net deferred tax assets due to pre-tax income. On March 27, 2020, the CARES Act was enacted in response to the COVID-19 pandemic. The Act includes several significant provisions for corporations including allowing companies to carryback certain NOLs, increasing the amount of NOLs that corporations can use to offset income, and increasing the amount of deductible interest under section 163(j). The Company does not expect to be materially impacted by the CARES Act provision and does not anticipate the CARES Act to have a material effect on its ability to realized deferred tax assets. The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to potential limitations under Section 382 and its related tax regulations. The utilization of these attributes may be limited if certain ownership changes by 5% shareholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change or more than 50% in the beneficial ownership of the Company. As of December 31, 2020, the Company has completed a Section 382 analysis, which reflects that no ownership change has occurred to further limit the use of NOL carryforwards or other tax attributes. There are conditions that exist that are beyond the Company’s control which could cause an ownership change in the future and create a significant limitation on the Company's ability to utilize those tax attributes. On April 30, 2020, the board of directors of the Company adopted a tax benefits preservation plan in order to protect against a possible limitation on the Company’s ability to use its tax net operating losses and certain other tax benefits to reduce potential future U.S. federal income tax obligations. The Tax Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any person or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities. As of December 31, 2020, the Company has recorded a liability associated with uncertain tax positions of $3.8 million, which is included in liabilities subject to compromise in the accompanying consolidated balance sheet as of December 31, 2020. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | EARNINGS PER SHARE Reconciliations of the components of basic and diluted net income per common share are presented in the tables below: For the Year Ended December 31, 2020 2019 2018 (In thousands, except share data) Net (loss) income $ (1,625,133) $ (2,002,358) $ 430,560 Basic Shares 160,231,335 160,341,125 174,675,840 Basic EPS $ (10.14) $ (12.49) $ 2.46 Effect of dilutive securities: Stock options and awards — — 722,866 Dilutive Shares 160,231,335 160,341,125 175,398,706 Dilutive EPS $ (10.14) $ (12.49) $ 2.45 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | DERIVATIVE INSTRUMENTS Natural Gas, Oil and Natural Gas Liquids Derivative Instruments The Company seeks to mitigate risks related to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, collars and various types of option contracts. These contracts allow the Company to mitigate the impact of declines in future natural gas, oil and NGL prices by effectively locking in floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to the Company in periods when the future market prices of natural gas, oil and NGL that are higher than the hedged prices. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural gas. Below is a summary of the Company's open fixed price swap positions as of December 31, 2020. Index Daily Volume (MMBtu/day) Weighted 2021 NYMEX Henry Hub 410,000 $ 2.75 The Company entered into costless collars based off the NYMEX Henry Hub natural gas index. Each two-way price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty. Index Daily Volume (MMBtu/day) Weighted Average Floor/Ceiling Price 2021 NYMEX Henry Hub 250,000 $2.46/$2.81 2022 NYMEX Henry Hub 20,000 $2.80/$3.40 In the third quarter of 2019, the Company sold call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. Index Daily Volume (MMBtu/day) Weighted 2022 NYMEX Henry Hub 153,000 $ 2.90 2023 NYMEX Henry Hub 628,000 $ 2.90 In addition, the Company entered into natural gas basis swap positions. As of December 31, 2020, the Company had the following natural gas basis swap positions open: Gulfport Pays Gulfport Receives Daily Volume (MMBtu/day) Weighted Average Fixed Spread 2021 Rex Zone 3 NYMEX Plus Fixed Spread 35,000 $ (0.21) 2021 Tetco M2 NYMEX Plus Fixed Spread 60,000 $ (0.67) Contingent Consideration Arrangement The purchase and sale agreement for the sale of the Company's non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles the Company to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture. See below for threshold and potential payment amounts. Period Threshold (1) Payment to be received (2) January 2021 - June 2021 Greater than or equal to $60.65 $ 150,000 Between $52.62 - $60.65 Calculated Value (3) Less than or equal to $52.62 $ — _____________________ (1) Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media. (2) Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month. (3) If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03. Balance sheet presentation The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities, and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company's derivative instruments on a gross basis at December 31, 2020 and 2019: December 31, 2020 2019 (In thousands) Commodity derivative instruments $ 27,146 $ 125,383 Contingent consideration arrangement — 818 Total short-term derivative instruments – asset $ 27,146 $ 126,201 Commodity derivative instruments 322 — Contingent consideration arrangement — 563 Total long-term derivative instruments – asset $ 322 $ 563 Total short-term derivative instruments – liability $ 11,641 $ 303 Total long-term derivative instruments – liability $ 36,604 $ 53,135 Gains and losses The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2020, 2019, and 2018. Net gain (loss) on derivative instruments For the Year Ended December 31, 2020 2019 2018 (In thousands) Natural gas derivatives $ 23,765 $ 194,450 $ (116,130) Oil derivatives 43,510 7,035 (13,084) NGL derivatives (603) 6,632 5,735 Contingent consideration arrangement (1,381) 243 — Total $ 65,291 $ 208,360 $ (123,479) Offsetting of derivative assets and liabilities As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value. As of December 31, 2020 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 27,468 $ (25,730) $ 1,738 Derivative liabilities $ (48,245) $ 25,730 $ (22,515) As of December 31, 2019 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 126,764 $ (53,438) $ 73,326 Derivative liabilities $ (53,438) $ 53,438 $ — Concentration of Credit Risk |
Restructuring And Liability Man
Restructuring And Liability Management | 12 Months Ended |
Dec. 31, 2020 | |
Restructuring and Related Activities [Abstract] | |
Restructuring And Liability Management | RESTRUCTURING AND LIABILITY MANAGEMENT EXPENSES In the third quarter of 2020 and fourth quarter of 2019, the Company announced and completed workforce reductions representing approximately 10% and 13%, respectively, of its headcount. Restructuring charges related to the reduction in workforce primarily consisted of one-time employee-related termination benefits. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability management alternatives during 2020 prior to the filing of the Chapter 11 Cases. The following table summarizes the expenses related to the Company's reductions in workforce as well as expenses incurred related to liability management efforts in the accompanying consolidated statements of operations for the years ended December 31, 2020 and 2019: For the Year Ended December 31, 2020 2019 (in thousands) Reduction in workforce $ 1,460 $ 4,611 Liability management 29,387 — Total restructuring and liability management expenses $ 30,847 $ 4,611 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories: Level 1 – Quoted prices in active markets for identical assets and liabilities. Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. Level 3 – Significant inputs to the valuation model are unobservable. Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. Financial assets and liabilities The following tables summarize the Company’s financial assets and liabilities by valuation level as of December 31, 2020 and 2019: December 31, 2020 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 27,468 $ — Contingent consideration arrangement $ — $ — $ 6,200 Total assets $ — $ 27,468 $ 6,200 Liabilities: Derivative Instruments $ — $ 48,245 $ — December 31, 2019 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 126,764 $ — Liabilities: Derivative Instruments $ — $ 53,438 $ — The Company estimates the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. As discussed in Note 3 , the water infrastructure sale included a contingent consideration arrangement. As of December 31, 2020, the fair value of the contingent consideration was $6.2 million, of which $1.1 million is included in prepaid expenses and other assets and $5.1 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. As a result of a reduction in the future anticipated contingent consideration since the acquisition date, the Company recognized a loss of $16.6 million on changes in fair value of the contingent consideration during the year ended December 31, 2020, which is included in other expense (income) in the accompanying consolidated statements of operations. Settlements under the contingent consideration arrangement totaled $0.3 million during the year ended December 31, 2020. Non-financial assets and liabilities The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the year ended December 31, 2020 were approximately $2.4 million. The Company did not record any other than temporary impairments on its equity method investments during the year ended December 31, 2020, however the Company recorded impairments on its investments during the year ended December 31, 2019. Due to the unobservable nature of the inputs, the fair value of the Company's investment in Grizzly as of December 31, 2019 was estimated using assumptions that represent Level 3 inputs. The fair value of the Company's investment in Mammoth Energy as of December 31, 2019 was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares. Fair value of other financial instruments The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's construction loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities. See Note 6 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2020 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS In the ordinary course of business, the Company has conducted business activities with certain related parties. As of December 31, 2020, the Company held approximately 21.5% of Mammoth Energy's outstanding common stock as discussed above in Note 5 . Approximately $0.6 million, and $2.0 million of services provided by Mammoth Energy were included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2019 and 2018, respectively, with no material amounts for the year ended December 31, 2020. Approximately $3.1 million and $109.9 million of services provided by Mammoth Energy were capitalized to oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets during the years ended December 31, 2020 and 2019, respectively. At December 31, 2019, the Company owed Mammoth Energy approximately $8.4 million related to these services. Amounts owed to Mammoth Energy as of December 31, 2020 were immaterial. See Note 18 for additional information on litigation proceedings with Mammoth Energy entities. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments | COMMITMENTS Firm Transportation and Gathering Agreements The Company has contractual commitments with pipeline carriers for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing its potential liability. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in the Company's estimates of proved reserves. Additionally, one of the requirements provided for in the RSA is that the Company must permanently reduce its future demand reservation fees owed over the life of all of its firm transportation agreements, taken as a whole, by at least 50% of the amount of all such fees owed on October 31, 2020, as calculated on a PV-10 basis. Additionally, the Company must reduce the future firm transportation demand reservation volumes over the life of all of its firm transportation agreements, taken as a whole, by at least 35%. The below table reflects the Company's obligations as of December 31, 2020 excluding contemplation of contracts to be rejected throughout the Chapter 11 Cases. A summary of these commitments at December 31, 2020 are set forth in the table below: (In thousands) 2021 $ 370,343 2022 380,979 2023 379,171 2024 358,990 2025 272,123 Thereafter 2,013,119 Total $ 3,774,725 Future Sales Commitments The Company has entered into various firm sales contracts with third parties to deliver and sell natural gas. The Company expects to fulfill its delivery commitments primarily with production from proved developed reserves. The Company's proved reserves have generally been sufficient to satisfy its delivery commitments during the three most recent years, and it expects such reserves will continue to be the primary means of fulfilling its future commitments. However, where the Company's proved reserves are not sufficient to satisfy its delivery commitments, it can and may use spot market purchases of third party production to satisfy these commitments. A summary of these commitments at December 31, 2020 are set forth in the table below: (MMBtu per day) 2021 88,000 2022 58,000 2023 17,000 2024 — 2025 — Thereafter — Total 163,000 Contributions to 401(k) Plan |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingencies | CONTINGENCIES Litigation and Regulatory Proceedings The Company is involved in a number of litigation and regulatory proceedings that may result in material liabilities, including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different. The Company, along with a number of other oil and gas companies, has been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15 th Judicial District of the State of Louisiana in the 15 th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals. In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of the Company's legacy Louisiana properties, filed an action against the Company and a number of other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleged negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of the Company's Louisiana properties and sought unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. This matter was voluntarily dismissed without prejudice on December 8, 2020. In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by the Company, and its significant stockholders, including the Company, in the United States District Court for the Western District of Oklahoma. In January 2020, plaintiffs consolidated actions against the same defendants in the United States District Court for the District of Delaware. The consolidated and amended complaint alleges, among other things, that the Company breached its fiduciary duties and misappropriated information as a controlling shareholder of Mammoth Energy in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria and the Company's secondary offering of Mammoth Energy common stock in June 2018. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms. In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against us in the District Court of Grady County, Oklahoma. The suit alleged that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud. This matter is settled in principal and a voluntary dismissal without prejudice is anticipated. In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against the Company, David M. Wood, Keri Crowell and Quentin R. Hicks in the United States District Court for the Southern District of New York. The complaint alleges that the Company made materially false and misleading statements regarding the Company’s business and operations in violation of the federal securities laws and seeks unspecified damages, the payment of reasonable attorneys’ fees, expert fees and other costs, pre-judgment and post-judgment interest, and such other and further relief that may be deemed just and proper. In June 2020, Sam L. Carter, derivatively on behalf of the Company, filed an action against certain of our current and former executive officers and directors in the United States District Court for the District of Delaware. The complaint alleged that the defendants breached their fiduciary duties to the Company in connection with certain alleged materially false and misleading statements regarding our business and operations in violation of the federal securities laws. The complaint sought to recover unspecified damages from the defendants, the implementation of specified corporate governance reforms, reasonable attorneys’ and experts’ fees, costs and expenses, and such other relief as may be deemed just and proper. The complaint was voluntarily dismissed without prejudice on October 6, 2020. The Company filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and the Company. In March 2020, Stingray filed a counterclaim against the Company in the Superior Court of the State of Delaware. The counterclaim alleges that the Company has breached the Master Services Agreement. The counterclaim seeks actual damages, and Stingray filed claims in the Chapter 11 proceedings totaling $43.4 million related to breach of contract damages, attorneys' fees and interest. In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against the Company in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that the Company violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal to six of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers. In August 2020, Muskie filed an action against the Company in the Superior Court of the State of Delaware for breach of contract. The complaint alleges that the Company breached its obligation to purchase a certain amount of proppant sand each month or make designated shortfall payments under the Sand Supply Agreement, effective October 1, 2014, as amended (the “Sand Supply Agreement”), between Muskie and the Company, and seeks payment of unpaid shortfall payments, and Muskie filed a claim in the Chapter 11 proceedings for $3.4 million. SEC Investigation The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. On February 24, 2021, without admitting or denying any of findings contained in the order, Gulfport resolved the SEC investigation through an administrative order that Gulfport violated Sections 13(a), 13(b)(2)(A), 13(b)(2)(B) and 14(a) of the Exchange Act and Rules 12b-20, 13a-1, 14a-3 and 14a-9. Under the administrative order and pursuant to Section 21C of the Exchange Act, Gulfport agreed to cease and desist from committing or causing any violations and any future violations of Sections 13(a), 13(b)(2)(A), 13(b)(2)(B) and 14(a) of the Exchange Act and Rules 12b-20, 13a-1, 14a-3 and 14a-9 thereunder. Based on the company’s extensive cooperation and prompt remedial efforts, the SEC did not impose a monetary penalty. Business Operations The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. Environmental Contingencies The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property. The Company received several Finding of Violation ("FOVs") from the USEPA alleging violations of the Clean Air Act in Ohio. The Company entered into a settlement with the Department of Justice and USEPA agreeing to pay $1.7 million and invest in improvements at 17 well pads. The settlement was filed with the U.S. District Court for the Southern District of Ohio in January 2020 and was fully paid in October 2020. Other Matters Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. Concentration of Credit Risk Gulfport operates in the oil and natural gas industry principally in the states of Ohio and Oklahoma with sales to refineries, re-sellers such as marketers, and other end users. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term. The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation. At December 31, 2020, Gulfport held no cash in excess of insured limits in these banks. |
Supplemental Information on Oil
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2020 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) | SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) The Company owns a 24.5% interest in Grizzly. However, Grizzly did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below. The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States: Capitalized Costs Related to Oil and Gas Producing Activities 2020 2019 (In thousands) Proved properties $ 9,359,866 $ 8,909,069 Unproved properties 1,457,043 1,686,666 10,816,909 10,595,735 Accumulated depreciation, depletion, amortization and impairment (8,778,759) (7,191,957) Net capitalized costs $ 2,038,150 $ 3,403,778 Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2020 2019 2018 (In thousands) Acquisition $ 15,260 $ 37,598 $ 119,444 Development 276,622 594,673 714,269 Exploratory — 9,762 22,081 Total $ 291,882 $ 642,033 $ 855,794 Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $0.9 million, $3.4 million and $4.5 million during 2020, 2019, 2018, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures. In addition to capitalized interest, the Company capitalized internal costs totaling $25.0 million, $30.1 million and $37.7 million during 2020, 2019, and 2018, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties. Results of Operations for Producing Activities The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production. 2020 2019 2018 (In thousands) Revenues $ 801,251 $ 1,354,766 $ 1,675,180 Production costs (537,609) (620,412) (611,965) Depletion (229,702) (539,379) (476,517) Impairment (1,357,099) (2,039,770) — Income tax (expense) benefit (7,290) 7,563 68 Results of operations from producing activities $ (1,330,449) $ (1,837,232) $ 586,766 Depletion per Mcf of gas equivalent (Mcfe) $ 0.61 $ 1.08 $ 0.96 Oil and Natural Gas Reserves The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2020, 2019 and 2018 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2020, 2019 and 2018, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2020 reserve report are $39.54 per barrel of oil, $1.99 per MMbtu and $15.40 per barrel for NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2019 and 2018 for reserve report purposes are $55.85 per barrel, $2.58 per MMbtu and $21.25 per barrel for NGL and $65.56 per barrel, $3.10 per MMbtu and $32.02 per barrel for NGL, respectively. Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Natural Gas Equivalent (Bcfe) Proved Reserves December 31, 2017 19 4,825 76 5,395 Purchases of reserves — — — — Extensions and discoveries 5 622 10 711 Sales of reserves — (43) — (45) Revisions of prior reserve estimates — (827) 1 (821) Current production (3) (444) (6) (497) December 31, 2018 21 4,134 81 4,743 Purchases of reserves — — — — Extensions and discoveries 4 997 13 1,097 Sales of reserves (2) (63) — (77) Revisions of prior reserve estimates (2) (562) (27) (734) Current production (2) (458) (5) (502) December 31, 2019 18 4,048 62 4,528 Purchases of reserves — — — — Extensions and discoveries 1 216 3 240 Sales of reserves — (74) — (75) Revisions of prior reserve estimates (4) (1,564) (23) (1,725) Current production (2) (345) (4) (380) December 31, 2020 13 2,281 38 2,588 Proved developed reserves December 31, 2018 10 1,813 41 2,115 December 31, 2019 8 1,757 30 1,984 December 31, 2020 7 1,358 22 1,527 Proved undeveloped reserves December 31, 2018 11 2,321 40 2,628 December 31, 2019 10 2,291 32 2,544 December 31, 2020 7 923 16 1,061 Totals may not sum or recalculate due to rounding. In 2020, the Company experienced extensions of 239.8 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions, 150.6 Bcfe was attributable to the addition of 14 PUD locations in the Utica field, 87.8 Bcfe was attributable to the addition of eight PUD locations in the SCOOP field. The Company experienced total downward revisions of approximately 1.7 Tcfe in estimated proved reserves, of which 1,268.4 Bcfe was the result of commodity price changes. Commodity prices experienced volatility throughout 2020 and the 12-month average price for natural gas decreased from $2.58 per MMBtu for 2019 to $1.99 per MMBtu for 2020, the 12-month average price for NGL decreased from $21.25 per barrel for 2019 to $15.40 per barrel for 2020, and the 12-month average price for crude oil decreased from $55.85 per barrel for 2019 to $39.54 per barrel for 2020. An additional 720.3 Bcfe in downward revisions was a result of the exclusion of 48 PUD locations in the Utica field and 31 PUD locations in the SCOOP field, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment to capital discipline, funding future activities within cash flow and ongoing optimization of our development plan. Positive revisions of 263.8 Bcfe were experienced from a combination of operating and development cost improvements, well performance and working interest changes. In 2019, the Company experienced extensions of 1.1 Tcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions, 793.5 Bcfe was attributable to the addition of 72 PUD locations in the Utica field, 302.9 Bcfe was attributable to the addition of 37 PUD locations in the SCOOP field. The Company experienced total downward revisions of approximately 733.8 Bcfe in estimated proved reserves, of which 347.2 Bcfe was a result of the exclusion of nine PUD locations in the Utica field and 22 PUD locations in the SCOOP field, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment capital discipline and funding future activities within cash flow. An additional 296.4 Bcfe in downward revisions was the result of commodity price changes. Commodity prices experienced volatility throughout 2019 and the 12-month average price for natural gas decreased from $3.10 per MMBtu for 2018 to $2.58 per MMBtu for 2019, the 12- month average price for NGL decreased from $32.02 per barrel for 2018 to $21.25 per barrel for 2019, and the 12-month average price for crude oil decreased from $65.56 per barrel for 2018 to $55.85 per barrel for 2019. The Company also experienced downward revisions of 90.2 Bcfe from a combination of working interest changes, optimization of well design in the current commodity price environment and well performance. In 2018, the Company experienced extensions and discoveries of 711.2 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions and discoveries, 556.3 Bcfe was attributable to the addition of 75 PUD locations in the Utica field, 90.1 Bcfe was attributable to the addition of 11 PUD locations in the SCOOP field and 3.0 Bcfe was attributable to the addition of 13 PUD locations in the Southern Louisiana fields as a result of the Company's current development plan that refocused some activity within existing fields. This change reflects the Company's ongoing efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations. In 2018, the Company experienced downward revisions of 1.0 Tcfe in estimated proved reserves with the exclusion of 127 PUD locations in the Company's Utica field and 12 PUD locations in the Company's SCOOP field, which was primarily the result of changes in the Company's development schedule moving development in excess of five years from initial booking. The development plan change, as approved by the Company's senior management and board of directors, is a result of continued focus on free cash flow generation. This downward revision was partially offset by upward revisions of 82.4 Bcfe in estimated proved reserves in 2018 due to changes in wellbore lateral length, 67.6 Bcfe due to changes in ownership interest, 27.9 Bcfe due to an increase in pricing and 8.3 Bcfe due to changes in well performance. In addition, the Company sold approximately 44.9 Bcfe of proved undeveloped oil and natural gas reserves associated with various non-operated interests, the majority of which were in the Company's Utica field. Discounted Future Net Cash Flows The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2020, 2019 and 2018 using an unweighted average first-of-the-month price for the period January through December 31, 2020, 2019 and 2018. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2020 2019 2018 (In millions) Future cash flows $ 4,079 $ 10,451 $ 14,483 Future development and abandonment costs (652) (2,058) (2,438) Future production costs (2,325) (4,513) (5,068) Future production taxes (137) (333) (456) Future income taxes — — (943) Future net cash flows 965 3,547 5,578 10% discount to reflect timing of cash flows (425) (1,844) (2,596) Standardized measure of discounted future net cash flows $ 540 $ 1,703 $ 2,982 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2020 2019 2018 (In millions) Sales and transfers of oil and gas produced, net of production costs $ (264) $ (734) $ (1,063) Net changes in prices, production costs, and development costs (954) (1,372) 591 Acquisition of oil and gas reserves in place — — — Extensions and discoveries 38 388 519 Previously estimated development costs incurred during the period 215 406 402 Revisions of previous quantity estimates, less related production costs (255) (321) (357) Sales of oil and gas reserves in place (6) (49) (26) Accretion of discount 170 298 264 Net changes in income taxes — 425 (185) Change in production rates and other (109) (319) 194 Total change in standardized measure of discounted future net cash flows $ (1,165) $ (1,278) $ 339 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2020 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following table summarizes quarterly financial data for the years ended December 31, 2020 and 2019: 2020 First Second Third Fourth (In thousands) Revenues $ 299,338 $ 186,301 $ 136,176 $ 244,727 (Loss) income from operations (480,087) (555,750) (346,400) 19,632 Income tax expense 7,290 — — — Net loss (517,538) (561,068) (380,963) (165,564) Loss per share: Basic $ (3.24) $ (3.51) $ (2.37) $ (1.03) Diluted $ (3.24) $ (3.51) $ (2.37) $ (1.03) 2019 First Second Third Fourth (In thousands) Revenues $ 372,462 $ 512,451 $ 341,745 $ 336,468 (Loss) income from operations 93,011 218,456 (570,955) (1,444,205) Income tax (benefit) expense — (179,331) (144,047) 315,815 Net income (loss) 62,242 234,956 (484,802) (1,814,754) Income (loss) per share: Basic $ 0.38 $ 1.47 $ (3.04) $ (11.36) Diluted $ 0.38 $ 1.47 $ (3.04) $ (11.36) |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2020 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS Subsequent to December 31, 2020 and as of March 1, 2021, the Company entered into the following natural gas, oil, and NGL derivative contracts as it works toward fulfilling minimum hedging requirements as provided for in the RSA: Period Type of Derivative Instrument Index Daily Volume (1) Weighted July 2021 - December 2021 Swaps NYMEX WTI 2,250 $53.07 July 2021 - December 2021 Swaps Mont Belvieu C3 3,100 $27.80 January 2022 - June 2022 Swaps Mont Belvieu C3 1,000 $27.30 April 2021 - May 2021 Basis Swaps Tetco M2 36,443 $(0.61) February 2021 - October 2021 Basis Swaps Rex Zone 3 94,505 $(0.22) July 2021 - December 2021 Costless Collars NYMEX Henry Hub 210,000 $2.67/$3.15 January 2022 - March 2022 Costless Collars NYMEX Henry Hub 340,000 $2.82/$3.40 (1) Volume units for gas instruments are presented as MMBtu/day while oil and NGL is presented in Bbls/day. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the Company and its wholly-owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC, Puma Resources, Inc., Gulfport Appalachia LLC, Gulfport Midstream Holdings, LLC, Gulfport MidCon, LLC and Mule Sky LLC. All intercompany balances and transactions are eliminated in consolidation. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the consolidated financial statements. |
Accounts Receivable | Accounts ReceivableThe Company sells oil and natural gas to various purchasers and participates in drilling, completion and operation of oil and natural gas wells with joint interest owners on properties the Company operates. The related receivables are classified as accounts receivable—oil and natural gas sales and accounts receivable—joint interest and other, respectively. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. |
Oil and Gas Properties | Oil and Gas Properties The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Additionally, interest is capitalized on the cost of unproved oil and natural gas properties that are excluded from amortization for which exploration and development activities are in process or expected within the next 12 months. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue (only to the extent that the derivative instruments are treated as cash flow hedges for accounting purposes), and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of unproved properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can result in a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. As a result of the decline in commodity prices throughout 2020, the Company recognized ceiling test impairments of $1.4 billion for the year ended December 31, 2020. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties, are depleted by an equivalent units-of-production method, converting barrels to gas at the ratio of one barrel of oil to six Mcf of gas. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proved oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled approximately $1.5 billion and $1.7 billion at December 31, 2020 and December 31, 2019, respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. The Company accounts for its abandonment and restoration liabilities by recording a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. |
Other Property and Equipment | Other Property and Equipment Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years. |
Foreign Currency | Foreign CurrencyThe U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented and equity contributions are translated at the current exchange rate in effect at the date of the contribution. In addition, the Company has an equity investment in a U.S. company that has a subsidiary that is a Canadian entity whose functional currency is the Canadian dollar. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ (deficit) equity. |
Net (Loss) Income per Common Share | Net (Loss) Income per Common ShareBasic net (loss) income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net (loss) income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. |
Income Taxes | Income Taxes Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 2003 – 2019 U.S. federal and 2009 - 2019 state income tax returns remain open to examination by tax authorities, due to net operating |
Revenue Recognition | Revenue Recognition The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. Sales of natural gas, oil and condensate and NGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to (i) whether the purchaser can direct the use of the product, (ii) the transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title. Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as midstream, gathering and processing expense in the accompanying consolidated statements of operations. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. The recognition of gains or losses on derivative instruments is outside the scope of ASC 606, Revenue from Contracts with Customers and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales. The Company has elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer, such as sales tax, use tax, value-added tax and similar taxes. |
Investments - Equity Method | Investments—Equity Method Investments in entities in which the Company owns an equity interest greater than 20% and less than 50% and/or investments in which it has significant influence are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the consolidated statements of operations. |
Accounting for Stock-Based Compensation | Accounting for Stock-based Compensation Share-based payments to employees, including grants of restricted stock, are recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for restricted shares range between one |
Derivative Instruments | Derivative Instruments The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and NGL production. All derivative instruments are recognized as assets or liabilities in the consolidated balance sheets, measured at fair value. The Company does not apply hedge accounting to derivative instruments. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets, the fair value determination of acquired assets and liabilities and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties. |
Reclassifications | Reclassifications In the fourth quarter of 2020, the Company updated the presentation of certain costs on its consolidated statements of operations to better align its cost reporting with industry peers. In particular, the Company created a new expense line item titled “Taxes other than income” in its consolidated statement of operations. This new line item includes production taxes, property taxes and certain other non-income tax related costs incurred. Prior period amounts have been reclassified to align to this new approach. The reclassifications have no impact on previously reported total assets, liabilities, net (loss) income or total operating cash flows. |
Impact on Previously Reported Results | Impact on Previously Reported ResultsDuring the third quarter of 2020, the Company identified that certain transportation activities during the years ended December 31, 2019 and 2018 were misclassified between "natural gas sales" and "midstream gathering and processing expenses" on its consolidated statements of operations. The Company assessed the materiality of this presentation on prior periods’ consolidated financial statements in accordance with the SEC Staff Accounting Bulletin No. 99, “Materiality”, codified in Accounting Standards Codification Topic 250, “Accounting Changes and Error Corrections". Based on this assessment, the Company concluded that the correction is not material to any previously issued financial statements. The correction had no impact on its consolidated balance sheets, consolidated statements of comprehensive income, consolidated statements of stockholders' equity or consolidated statements of cash flows. Additionally, the error had no impact on net loss or net loss per share. The Company will conform presentation of previously reported consolidated statements of operations in future filings. |
Recent Adopted Accounting Pronouncements | Recent Adopted Accounting Pronouncements On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments , which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of the reported amount. The Company adopted the new standard using the prospective transition method, and it did not have a material impact on the Company's consolidated financial statements and related disclosures. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Schedule of cumulative translation adjustments | The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive loss, exclusive of taxes. (In thousands) December 31, 2017 (39,190) December 31, 2018 (54,677) December 31, 2019 (45,484) December 31, 2020 (41,651) |
Schedule of Cash Flow, Supplemental Disclosures | Supplemental cash flow and non-cash information Year Ended December 31, 2020 2019 2018 Supplemental disclosure of cash flow information: (In thousands) Cash paid for reorganization items, net $ 24,553 $ — $ — Interest payments $ 84,823 $ 142,664 $ 132,995 Income tax receipts $ — $ (1,794) $ — Supplemental disclosure of non-cash transactions: Capitalized stock-based compensation $ 2,860 $ 5,766 $ 4,533 Asset retirement obligation capitalized $ 2,358 $ 6,883 $ 1,452 Asset retirement obligation removed due to divestiture $ (2,213) $ (30,146) $ — Interest capitalized $ 907 $ 3,372 $ 4,470 Pre-petition revolver principal transfer to DIP credit facility $ 157,500 $ — $ — Fair value of contingent consideration asset on date of divestiture $ 23,090 $ (1,137) $ — Foreign currency translation gain (loss) on equity method investments $ 3,833 $ 9,193 $ (15,487) |
Schedule of error corrections and prior period adjustments | The following tables present the effect of the correction on all affected line items of our previously issued consolidated financial statements of operations for the years ended December 31, 2019 and 2018. Year Ended December 31, 2019 As Reported Adjustments As Revised (In thousands) Natural gas sales $ 918,263 $ 217,118 $ 1,135,381 Total Revenues $ 1,346,008 $ 217,118 $ 1,563,126 Midstream gathering and processing expenses $ 291,725 $ 217,118 $ 508,843 Total Operating Expenses $ 3,049,701 $ 217,118 $ 3,266,819 Year Ended December 31, 2018 As Reported Adjustments As Revised (In thousands) Natural gas sales $ 1,121,815 $ 196,657 $ 1,318,472 Total Revenues $ 1,355,044 $ 196,657 $ 1,551,701 Midstream gathering and processing expenses $ 290,188 $ 196,657 $ 486,845 Total Operating Expenses $ 956,085 $ 196,657 $ 1,152,742 |
Chapter 11 Proceedings (Tables)
Chapter 11 Proceedings (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Reorganizations [Abstract] | |
Schedule of liabilities subject to compromise | The following table summarizes the components of liabilities subject to compromise included on the Company's audited consolidated balance sheet as of December 31, 2020: December 31, 2020 (in thousands) Debt subject to compromise $ 2,005,219 Accounts payable and accrued liabilities 164,939 Asset retirement obligations 63,566 Accrued interest on debt subject to compromise 55,634 Other liabilities 4,122 Liabilities subject to compromise $ 2,293,480 |
Schedule of reorganization items | The following table summarizes the components in reorganization items, net included in the Company's audited consolidated statements of operations for the year ended December 31, 2020: Year Ended December 31, 2020 (in thousands) Adjustment to allowed claims $ 104,943 Legal and professional fees 24,905 Write off of unamortized issuance costs on debt subject to compromise 21,956 DIP credit facility financing fees 2,988 Gain on settlement of pre-petition accounts payable (2,433) Reorganization items, net $ 152,359 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
Schedule of property and equipment | The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2020 and 2019 are as follows: December 31, 2020 2019 (In thousands) Oil and natural gas properties $ 10,816,909 $ 10,595,735 Other depreciable property and equipment 85,530 91,198 Land 3,008 5,521 Total property and equipment 10,905,447 10,692,454 Accumulated depletion, depreciation, amortization and impairment (8,819,178) (7,228,660) Property and equipment, net $ 2,086,269 $ 3,463,794 |
Schedule of oil and gas properties not subject to amortization | The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2020: Costs Incurred in 2020 2019 2018 Prior to 2018 Total (In thousands) Acquisition costs $ 18,485 $ 8,067 $ 98,876 $ 1,330,895 $ 1,456,323 Exploration costs — — — — — Development costs — — — — — Capitalized interest — 121 172 427 720 Total oil and natural gas properties not subject to amortization $ 18,485 $ 8,188 $ 99,048 $ 1,331,322 $ 1,457,043 The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2020: December 31, 2020 (In thousands) Utica $ 793,441 SCOOP 662,614 Other 988 $ 1,457,043 |
Schedule of asset retirement obligation | A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2020 and 2019 is as follows: December 31, 2020 2019 (In thousands) Asset retirement obligation, beginning of period $ 60,355 $ 79,952 Liabilities incurred 2,358 5,935 Liabilities settled — (273) Liabilities removed due to divestitures (2,213) (30,146) Accretion expense 3,066 3,939 Revisions in estimated cash flows — 948 Total asset retirement obligation as of end of period 63,566 60,355 Less: amounts reclassified to liabilities subject to compromise (63,566) — Total asset retirement obligation reflected as non-current liabilities $ — $ 60,355 |
Equity Investments (Tables)
Equity Investments (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of investments accounted for by the equity method | Investments accounted for by the equity method consist of the following as of December 31, 2020 and 2019: Carrying Value Loss (income) from equity method investments Approximate Ownership % December 31, For the Year Ended December 31, 2020 2019 2020 2019 2018 (In thousands) Investment in Grizzly Oil Sands ULC 24.5 % $ 24,816 $ 21,000 $ 377 $ 32,710 $ 510 Investment in Mammoth Energy Services, Inc. 21.5 % — 11,005 10,646 179,524 (49,969) Investment in Tatex Thailand II, LLC 23.5 % — — — (2,086) (241) Other equity investments (1) — % — 39 32 — (204) $ 24,816 $ 32,044 $ 11,055 $ 210,148 $ (49,904) _____________________ (1) Consists of sold/dissolved investments, including Windsor Midstream, LLC, which was dissolved as of December 31, 2020. Additionally, this includes the Company's investment in Strike Force that was sold in 2018, from which the Company recognized a gain of $96.4 million net of transaction fees, which is included in gain on sale of equity method investments in the accompanying consolidated statement of operations for the year ended December 31, 2018. |
Schedule of Equity Investments - Balance Sheet | Summarized balance sheet information: December 31, 2020 2019 (In thousands) Current assets $ 483,303 $ 421,326 Noncurrent assets $ 1,092,495 $ 1,260,075 Current liabilities $ 132,978 $ 132,569 Noncurrent liabilities $ 148,240 $ 163,241 |
Schedule of Equity Investments - Income Statement | Summarized results of operations: December 31, 2020 2019 2018 (In thousands) Gross revenue $ 313,076 $ 625,012 $ 1,729,778 Net (loss) income $ (106,072) $ (76,523) $ 253,451 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of long-term debt | Long-term debt consisted of the following items as of December 31: 2020 2019 (In thousands) DIP credit facility $ 157,500 $ — Pre-petition revolving credit facility 292,910 120,000 6.625% senior unsecured notes due 2023 324,583 329,467 6.000% senior unsecured notes due 2024 579,568 603,428 6.375% senior unsecured notes due 2025 507,870 529,525 6.375% senior unsecured notes due 2026 374,617 397,529 Building loan 21,914 22,453 Net unamortized debt issuance costs — (23,751) Total Debt, net 2,258,962 1,978,651 Less: current maturities of long term debt (253,743) (631) Less: amounts reclassified to liabilities subject to compromise (2,005,219) — Total Debt reflected as long term $ — $ 1,978,020 |
Schedule of interest expense | The following schedule shows the components of interest expense for the year ended December 31: 2020 2019 2018 (In thousands) Cash paid for interest $ 84,823 $ 142,664 $ 132,995 Change in accrued interest 30,600 (3,834) 7,266 Capitalized interest (907) (3,372) (4,470) Amortization of loan costs 5,563 6,328 6,121 Total interest expense $ 120,079 $ 141,786 $ 141,912 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement, Noncash Expense [Abstract] | |
Schedule of restricted stock award and unit activity | The following table summarizes restricted stock unit and performance vesting restricted stock unit activity for the twelve months ended December 31, 2020, 2019 and 2018: Number of Weighted Number of Weighted Unvested shares as of January 1, 2018 976,027 $ 18.71 — $ — Granted 1,579,911 9.90 — — Vested (626,671) 18.05 — — Forfeited (393,456) 12.23 — — Unvested shares as of December 31, 2018 1,535,811 $ 11.57 — $ — Granted 4,011,073 $ 3.74 2,009,144 2.85 Vested (676,108) 12.89 — — Forfeited (772,458) 6.05 (225,484) 1.98 Unvested shares as of December 31, 2019 4,098,318 $ 4.73 1,783,660 $ 2.96 Granted 3,069,521 0.85 — — Vested (1,294,285) 5.73 — — Forfeited (4,171,041) 1.68 (943,065) 1.98 Unvested shares as of December 31, 2020 1,702,513 $ 4.74 840,595 $ 4.07 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Schedule of operating lease liability | Future amounts due under operating lease liabilities as of December 31, 2020 were as follows: (In thousands) 2021 $ 129 2022 115 2023 90 2024 30 Total lease payments 364 Less: Imputed interest (22) Less: amounts reclassified to liabilities subject to compromise (342) Total lease liabilities $ — |
Schedule of lease cost | Lease costs incurred for the years ended December 31, 2020 and 2019 consisted of the following: For the Year Ended December 31, 2020 2019 (In thousands) Operating lease cost $ 9,658 $ 24,960 Operating lease cost - related party — 22,440 Variable lease cost 586 2,172 Variable lease cost - related party — 66,924 Short-term lease cost 9,361 834 Total lease cost (1) $ 19,605 $ 117,330 _____________________ (1) The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations. Supplemental cash flow information for the years ended December 31, 2020 and 2019 related to leases was as follows: For the Year Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities (In thousands) Operating cash flows from operating leases 140 182 Investing cash flow from operating leases 10,272 24,263 Investing cash flow from operating leases - related party 6,800 84,750 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Schedule of income tax provision | The income tax provision consists of the following: 2020 2019 2018 (In thousands) Current: State $ — $ — $ (1,530) Federal (273) (7) 253 Deferred: State 7,563 (7,556) 1,530 Federal — — (322) Total income tax expense (benefit) provision $ 7,290 $ (7,563) $ (69) |
Schedule of reconciliation to the statutory federal income tax | A reconciliation of the statutory federal income tax amount to the recorded expense follows: 2020 2019 2018 (In thousands) (Loss) income before federal income taxes $ (1,617,843) $ (2,009,921) $ 430,491 Expected income tax at statutory rate (339,747) (422,083) 90,403 State income taxes (14,696) (28,316) (511) Other differences 10,800 3,372 1,078 Change in valuation allowance due to current year activity 350,933 439,464 (91,039) Income tax expense (benefit) recorded $ 7,290 $ (7,563) $ (69) |
Schedule of deferred tax assets and liabilities | The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2020, 2019 and 2018 are estimated as follows: 2020 2019 2018 (In thousands) Deferred tax assets: Net operating loss carryforward $ 392,318 $ 269,851 $ 164,363 Oil and gas property basis difference 463,705 289,850 3,595 Investment in pass through entities 61,078 58,951 8,620 Stock-based compensation expense 1,223 1,440 616 Business energy investment tax credit 370 370 369 Charitable contributions carryover 318 297 269 Change in fair value of derivative instruments 7,656 11,219 2,761 Foreign tax credit carryforwards 523 943 2,009 Accrued liabilities 868 669 834 ARO liability 13,414 12,744 16,923 Non-oil and gas property basis difference — — 104 Lease liability 72 12,128 — Reorganization items 25,714 — — State net operating loss carryover 22,191 13,258 11,526 Interest expense carryforward — 23,818 — Total deferred tax assets 989,450 695,538 211,989 Valuation allowance for deferred tax assets (985,528) (647,575) (211,987) Deferred tax assets, net of valuation allowance 3,922 47,963 2 Deferred tax liabilities: Non-oil and gas property basis difference 575 1,859 — Change in fair value of derivative instruments 3,272 26,410 2 Right of use asset 72 12,128 — Other 3 3 — Total deferred tax liabilities 3,922 40,400 2 Net deferred tax asset $ — $ 7,563 $ — |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |
Schedule of earnings per share | Reconciliations of the components of basic and diluted net income per common share are presented in the tables below: For the Year Ended December 31, 2020 2019 2018 (In thousands, except share data) Net (loss) income $ (1,625,133) $ (2,002,358) $ 430,560 Basic Shares 160,231,335 160,341,125 174,675,840 Basic EPS $ (10.14) $ (12.49) $ 2.46 Effect of dilutive securities: Stock options and awards — — 722,866 Dilutive Shares 160,231,335 160,341,125 175,398,706 Dilutive EPS $ (10.14) $ (12.49) $ 2.45 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of open fixed price swap positions | Below is a summary of the Company's open fixed price swap positions as of December 31, 2020. Index Daily Volume (MMBtu/day) Weighted 2021 NYMEX Henry Hub 410,000 $ 2.75 The Company entered into costless collars based off the NYMEX Henry Hub natural gas index. Each two-way price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty. Index Daily Volume (MMBtu/day) Weighted Average Floor/Ceiling Price 2021 NYMEX Henry Hub 250,000 $2.46/$2.81 2022 NYMEX Henry Hub 20,000 $2.80/$3.40 In the third quarter of 2019, the Company sold call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. Index Daily Volume (MMBtu/day) Weighted 2022 NYMEX Henry Hub 153,000 $ 2.90 2023 NYMEX Henry Hub 628,000 $ 2.90 |
Schedule of natural gas basis swap positions | As of December 31, 2020, the Company had the following natural gas basis swap positions open: Gulfport Pays Gulfport Receives Daily Volume (MMBtu/day) Weighted Average Fixed Spread 2021 Rex Zone 3 NYMEX Plus Fixed Spread 35,000 $ (0.21) 2021 Tetco M2 NYMEX Plus Fixed Spread 60,000 $ (0.67) Subsequent to December 31, 2020 and as of March 1, 2021, the Company entered into the following natural gas, oil, and NGL derivative contracts as it works toward fulfilling minimum hedging requirements as provided for in the RSA: Period Type of Derivative Instrument Index Daily Volume (1) Weighted July 2021 - December 2021 Swaps NYMEX WTI 2,250 $53.07 July 2021 - December 2021 Swaps Mont Belvieu C3 3,100 $27.80 January 2022 - June 2022 Swaps Mont Belvieu C3 1,000 $27.30 April 2021 - May 2021 Basis Swaps Tetco M2 36,443 $(0.61) February 2021 - October 2021 Basis Swaps Rex Zone 3 94,505 $(0.22) July 2021 - December 2021 Costless Collars NYMEX Henry Hub 210,000 $2.67/$3.15 January 2022 - March 2022 Costless Collars NYMEX Henry Hub 340,000 $2.82/$3.40 (1) Volume units for gas instruments are presented as MMBtu/day while oil and NGL is presented in Bbls/day. |
Schedule of purchase and sale agreement for sale of the company's non-core assets | The purchase and sale agreement for the sale of the Company's non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles the Company to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture. See below for threshold and potential payment amounts. Period Threshold (1) Payment to be received (2) January 2021 - June 2021 Greater than or equal to $60.65 $ 150,000 Between $52.62 - $60.65 Calculated Value (3) Less than or equal to $52.62 $ — _____________________ (1) Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media. (2) Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month. (3) If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03. |
Schedule of derivative instruments on a gross basis | The following table presents the fair value of the Company's derivative instruments on a gross basis at December 31, 2020 and 2019: December 31, 2020 2019 (In thousands) Commodity derivative instruments $ 27,146 $ 125,383 Contingent consideration arrangement — 818 Total short-term derivative instruments – asset $ 27,146 $ 126,201 Commodity derivative instruments 322 — Contingent consideration arrangement — 563 Total long-term derivative instruments – asset $ 322 $ 563 Total short-term derivative instruments – liability $ 11,641 $ 303 Total long-term derivative instruments – liability $ 36,604 $ 53,135 |
Schedule of net gain (loss) on derivatives | The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2020, 2019, and 2018. Net gain (loss) on derivative instruments For the Year Ended December 31, 2020 2019 2018 (In thousands) Natural gas derivatives $ 23,765 $ 194,450 $ (116,130) Oil derivatives 43,510 7,035 (13,084) NGL derivatives (603) 6,632 5,735 Contingent consideration arrangement (1,381) 243 — Total $ 65,291 $ 208,360 $ (123,479) |
Schedule of recognized derivative assets | The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value. As of December 31, 2020 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 27,468 $ (25,730) $ 1,738 Derivative liabilities $ (48,245) $ 25,730 $ (22,515) As of December 31, 2019 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 126,764 $ (53,438) $ 73,326 Derivative liabilities $ (53,438) $ 53,438 $ — |
Schedule of recognized derivative liabilities | The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value. As of December 31, 2020 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 27,468 $ (25,730) $ 1,738 Derivative liabilities $ (48,245) $ 25,730 $ (22,515) As of December 31, 2019 Derivative instruments, gross Netting adjustments Derivative instruments, net (In thousands) Derivative assets $ 126,764 $ (53,438) $ 73,326 Derivative liabilities $ (53,438) $ 53,438 $ — |
Restructuring And Liability M_2
Restructuring And Liability Management (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Restructuring and Related Activities [Abstract] | |
Restructuring and Related Costs | For the Year Ended December 31, 2020 2019 (in thousands) Reduction in workforce $ 1,460 $ 4,611 Liability management 29,387 — Total restructuring and liability management expenses $ 30,847 $ 4,611 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value measurements | The following tables summarize the Company’s financial assets and liabilities by valuation level as of December 31, 2020 and 2019: December 31, 2020 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 27,468 $ — Contingent consideration arrangement $ — $ — $ 6,200 Total assets $ — $ 27,468 $ 6,200 Liabilities: Derivative Instruments $ — $ 48,245 $ — December 31, 2019 Level 1 Level 2 Level 3 (In thousands) Assets: Derivative Instruments $ — $ 126,764 $ — Liabilities: Derivative Instruments $ — $ 53,438 $ — |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of future service commitments | A summary of these commitments at December 31, 2020 are set forth in the table below: (In thousands) 2021 $ 370,343 2022 380,979 2023 379,171 2024 358,990 2025 272,123 Thereafter 2,013,119 Total $ 3,774,725 |
Schedule of long-term purchase commitments | A summary of these commitments at December 31, 2020 are set forth in the table below: (MMBtu per day) 2021 88,000 2022 58,000 2023 17,000 2024 — 2025 — Thereafter — Total 163,000 |
Supplemental Information on O_2
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Extractive Industries [Abstract] | |
Schedule of capitalized costs related to oil and gas producing activities | Capitalized Costs Related to Oil and Gas Producing Activities 2020 2019 (In thousands) Proved properties $ 9,359,866 $ 8,909,069 Unproved properties 1,457,043 1,686,666 10,816,909 10,595,735 Accumulated depreciation, depletion, amortization and impairment (8,778,759) (7,191,957) Net capitalized costs $ 2,038,150 $ 3,403,778 |
Schedule of cost incurred in oil and gas property acquisition and development activities | Costs Incurred in Oil and Gas Property Acquisition and Development Activities 2020 2019 2018 (In thousands) Acquisition $ 15,260 $ 37,598 $ 119,444 Development 276,622 594,673 714,269 Exploratory — 9,762 22,081 Total $ 291,882 $ 642,033 $ 855,794 |
Schedule of results of operations for oil and gas production activities | The results of operations exclude general office overhead and interest expense attributable to oil and gas production. 2020 2019 2018 (In thousands) Revenues $ 801,251 $ 1,354,766 $ 1,675,180 Production costs (537,609) (620,412) (611,965) Depletion (229,702) (539,379) (476,517) Impairment (1,357,099) (2,039,770) — Income tax (expense) benefit (7,290) 7,563 68 Results of operations from producing activities $ (1,330,449) $ (1,837,232) $ 586,766 Depletion per Mcf of gas equivalent (Mcfe) $ 0.61 $ 1.08 $ 0.96 |
Schedule of oil and gas reserves | These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Natural Gas Equivalent (Bcfe) Proved Reserves December 31, 2017 19 4,825 76 5,395 Purchases of reserves — — — — Extensions and discoveries 5 622 10 711 Sales of reserves — (43) — (45) Revisions of prior reserve estimates — (827) 1 (821) Current production (3) (444) (6) (497) December 31, 2018 21 4,134 81 4,743 Purchases of reserves — — — — Extensions and discoveries 4 997 13 1,097 Sales of reserves (2) (63) — (77) Revisions of prior reserve estimates (2) (562) (27) (734) Current production (2) (458) (5) (502) December 31, 2019 18 4,048 62 4,528 Purchases of reserves — — — — Extensions and discoveries 1 216 3 240 Sales of reserves — (74) — (75) Revisions of prior reserve estimates (4) (1,564) (23) (1,725) Current production (2) (345) (4) (380) December 31, 2020 13 2,281 38 2,588 Proved developed reserves December 31, 2018 10 1,813 41 2,115 December 31, 2019 8 1,757 30 1,984 December 31, 2020 7 1,358 22 1,527 Proved undeveloped reserves December 31, 2018 11 2,321 40 2,628 December 31, 2019 10 2,291 32 2,544 December 31, 2020 7 923 16 1,061 Totals may not sum or recalculate due to rounding. |
Schedule of standardized measure of discounted future net cash flows relating to proved oil and gas reserves | Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2020 2019 2018 (In millions) Future cash flows $ 4,079 $ 10,451 $ 14,483 Future development and abandonment costs (652) (2,058) (2,438) Future production costs (2,325) (4,513) (5,068) Future production taxes (137) (333) (456) Future income taxes — — (943) Future net cash flows 965 3,547 5,578 10% discount to reflect timing of cash flows (425) (1,844) (2,596) Standardized measure of discounted future net cash flows $ 540 $ 1,703 $ 2,982 |
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves | Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Year ended December 31, 2020 2019 2018 (In millions) Sales and transfers of oil and gas produced, net of production costs $ (264) $ (734) $ (1,063) Net changes in prices, production costs, and development costs (954) (1,372) 591 Acquisition of oil and gas reserves in place — — — Extensions and discoveries 38 388 519 Previously estimated development costs incurred during the period 215 406 402 Revisions of previous quantity estimates, less related production costs (255) (321) (357) Sales of oil and gas reserves in place (6) (49) (26) Accretion of discount 170 298 264 Net changes in income taxes — 425 (185) Change in production rates and other (109) (319) 194 Total change in standardized measure of discounted future net cash flows $ (1,165) $ (1,278) $ 339 |
Selected Quarterly Financial _2
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of selected quarterly financial data | The following table summarizes quarterly financial data for the years ended December 31, 2020 and 2019: 2020 First Second Third Fourth (In thousands) Revenues $ 299,338 $ 186,301 $ 136,176 $ 244,727 (Loss) income from operations (480,087) (555,750) (346,400) 19,632 Income tax expense 7,290 — — — Net loss (517,538) (561,068) (380,963) (165,564) Loss per share: Basic $ (3.24) $ (3.51) $ (2.37) $ (1.03) Diluted $ (3.24) $ (3.51) $ (2.37) $ (1.03) 2019 First Second Third Fourth (In thousands) Revenues $ 372,462 $ 512,451 $ 341,745 $ 336,468 (Loss) income from operations 93,011 218,456 (570,955) (1,444,205) Income tax (benefit) expense — (179,331) (144,047) 315,815 Net income (loss) 62,242 234,956 (484,802) (1,814,754) Income (loss) per share: Basic $ 0.38 $ 1.47 $ (3.04) $ (11.36) Diluted $ 0.38 $ 1.47 $ (3.04) $ (11.36) |
Subsequent Events (Tables)
Subsequent Events (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Subsequent Events [Abstract] | |
Schedule of natural gas basis swap positions | As of December 31, 2020, the Company had the following natural gas basis swap positions open: Gulfport Pays Gulfport Receives Daily Volume (MMBtu/day) Weighted Average Fixed Spread 2021 Rex Zone 3 NYMEX Plus Fixed Spread 35,000 $ (0.21) 2021 Tetco M2 NYMEX Plus Fixed Spread 60,000 $ (0.67) Subsequent to December 31, 2020 and as of March 1, 2021, the Company entered into the following natural gas, oil, and NGL derivative contracts as it works toward fulfilling minimum hedging requirements as provided for in the RSA: Period Type of Derivative Instrument Index Daily Volume (1) Weighted July 2021 - December 2021 Swaps NYMEX WTI 2,250 $53.07 July 2021 - December 2021 Swaps Mont Belvieu C3 3,100 $27.80 January 2022 - June 2022 Swaps Mont Belvieu C3 1,000 $27.30 April 2021 - May 2021 Basis Swaps Tetco M2 36,443 $(0.61) February 2021 - October 2021 Basis Swaps Rex Zone 3 94,505 $(0.22) July 2021 - December 2021 Costless Collars NYMEX Henry Hub 210,000 $2.67/$3.15 January 2022 - March 2022 Costless Collars NYMEX Henry Hub 340,000 $2.82/$3.40 (1) Volume units for gas instruments are presented as MMBtu/day while oil and NGL is presented in Bbls/day. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2020USD ($)bbl | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||
Decrease in capital spending, percentage | 50.00% | ||
Accounts receivable, collection period | 30 days | ||
Allowance for doubtful accounts | $ 0 | $ 0 | |
Impairment of oil and natural gas properties | $ 1,357,099,000 | 2,039,770,000 | $ 0 |
Conversion ratio, gas to barrels of oil (in Mcf of gas) | bbl | 6 | ||
Capitalized costs of oil and natural gas properties excluded from amortization | $ 1,457,043,000 | 1,686,666,000 | |
Unrecognized tax benefits that would impact effective tax rate | 0 | ||
Equity method investment recognized impairment charges | 0 | ||
Unsecured Debt | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Debt instrument, repurchase amount | 73,300,000 | ||
Investment in Mammoth Energy Services, Inc. | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Equity method investment recognized impairment charges | 0 | 160,800,000 | |
Investment in Grizzly Oil Sands ULC | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Equity method investment recognized impairment charges | $ 0 | $ 32,400,000 | $ 0 |
Minimum | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Useful life | 3 years | ||
Minimum | Restricted stock | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Vesting period | 1 year | ||
Maximum | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Useful life | 30 years | ||
Maximum | Restricted stock | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Vesting period | 3 years |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Foreign Currency (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||||
Cumulative translation adjustments included in AOCI | $ (41,651) | $ (45,484) | $ (54,677) | $ (39,190) |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Supplemental Cash and Non Cash Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Supplemental disclosure of cash flow information: | |||
Cash paid for reorganization items, net | $ 24,553 | $ 0 | $ 0 |
Interest payments | 84,823 | 142,664 | 132,995 |
Income tax receipts | 0 | (1,794) | 0 |
Supplemental disclosure of non-cash transactions: | |||
Capitalized stock-based compensation | 2,860 | 5,766 | 4,533 |
Asset retirement obligation capitalized | 2,358 | 6,883 | 1,452 |
Asset retirement obligation removed due to divestiture | (2,213) | (30,146) | 0 |
Interest capitalized | 907 | 3,372 | 4,470 |
Pre-petition revolver principal transfer to DIP credit facility | 157,500 | 0 | 0 |
Fair value of contingent consideration asset on date of divestiture | 23,090 | (1,137) | 0 |
Foreign currency translation gain (loss) on equity method investments | $ 3,833 | $ 9,193 | $ (15,487) |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Schedule of Error Corrections and Prior Period Adjustments (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Total Revenues | $ 244,727 | $ 136,176 | $ 186,301 | $ 299,338 | $ 336,468 | $ 341,745 | $ 512,451 | $ 372,462 | $ 866,542 | $ 1,563,126 | $ 1,551,701 |
Midstream gathering and processing expenses | 456,318 | 508,843 | 486,845 | ||||||||
Total Operating Expenses | 2,229,147 | 3,266,819 | 1,152,742 | ||||||||
Natural gas sales | |||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Revenue | $ 671,535 | 1,135,381 | 1,318,472 | ||||||||
As Reported | |||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Total Revenues | 1,346,008 | 1,355,044 | |||||||||
Midstream gathering and processing expenses | 291,725 | 290,188 | |||||||||
Total Operating Expenses | 3,049,701 | 956,085 | |||||||||
As Reported | Natural gas sales | |||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Revenue | 918,263 | 1,121,815 | |||||||||
Adjustments | |||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Total Revenues | 217,118 | 196,657 | |||||||||
Midstream gathering and processing expenses | 217,118 | 196,657 | |||||||||
Total Operating Expenses | 217,118 | 196,657 | |||||||||
Adjustments | Natural gas sales | |||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||||
Revenue | $ 217,118 | $ 196,657 |
Chapter 11 Proceedings - Additi
Chapter 11 Proceedings - Additional Information (Details) $ in Millions | Feb. 25, 2021USD ($)claim | Dec. 31, 2020USD ($) | Nov. 13, 2020 |
Debt Instrument [Line Items] | |||
Debtor-in-possession financing, percentage of lenders involved | 95.00% | ||
Holders of an allowed general unsecured claim, percentage of new common stock received | 94.00% | ||
Debtor-in-possession financing, letters of credit outstanding | $ 262.5 | ||
Debtor-in-possession financing, amount arranged | 105 | ||
Debtor-in-possession financing, borrowings outstanding | 157.5 | ||
Contractual interest expense | $ 15.3 | ||
Subsequent Event | |||
Debt Instrument [Line Items] | |||
Number of claims | claim | 2,200 | ||
Claims amount | $ 12,500 | ||
6.625% senior unsecured notes due 2023 | Senior notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 6.625% | ||
6.000% senior unsecured notes due 2024 | Senior notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 6.00% | ||
6.375% senior unsecured notes due 2025 | Senior notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 6.375% | ||
6.375% senior unsecured notes due 2026 | Senior notes | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 6.375% |
Chapter 11 Proceedings - Compan
Chapter 11 Proceedings - Company's Audited Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Reorganizations [Abstract] | ||
Debt subject to compromise | $ 2,005,219 | $ 0 |
Accounts payable and accrued liabilities | 164,939 | |
Asset retirement obligations | 63,566 | 0 |
Accrued interest on debt subject to compromise | 55,634 | |
Other liabilities | 4,122 | |
Liabilities subject to compromise | $ 2,293,480 | $ 0 |
Chapter 11 Proceedings - Comp_2
Chapter 11 Proceedings - Company's Audited Consolidated Statements of Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Reorganizations [Abstract] | |||
Adjustment to allowed claims | $ 104,943 | ||
Legal and professional fees | 24,905 | ||
Write off of unamortized issuance costs on debt subject to compromise | 21,956 | ||
DIP credit facility financing fees | 2,988 | ||
Gain on settlement of pre-petition accounts payable | (2,433) | ||
Reorganization items, net | $ 152,359 | $ 0 | $ 0 |
Divestitures - Narrative (Detai
Divestitures - Narrative (Details) - USD ($) | Jan. 02, 2020 | Jul. 03, 2019 | Dec. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Business Acquisition [Line Items] | ||||||
Contingent consideration arrangement | $ 6,200,000 | |||||
Water Infrastructure Assets | ||||||
Business Acquisition [Line Items] | ||||||
Proceeds from sale of assets | $ 50,000,000 | |||||
Incentive payments, term | 15 years | |||||
Contingent consideration arrangement | $ 23,100,000 | |||||
Gain (loss) on disposal | $ 0 | |||||
Utica Shale | ||||||
Business Acquisition [Line Items] | ||||||
Proceeds from sale of business | $ 29,000,000 | |||||
Bakken | ||||||
Business Acquisition [Line Items] | ||||||
Proceeds from sale of business | $ 7,000,000 | |||||
Louisiana Assets | ||||||
Business Acquisition [Line Items] | ||||||
Royalty interests | $ 9,200,000 | |||||
Contingent payments | 2 years | |||||
Asset retirement obligation liabilities removed | $ 30,000,000 | |||||
Louisiana Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations | ||||||
Business Acquisition [Line Items] | ||||||
Purchase price of sale | $ 19,700,000 |
Property and Equipment - Schedu
Property and Equipment - Schedule of Property and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Property, Plant and Equipment [Abstract] | ||
Oil and natural gas properties | $ 10,816,909 | $ 10,595,735 |
Other depreciable property and equipment | 85,530 | 91,198 |
Land | 3,008 | 5,521 |
Total property and equipment | 10,905,447 | 10,692,454 |
Accumulated depletion, depreciation, amortization and impairment | (8,819,178) | (7,228,660) |
Property and equipment, net | $ 2,086,269 | $ 3,463,794 |
Property and Equipment - Narrat
Property and Equipment - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2020USD ($)usd_per_mcf | Dec. 31, 2019USD ($)usd_per_mcf | Dec. 31, 2018USD ($)usd_per_mcf | |
Property, Plant and Equipment [Line Items] | |||
Impairment of oil and natural gas properties | $ 1,357,099,000 | $ 2,039,770,000 | $ 0 |
Capitalized general and administrative costs | $ 25,000,000 | $ 30,100,000 | $ 37,700,000 |
Depletion per Mcf of gas equivalent (usd per Mcfe) | usd_per_mcf | 0.61 | 1.08 | 0.96 |
Capitalized costs of oil and natural gas properties excluded from amortization | $ 1,457,043,000 | $ 1,686,666,000 | |
Non producing leases extension term | 5 years | ||
Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Expected number of years amortization will commence | 3 years | ||
Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Expected number of years amortization will commence | 5 years |
Property and Equipment - Summar
Property and Equipment - Summary of Oil and Gas Properties Not Subject to Amortization (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Line Items] | ||||
Acquisition costs | $ 18,485 | $ 8,067 | $ 98,876 | $ 1,330,895 |
Acquisition costs, total | 1,456,323 | |||
Exploration costs | 0 | 0 | 0 | 0 |
Exploration costs, total | 0 | |||
Development costs | 0 | 0 | 0 | 0 |
Development costs, total | 0 | |||
Capitalized interest | 0 | 121 | 172 | 427 |
Capitalized interest, total | 720 | |||
Total oil and natural gas properties not subject to amortization | 18,485 | 8,188 | $ 99,048 | $ 1,331,322 |
Total oil and natural gas properties not subject to amortization, total | 1,457,043 | $ 1,686,666 | ||
Utica | ||||
Property, Plant and Equipment [Line Items] | ||||
Total oil and natural gas properties not subject to amortization, total | 793,441 | |||
SCOOP | ||||
Property, Plant and Equipment [Line Items] | ||||
Total oil and natural gas properties not subject to amortization, total | 662,614 | |||
Other | ||||
Property, Plant and Equipment [Line Items] | ||||
Total oil and natural gas properties not subject to amortization, total | $ 988 |
Property and Equipment - Sche_2
Property and Equipment - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligation, beginning of period | $ 60,355 | $ 79,952 | |
Liabilities incurred | 2,358 | 5,935 | |
Liabilities settled | 0 | (273) | |
Asset retirement obligation removed due to divestiture | (2,213) | (30,146) | $ 0 |
Accretion expense | 3,066 | 3,939 | 4,119 |
Revisions in estimated cash flows | 0 | 948 | |
Total asset retirement obligation as of end of period | 63,566 | 60,355 | $ 79,952 |
Less: amounts reclassified to liabilities subject to compromise | (63,566) | 0 | |
Total asset retirement obligation reflected as non-current liabilities | $ 0 | $ 60,355 |
Equity Investments - Investment
Equity Investments - Investments Accounted for by the Equity Method (Details) - USD ($) | May 01, 2018 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Schedule of Equity Method Investments [Line Items] | ||||
Carrying Value | $ 24,816,000 | $ 32,044,000 | ||
Loss (income) from equity investments, net | $ 11,055,000 | 210,148,000 | $ (49,904,000) | |
Investment in Grizzly Oil Sands ULC | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Approximate Ownership % | 24.50% | |||
Carrying Value | $ 24,816,000 | 21,000,000 | ||
Loss (income) from equity investments, net | $ 377,000 | 32,710,000 | $ 510,000 | |
Investment in Mammoth Energy Services, Inc. | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Approximate Ownership % | 21.50% | 21.50% | ||
Carrying Value | $ 0 | 11,005,000 | ||
Loss (income) from equity investments, net | $ 10,646,000 | 179,524,000 | $ (49,969,000) | |
Investment in Tatex Thailand II, LLC | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Approximate Ownership % | 23.50% | |||
Carrying Value | $ 0 | 0 | ||
Loss (income) from equity investments, net | $ 0 | (2,086,000) | (241,000) | |
Other Equity Investments | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Approximate Ownership % | 0.00% | |||
Carrying Value | $ 0 | 39,000 | ||
Loss (income) from equity investments, net | $ 32,000 | $ 0 | $ (204,000) | |
Investment in Strike Force Midstream LLC | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Loss (income) from equity investments, net | $ (96,400,000) |
Equity Investments - Balance Sh
Equity Investments - Balance Sheet Disclosure (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Schedule of Equity Method Investments [Line Items] | ||
Current assets | $ 409,750 | $ 305,877 |
Current liabilities | 510,287 | 451,198 |
Noncurrent liabilities | 36,604 | 2,117,029 |
Equity Method Investment, Nonconsolidated Investee or Group of Investees | ||
Schedule of Equity Method Investments [Line Items] | ||
Current assets | 483,303 | 421,326 |
Noncurrent assets | 1,092,495 | 1,260,075 |
Current liabilities | 132,978 | 132,569 |
Noncurrent liabilities | $ 148,240 | $ 163,241 |
Equity Investments - Income Sta
Equity Investments - Income Statement Disclosure (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Schedule of Equity Method Investments [Line Items] | |||||||||||
Gross revenue | $ 244,727 | $ 136,176 | $ 186,301 | $ 299,338 | $ 336,468 | $ 341,745 | $ 512,451 | $ 372,462 | $ 866,542 | $ 1,563,126 | $ 1,551,701 |
Equity Method Investment, Nonconsolidated Investee or Group of Investees | |||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||
Gross revenue | 313,076 | 625,012 | 1,729,778 | ||||||||
Net (loss) income | $ (106,072) | $ (76,523) | $ 253,451 |
Equity Investments - Narrative
Equity Investments - Narrative (Details) a in Thousands | Jul. 26, 2018USD ($)shares | Jun. 29, 2018USD ($)shares | Dec. 31, 2020USD ($)ashares | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | May 31, 2019 |
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investment, other than temporary impairment | $ 0 | ||||||
Accumulated other comprehensive loss | $ 43,000,000 | $ 46,833,000 | |||||
Proceeds from sale of equity method investments | 0 | 0 | 226,487,000 | ||||
Income (loss) from equity method investments | (11,055,000) | (210,289,000) | 49,625,000 | ||||
Equity investments | $ 24,816,000 | 32,044,000 | |||||
Investment in Tatex Thailand II, LLC | Apico Llc | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity investment, ownership interest | 8.50% | ||||||
Investment in Grizzly Oil Sands ULC | Athabasca Peace River And Cold Lake Oil Sands Regions | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Gas and oil area, reserve (acres) | a | 830 | ||||||
Investment in Grizzly Oil Sands ULC | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity investment, ownership interest | 24.50% | ||||||
Equity method investment, other than temporary impairment | $ 0 | 32,400,000 | 0 | ||||
Amount of cash paid for equity investments | 0 | 400,000 | |||||
Increase (decrease) due to foreign currency translation adjustment | 4,200,000 | 9,000,000 | $ (15,200,000) | ||||
Accumulated other comprehensive loss | 40,600,000 | 44,800,000 | |||||
Equity investments | $ 24,816,000 | 21,000,000 | |||||
Mammoth Energy Partners LP | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity investment, ownership interest | 21.50% | 21.50% | |||||
Equity method investment, other than temporary impairment | $ 0 | 160,800,000 | |||||
Increase (decrease) due to foreign currency translation adjustment | 200,000 | $ (400,000) | |||||
Equity method investment, ownership (in shares) | shares | 9,829,548 | 9,829,548 | |||||
Gain on sale of equity method investment | $ 28,300,000 | ||||||
Quoted market value of equity method investment | $ 43,700,000 | 21,600,000 | |||||
Income (loss) from equity method investments | (10,600,000) | ||||||
Equity investments | $ 0 | 11,005,000 | |||||
Distributions from equity method investments | 2,500,000 | ||||||
Mammoth Energy Partners LP | Over-allotment option | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Proceeds from sale of equity method investments | $ 4,500,000 | $ 47,000,000 | |||||
Mammoth Energy Partners LP | Common Stock | Over-allotment option | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Shares issued in equity method investment transaction (in shares) | shares | 118,974 | 1,235,600 | |||||
Investment in Tatex Thailand II, LLC | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity investment, ownership interest | 23.50% | ||||||
Equity investments | $ 0 | 0 | |||||
Distributions from equity method investments | $ 0 | $ 2,100,000 |
Long-Term Debt - Summary of Lon
Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Debt Instrument [Line Items] | ||
Net unamortized debt issuance costs | $ 0 | $ (23,751) |
Total Debt, net | 2,258,962 | 1,978,651 |
Less: current maturities of long term debt | (253,743) | (631) |
Less: amounts reclassified to liabilities subject to compromise | (2,005,219) | 0 |
Total Debt reflected as long term | 0 | 1,978,020 |
Building Loan | ||
Debt Instrument [Line Items] | ||
Long-term debt | 21,914 | 22,453 |
Senior notes | 6.625% senior unsecured notes due 2023 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 324,583 | 329,467 |
Stated interest rate | 6.625% | |
Senior notes | 6.000% senior unsecured notes due 2024 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 579,568 | 603,428 |
Stated interest rate | 6.00% | |
Senior notes | 6.375% senior unsecured notes due 2025 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 507,870 | 529,525 |
Stated interest rate | 6.375% | |
Senior notes | 6.375% senior unsecured notes due 2026 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 374,617 | 397,529 |
Stated interest rate | 6.375% | |
Line of Credit | DIP credit facility | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 157,500 | 0 |
Line of Credit | Pre-petition revolving credit facility | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 292,910 | $ 120,000 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Details) | Sep. 30, 2021 | May 01, 2020USD ($) | Dec. 31, 2020USD ($)day | Dec. 31, 2020USD ($)day | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Oct. 08, 2020USD ($) | Jul. 27, 2020USD ($) | Mar. 31, 2020USD ($) | Nov. 25, 2019USD ($) | Jul. 31, 2019USD ($) |
Debt Instrument [Line Items] | |||||||||||
Write off of unamortized issuance costs on debt subject to compromise | $ 21,956,000 | ||||||||||
Debtor-in-possession financing, letters of credit outstanding | $ 262,500,000 | 262,500,000 | |||||||||
Debtor-in-possession financing, amount arranged | 105,000,000 | 105,000,000 | |||||||||
Debtor-in-possession financing, borrowings outstanding | $ 157,500,000 | 157,500,000 | |||||||||
DIP credit facility financing fees | $ 2,988,000 | ||||||||||
Debtor-in-possession financing, number of business days after petition date to terminate | day | 3 | 3 | |||||||||
Debtor-in-possession financing, number of dates after the entry of the interim order to terminate | day | 35 | 35 | |||||||||
Gain on extinguishment of debt | $ 49,579,000 | $ 48,630,000 | $ 0 | ||||||||
Capitalized interest | (907,000) | (3,372,000) | (4,470,000) | ||||||||
Oil and gas properties | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Capitalized interest | (900,000) | (3,400,000) | $ (4,500,000) | ||||||||
Senior notes | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Authorized amount | $ 200,000,000 | 200,000,000 | $ 100,000,000 | ||||||||
Repurchased face amount | 73,300,000 | 73,300,000 | |||||||||
Repayments of debt | 22,800,000 | ||||||||||
Gain on extinguishment of debt | 49,600,000 | ||||||||||
Senior notes | Carrying value | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Outstanding debt | 1,800,000,000 | 1,800,000,000 | |||||||||
Senior notes | Fair value | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Outstanding debt | 1,200,000,000 | $ 1,200,000,000 | |||||||||
Building Loan | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Fixed interest rate on outstanding principal | 4.50% | ||||||||||
Credit facility | 21,900,000 | $ 21,900,000 | |||||||||
DIP credit facility | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Weight average interest rate | 5.50% | ||||||||||
DIP credit facility | Revolving credit facility | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Commitment fee percentage | 0.50% | ||||||||||
DIP credit facility | Letter of credit | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Commitment fee percentage | 0.20% | ||||||||||
DIP credit facility | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | 157,500,000 | $ 157,500,000 | 0 | ||||||||
DIP credit facility | Eurodollar | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest rate | 4.50% | ||||||||||
DIP credit facility | Base Rate | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Interest rate | 3.50% | ||||||||||
Pre-petition revolving credit facility | Revolving credit facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Borrowing base | 700,000,000 | $ 580,000,000 | |||||||||
Long-term debt | 292,900,000 | $ 292,900,000 | |||||||||
Repayments of lines of credit | $ 1,300,000 | ||||||||||
Pre-petition revolving credit facility | Revolving credit facility | Nova Scotia, Amegy, KeyBank | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Proceeds from line of credit | 96,200,000 | ||||||||||
Pre-petition revolving credit facility | Revolving credit facility | Line of Credit | Nova Scotia, Amegy, KeyBank | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Weight average interest rate | 3.15% | ||||||||||
Pre-petition revolving credit facility | Letter of credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Maximum repayment amount | $ 750,000,000 | ||||||||||
Pre-petition revolving credit facility | Letter of credit | Nova Scotia, Amegy, KeyBank | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Borrowing base | $ 700,000,000 | $ 1,000,000,000 | $ 1,200,000,000 | ||||||||
Maximum net secured debt to EBITDAX ratio | 2 | ||||||||||
Proceeds from line of credit | 171,800,000 | ||||||||||
Pre-petition revolving credit facility | Letter of credit | Nova Scotia, Amegy, KeyBank | Prepaid Expenses and Other Current Assets | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term line of credit outstanding | 111,800,000 | $ 111,800,000 | |||||||||
Pre-petition revolving credit facility | Letter of credit | Nova Scotia, Amegy, KeyBank | Forecast | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Net funded debt to EBITDAX ratio | 4 | ||||||||||
Pre-petition revolving credit facility | Letter of credit | Line of Credit | Nova Scotia, Amegy, KeyBank | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term line of credit outstanding | 147,500,000 | 147,500,000 | |||||||||
Pre-petition revolving credit facility | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 292,910,000 | $ 292,910,000 | $ 120,000,000 |
Long-Term Debt - Total Interest
Long-Term Debt - Total Interest Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Long-term Debt, Unclassified [Abstract] | |||
Cash paid for interest | $ 84,823 | $ 142,664 | $ 132,995 |
Change in accrued interest | 30,600 | (3,834) | 7,266 |
Capitalized interest | (907) | (3,372) | (4,470) |
Amortization of loan costs | 5,563 | 6,328 | 6,121 |
Total interest expense | $ 120,079 | $ 141,786 | $ 141,912 |
Changes In Capitalization (Deta
Changes In Capitalization (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Jan. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | May 31, 2018 | Jan. 31, 2018 | |
Class of Stock [Line Items] | |||||||
Stock repurchase program, authorized amount | $ 200,000,000 | $ 100,000,000 | |||||
Stock repurchase program, additional authorized amount | $ 100,000,000 | ||||||
Stock repurchased and retired during period (in shares) | 20,700,000 | ||||||
Stock repurchased and retired during period, net of tax | $ 200,000,000 | ||||||
Stock repurchase program, period in force | 24 months | ||||||
Value of shares repurchased | $ 236,000 | $ 30,688,000 | $ 200,251,000 | ||||
Share purchased to satisfy tax withholding requirements (in shares) | 200,000 | 100,000 | |||||
Tax withholding requirement | $ 200,000 | $ 700,000 | |||||
Common Stock | |||||||
Class of Stock [Line Items] | |||||||
Stock repurchased and retired during period (in shares) | 243,054 | 3,951,198 | 20,746,536 | ||||
Value of shares repurchased | $ 3,000 | $ 40,000 | $ 207,000 | ||||
Share Repurchase Program | Common Stock | |||||||
Class of Stock [Line Items] | |||||||
Stock repurchased and retired during period (in shares) | 0 | 3,800,000 | |||||
Value of shares repurchased | $ 30,000,000 |
Stock-Based Compensation - Narr
Stock-Based Compensation - Narrative (Details) - USD ($) $ in Millions | Aug. 04, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Aug. 31, 2020 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Issuance of common stock, net of related expenses (in shares) | 12,500,000 | ||||
Stock-based compensation expense | $ 16.3 | $ 10.7 | $ 11.3 | ||
Capitalized stock-based compensation | $ 2.9 | $ 5.8 | $ 4.5 | ||
Restricted stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of awards granted (in shares) | 3,069,521 | 4,011,073 | 1,579,911 | ||
Unrecognized compensation expense | $ 5.2 | ||||
Weighted average period | 1 year 3 months 21 days | ||||
Restricted stock | 2019 Plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of awards granted (in shares) | 7,630,554 | ||||
Restricted stock | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based payment award, award vesting period | 1 year | ||||
Restricted stock | Minimum | Director | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based payment award, award vesting period | 1 year | ||||
Restricted stock | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based payment award, award vesting period | 3 years | ||||
Restricted stock | Maximum | Employee | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based payment award, award vesting period | 3 years | ||||
Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of awards granted (in shares) | 0 | 2,009,144 | 0 | ||
Unrecognized compensation expense | $ 1.4 | ||||
Weighted average period | 1 year 3 months 7 days | ||||
Share-based payment award, relative total shareholder return, target award, minimum | 0.00% | ||||
Share-based payment award, relative total shareholder Return, target award, maximum | 200.00% | ||||
Share-based payment award, expected award performance period | 2 years | ||||
Share-based payment award, fair value assumptions, risk free interest rate, minimum | 1.56% | ||||
Share-based payment award, fair value assumptions, risk free interest rate, maximum | 2.42% | ||||
Share-based payment award, fair value assumptions, expected volatility rate, minimum | 29.10% | ||||
Share-based payment award, fair value assumptions, expected volatility rate, maximum | 85.10% | ||||
Performance Shares | 2019 Plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of awards granted (in shares) | 840,595 | ||||
Incentive Awards | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Stock-based compensation expense | $ 1.5 | ||||
Percentage of cash retention incentives clawed back | 50.00% | ||||
Percentage of cash retention incentives repaid | 50.00% | ||||
Cash retention | $ 13.5 | ||||
Cash incentives net paid | 3.6 | ||||
Prepaid cash incentives | $ 4.8 |
Stock-Based Compensation - Summ
Stock-Based Compensation - Summary of Restricted Stock Award and Unit Activity (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Restricted stock | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Beginning of period (in shares) | 4,098,318 | 1,535,811 | 976,027 |
Granted (in shares) | 3,069,521 | 4,011,073 | 1,579,911 |
Vested (in shares) | (1,294,285) | (676,108) | (626,671) |
Forfeited (in shares) | (4,171,041) | (772,458) | (393,456) |
End of period (in shares) | 1,702,513 | 4,098,318 | 1,535,811 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |||
Weighted average grant date fair value, beginning of period (in dollars per share) | $ 4.73 | $ 11.57 | $ 18.71 |
Granted, weighted average grant date fair value (in dollars per share) | 0.85 | 3.74 | 9.90 |
Vested, weighted average grant date fair value (in dollars per share) | 5.73 | 12.89 | 18.05 |
Forfeited, weighted average grant date fair value (in dollars per share) | 1.68 | 6.05 | 12.23 |
Weighted average grant date fair value,, end of period (in dollars per share) | $ 4.74 | $ 4.73 | $ 11.57 |
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Beginning of period (in shares) | 1,783,660 | 0 | 0 |
Granted (in shares) | 0 | 2,009,144 | 0 |
Vested (in shares) | 0 | 0 | 0 |
Forfeited (in shares) | (943,065) | (225,484) | 0 |
End of period (in shares) | 840,595 | 1,783,660 | 0 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |||
Weighted average grant date fair value, beginning of period (in dollars per share) | $ 2.96 | $ 0 | $ 0 |
Granted, weighted average grant date fair value (in dollars per share) | 0 | 2.85 | 0 |
Vested, weighted average grant date fair value (in dollars per share) | 0 | 0 | 0 |
Forfeited, weighted average grant date fair value (in dollars per share) | 1.98 | 1.98 | 0 |
Weighted average grant date fair value,, end of period (in dollars per share) | $ 4.07 | $ 2.96 | $ 0 |
Revenue From Contracts With C_2
Revenue From Contracts With Customers (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Performance obligation description | However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. | |
Receivables from customers | $ 119,879 | $ 121,210 |
Maximum | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Performance obligation description | 30 days |
Leases - Narrative (Details)
Leases - Narrative (Details) | Dec. 31, 2020 |
Lessee, Lease, Description [Line Items] | |
Weighted average remaining lease term | 3 years 10 days |
Weighted-average discount rate - operating lease | 4.22% |
Minimum | |
Lessee, Lease, Description [Line Items] | |
Lease term | 1 year |
Maximum | |
Lessee, Lease, Description [Line Items] | |
Lease term | 5 years |
Drilling Rig | Minimum | |
Lessee, Lease, Description [Line Items] | |
Lease term | 1 year |
Drilling Rig | Maximum | |
Lessee, Lease, Description [Line Items] | |
Lease term | 2 years |
Leases - Maturities of Lease Li
Leases - Maturities of Lease Liabilities (Details) $ in Thousands | Dec. 31, 2020USD ($) |
Leases [Abstract] | |
2021 | $ 129 |
2022 | 115 |
2023 | 90 |
2024 | 30 |
Total lease payments | 364 |
Less: Imputed interest | (22) |
Less: amounts reclassified to liabilities subject to compromise | (342) |
Total lease liabilities | $ 0 |
Leases - Lease Cost (Details)
Leases - Lease Cost (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Leases [Abstract] | ||
Operating lease cost | $ 9,658 | $ 24,960 |
Operating lease cost - related party | 0 | 22,440 |
Variable lease cost | 586 | 2,172 |
Variable lease cost - related party | 0 | 66,924 |
Short-term lease cost | 9,361 | 834 |
Total lease cost | $ 19,605 | $ 117,330 |
Leases - Other Information (Det
Leases - Other Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Leases [Abstract] | ||
Operating cash flows from operating leases | $ 140 | $ 182 |
Investing cash flow from operating leases | 10,272 | 24,263 |
Investing cash flow from operating leases - related party | $ 6,800 | $ 84,750 |
Income Taxes - Schedule of Comp
Income Taxes - Schedule of Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Current: | |||||||||||
State | $ 0 | $ 0 | $ (1,530) | ||||||||
Federal | (273) | (7) | 253 | ||||||||
Deferred: | |||||||||||
State | 7,563 | (7,556) | 1,530 | ||||||||
Federal | 0 | 0 | (322) | ||||||||
Total income tax expense (benefit) provision | $ 0 | $ 0 | $ 0 | $ 7,290 | $ 315,815 | $ (144,047) | $ (179,331) | $ 0 | $ 7,290 | $ (7,563) | $ (69) |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Statutory Federal Income Tax Amount (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |||||||||||
(Loss) income before federal income taxes | $ (1,617,843) | $ (2,009,921) | $ 430,491 | ||||||||
Expected income tax at statutory rate | (339,747) | (422,083) | 90,403 | ||||||||
State income taxes | (14,696) | (28,316) | (511) | ||||||||
Other differences | 10,800 | 3,372 | 1,078 | ||||||||
Change in valuation allowance due to current year activity | 350,933 | 439,464 | (91,039) | ||||||||
Total income tax expense (benefit) provision | $ 0 | $ 0 | $ 0 | $ 7,290 | $ 315,815 | $ (144,047) | $ (179,331) | $ 0 | $ 7,290 | $ (7,563) | $ (69) |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred tax assets: | |||
Net operating loss carryforward | $ 392,318 | $ 269,851 | $ 164,363 |
Oil and gas property basis difference | 463,705 | 289,850 | 3,595 |
Investment in pass through entities | 61,078 | 58,951 | 8,620 |
Stock-based compensation expense | 1,223 | 1,440 | 616 |
Business energy investment tax credit | 370 | 370 | 369 |
Charitable contributions carryover | 318 | 297 | 269 |
Change in fair value of derivative instruments | 7,656 | 11,219 | 2,761 |
Foreign tax credit carryforwards | 523 | 943 | 2,009 |
Accrued liabilities | 868 | 669 | 834 |
ARO liability | 13,414 | 12,744 | 16,923 |
Non-oil and gas property basis difference | 0 | 0 | 104 |
Lease liability | 72 | 12,128 | 0 |
Reorganization items | 25,714 | 0 | 0 |
State net operating loss carryover | 22,191 | 13,258 | 11,526 |
Interest expense carryforward | 0 | 23,818 | 0 |
Total deferred tax assets | 989,450 | 695,538 | 211,989 |
Valuation allowance for deferred tax assets | (985,528) | (647,575) | (211,987) |
Deferred tax assets, net of valuation allowance | 3,922 | 47,963 | 2 |
Deferred tax liabilities: | |||
Non-oil and gas property basis difference | 575 | 1,859 | 0 |
Change in fair value of derivative instruments | 3,272 | 26,410 | 2 |
Right of use asset | 72 | 12,128 | 0 |
Other | 3 | 3 | 0 |
Total deferred tax liabilities | 3,922 | 40,400 | 2 |
Net deferred tax asset | $ 0 | $ 7,563 | $ 0 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Apr. 30, 2020 | |
Operating Loss Carryforwards [Line Items] | ||||||||||||
Income tax (benefit) expense | $ 0 | $ 0 | $ 0 | $ 7,290 | $ 315,815 | $ (144,047) | $ (179,331) | $ 0 | $ 7,290 | $ (7,563) | $ (69) | |
Foreign tax credit carryforwards | 523 | 943 | 523 | 943 | 2,009 | |||||||
Valuation allowance for deferred tax assets | (985,528) | $ (647,575) | (985,528) | (647,575) | (211,987) | |||||||
Valuation allowance increase (decrease) | $ 338,000 | $ 439,500 | $ (86,800) | |||||||||
Testing period | 3 years | |||||||||||
Maximum percentage of company's securities allowed to be owned by third party | 4.90% | |||||||||||
Uncertain tax positions, liability | 3,800 | $ 3,800 | ||||||||||
Federal | ||||||||||||
Operating Loss Carryforwards [Line Items] | ||||||||||||
Net operating loss carryforward | 1,900,000 | 1,900,000 | ||||||||||
State | ||||||||||||
Operating Loss Carryforwards [Line Items] | ||||||||||||
Operating loss carryforwards, subject to expiration | $ 441,000 | $ 441,000 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Basic | |||||||||||
Net (loss) income | $ (1,625,133,000) | $ (2,002,358,000) | $ 430,560,000 | ||||||||
Basic Shares (in shares) | 160,231,335 | 160,341,125 | 174,675,840 | ||||||||
Basic EPS (in dollars per share) | $ (1.03) | $ (2.37) | $ (3.51) | $ (3.24) | $ (11.36) | $ (3.04) | $ 1.47 | $ 0.38 | $ (10.14) | $ (12.49) | $ 2.46 |
Effect of dilutive securities: | |||||||||||
Stock options and awards | $ 0 | $ 0 | $ 722,866 | ||||||||
Dilutive Shares (in shares) | 160,231,335 | 160,341,125 | 175,398,706 | ||||||||
Dilutive EPS (in dollars per share) | $ (1.03) | $ (2.37) | $ (3.51) | $ (3.24) | $ (11.36) | $ (3.04) | $ 1.47 | $ 0.38 | $ (10.14) | $ (12.49) | $ 2.45 |
Anti-dilutive common shares excluded from calculation of earnings per share (in shares) | 0 | 3,867,084 | 0 |
Derivative Instruments - Schedu
Derivative Instruments - Schedule of Derivative Instruments (Details) | 12 Months Ended |
Dec. 31, 2020MMBTU$ / MMBTU | |
NYMEX Henry Hub Swap - 2021 | |
Derivative [Line Items] | |
Daily Volume (MMBtu/day) | MMBTU | 410,000 |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.75 |
N Y M E X Henry Hub2021 | |
Derivative [Line Items] | |
Daily Volume (MMBtu/day) | MMBTU | 250,000 |
N Y M E X Henry Hub2021 | Minimum | |
Derivative [Line Items] | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.46 |
N Y M E X Henry Hub2021 | Maximum | |
Derivative [Line Items] | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.81 |
N Y M E X Henry Hub2022 | |
Derivative [Line Items] | |
Daily Volume (MMBtu/day) | MMBTU | 20,000 |
N Y M E X Henry Hub2022 | Minimum | |
Derivative [Line Items] | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.80 |
N Y M E X Henry Hub2022 | Maximum | |
Derivative [Line Items] | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 3.40 |
NYMEX Henry Hub Swap 2022 | Call option | Short | |
Derivative [Line Items] | |
Daily Volume (MMBtu/day) | MMBTU | 153,000 |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.90 |
NYMEX Henry Hub Swap 2023 | Call option | Short | |
Derivative [Line Items] | |
Daily Volume (MMBtu/day) | MMBTU | 628,000 |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.90 |
Rex Zone 3 | |
Derivative [Line Items] | |
Daily Volume (MMBtu/day) | MMBTU | 35,000 |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | (0.21) |
Tetco M2 | |
Derivative [Line Items] | |
Daily Volume (MMBtu/day) | MMBTU | 60,000 |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | (0.67) |
Derivative Instruments - Narrat
Derivative Instruments - Narrative (Details) $ in Millions | Dec. 31, 2020USD ($) |
Derivative [Line Items] | |
Contingent consideration arrangement | $ 6.2 |
Prepaid Expenses and Other Current Assets | |
Derivative [Line Items] | |
Contingent consideration arrangement | $ 1.1 |
Derivative Instruments - Contin
Derivative Instruments - Contingent Consideration Arrangement (Details) | 12 Months Ended |
Dec. 31, 2020USD ($)$ / shares | |
Derivative [Line Items] | |
Derivative, credit risk related contingent features, payment to be received, denominator (in dollars per share) | $ / shares | $ 8.03 |
Derivative Threshold One | |
Derivative [Line Items] | |
Payment to be received | $ | $ 150,000 |
Derivative Threshold Two | |
Derivative [Line Items] | |
Payment to be received | $ | $ 150,000 |
Derivative Threshold Two | Minimum | |
Derivative [Line Items] | |
Derivative, credit risk related contingent features, commodity price threshold (in dollars per share) | $ / shares | $ 52.62 |
Derivative Threshold Two | Maximum | |
Derivative [Line Items] | |
Derivative, credit risk related contingent features, commodity price threshold (in dollars per share) | $ / shares | $ 60.65 |
Derivative Threshold Three | |
Derivative [Line Items] | |
Payment to be received | $ | $ 0 |
Derivative Instruments - Sche_2
Derivative Instruments - Schedule of Derivative Instruments in Statement of Financial Position (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Derivative [Line Items] | ||
Total short-term derivative instruments – asset | $ 27,146 | $ 126,201 |
Total long-term derivative instruments – asset | 322 | 563 |
Total short-term derivative instruments – liability | 11,641 | 303 |
Total long-term derivative instruments – liability | 36,604 | 53,135 |
Commodity derivative instruments | ||
Derivative [Line Items] | ||
Total short-term derivative instruments – asset | 27,146 | 125,383 |
Total long-term derivative instruments – asset | 322 | 0 |
Contingent consideration arrangement | ||
Derivative [Line Items] | ||
Total short-term derivative instruments – asset | 0 | 818 |
Total long-term derivative instruments – asset | $ 0 | $ 563 |
Derivative Instruments - Gain (
Derivative Instruments - Gain (Loss) on Derivative Instruments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Derivative [Line Items] | |||
Net gain (loss) on natural gas, oil, and NGL derivatives | $ 65,291 | $ 208,360 | $ (123,479) |
Natural gas derivatives | |||
Derivative [Line Items] | |||
Net gain (loss) on natural gas, oil, and NGL derivatives | 23,765 | 194,450 | (116,130) |
Oil derivatives | |||
Derivative [Line Items] | |||
Net gain (loss) on natural gas, oil, and NGL derivatives | 43,510 | 7,035 | (13,084) |
NGL derivatives | |||
Derivative [Line Items] | |||
Net gain (loss) on natural gas, oil, and NGL derivatives | (603) | 6,632 | 5,735 |
Contingent consideration arrangement | |||
Derivative [Line Items] | |||
Net gain (loss) on natural gas, oil, and NGL derivatives | $ (1,381) | $ 243 | $ 0 |
Derivative Instruments - Sche_3
Derivative Instruments - Schedule of Offsetting (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative asset, gross asset | $ 27,468 | $ 126,764 |
Derivative asset, netting adjustment | (25,730) | (53,438) |
Derivative asset, net | 1,738 | 73,326 |
Derivative liability, gross liability | (48,245) | (53,438) |
Derivative liability, netting adjustment | 25,730 | 53,438 |
Derivative liability, net | $ (22,515) | $ 0 |
Restructuring And Liability M_3
Restructuring And Liability Management (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2020 | |
Restructuring and Related Activities [Abstract] | ||||
Workforce reduction | 13.00% | 10.00% | ||
Reduction in workforce | $ 1,460 | $ 4,611 | ||
Liability management | 29,387 | 0 | ||
Total restructuring and liability management expenses | $ 30,847 | $ 4,611 | $ 0 |
Fair Value Measurements - Summa
Fair Value Measurements - Summary of Financial and Non-Financial Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Contingent consideration arrangement | $ 6,200 | |
Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative asset | 0 | $ 0 |
Contingent consideration arrangement | 0 | |
Total assets | 0 | |
Liabilities | 0 | 0 |
Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative asset | 27,468 | 126,764 |
Contingent consideration arrangement | 0 | |
Total assets | 27,468 | |
Liabilities | 48,245 | 53,438 |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative asset | 0 | 0 |
Contingent consideration arrangement | 6,200 | |
Total assets | 6,200 | |
Liabilities | $ 0 | $ 0 |
Fair Value Measurements - Narra
Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Contingent consideration arrangement | $ 6,200 | |
Contingent consideration, gain (loss) due to change in value | 16,600 | |
Contingent consideration, settlements | 300 | |
Asset retirement obligation capitalized | 2,358 | $ 5,935 |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Contingent consideration arrangement | 6,200 | |
Asset retirement obligation capitalized | 2,400 | |
Prepaid Expenses and Other Current Assets | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Contingent consideration arrangement | 1,100 | |
Other Noncurrent Assets | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Contingent consideration arrangement | $ 5,100 |
Related Party Transactions (Det
Related Party Transactions (Details) - Mammoth Energy Partners LP - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Related Party Transaction [Line Items] | |||
Equity investment, ownership interest | 21.50% | 21.50% | |
Investee | |||
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | $ 3,100,000 | $ 109,900,000 | |
Due to related parties | 8,400,000 | ||
Investee | Lease operating expense | |||
Related Party Transaction [Line Items] | |||
Related party services provided | $ 0 | $ 600,000 | $ 2,000,000 |
Commitments - Schedule of Firm
Commitments - Schedule of Firm Transportation Contracts (Details) - Transportation commitment $ in Thousands | Dec. 31, 2020USD ($) |
Transportation [Abstract] | |
2021 | $ 370,343 |
2022 | 380,979 |
2023 | 379,171 |
2024 | 358,990 |
2025 | 272,123 |
Thereafter | 2,013,119 |
Total | $ 3,774,725 |
Commitments - Schedule of Fir_2
Commitments - Schedule of Firm Sales Contracted with Third Parties (Details) | Dec. 31, 2020MMBTU |
Commitments and Contingencies Disclosure [Abstract] | |
2021 (MMBtu per day) | 88,000 |
2022 (MMBtu per day) | 58,000 |
2023 (MMBtu per day) | 17,000 |
2024 (MMBtu per day) | 0 |
2025 (MMBtu per day) | 0 |
Thereafter (MMBtu per day) | 0 |
Total (MMBtu per day) | 163,000 |
Commitments - Narrative (Detail
Commitments - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Commitments [Line Items] | |||
Percentage decrease in future demand reservation fees | 50.00% | ||
Percentage decrease in future demand reservation volume | 35.00% | ||
Maximum annual contributions per employee (401K Plan) | 100.00% | ||
Minimum matching employer contribution for 401K | 50.00% | ||
Cost recognized on defined contribution plan | $ 2.6 | $ 2.9 | $ 2.6 |
Minimum | |||
Commitments [Line Items] | |||
Minimum matching employer contribution for 401K | 4.00% | ||
Maximum | |||
Commitments [Line Items] | |||
Minimum matching employer contribution for 401K | 6.00% |
Contingencies - Narrative (Deta
Contingencies - Narrative (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
Apr. 30, 2020 | Jan. 31, 2020USD ($)well_pad | Dec. 31, 2020USD ($)claim | |
Loss Contingencies [Line Items] | |||
Number of claims filed | claim | 2 | ||
Loss contingency, damages sought, percentages of unpaid overtime compensation | 6.00% | ||
Settlement pay | $ 1.7 | ||
Invest in improvements well pads | well_pad | 17 | ||
Stingray Pressure Pumping L L C V Gulfport Energy Corporation | |||
Loss Contingencies [Line Items] | |||
Loss contingency, damages sought | $ 43.4 | ||
Muskie V Gulfport Energy Corporation | |||
Loss Contingencies [Line Items] | |||
Loss contingency, damages sought | $ 3.4 |
Contingencies - Sales to Major
Contingencies - Sales to Major Customers (Details) - Customer concentration risk - Revenue | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Company A | |||
Product Information [Line Items] | |||
Percentage of sales to major customers | 12.00% | 14.00% | 17.00% |
Company B | |||
Product Information [Line Items] | |||
Percentage of sales to major customers | 10.00% |
Supplemental Information on O_3
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Narrative (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020USD ($)Bcfewell$ / bbl$ / MMBTU | Dec. 31, 2019USD ($)Bcfewell$ / MMBTU$ / bbl | Dec. 31, 2018USD ($)BcfeTcfewell$ / bbl$ / MMBTU | |
Reserve Quantities [Line Items] | |||
Interest capitalized | $ | $ 907 | $ 3,372 | $ 4,470 |
Capitalized general and administrative costs | $ | $ 25,000 | $ 30,100 | $ 37,700 |
Increase (decrease) in reserve during the period | 239.8 | 1.1 | 711.2 |
Decline in performance | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserve, revision of previous estimate | (1.7) | (733.8) | |
Lower commodity prices | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserve, revision of previous estimate | (1,268.4) | (296.4) | |
Utica Shale | |||
Reserve Quantities [Line Items] | |||
Increase (decrease) in reserve during the period | 150.6 | 793.5 | 556.3 |
Planned unit development | well | 14 | 72 | 75 |
Proved developed and undeveloped reserves, sale of mineral in place | 44.9 | ||
Utica Shale | Decline in performance | |||
Reserve Quantities [Line Items] | |||
Planned unit development | well | 48 | 9 | |
Proved developed and undeveloped reserve, revision of previous estimate | (720.3) | (347.2) | 8.3 |
Proved developed, revision of previous estimate | 263.8 | 90.2 | |
Utica Shale | Lower commodity prices | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserve, revision of previous estimate | Tcfe | (1) | ||
Utica Shale | Exclusion of PUD locations | |||
Reserve Quantities [Line Items] | |||
Planned unit development | well | 127 | ||
Utica Shale | Improved performance | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserve, revision of previous estimate | 82.4 | ||
Utica Shale | Change in ownership interest | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserve, revision of previous estimate | 67.6 | ||
Utica Shale | Increase in pricing | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserve, revision of previous estimate | 27.9 | ||
SCOOP Properties | |||
Reserve Quantities [Line Items] | |||
Increase (decrease) in reserve during the period | 87.8 | 302.9 | 90.1 |
Planned unit development | well | 8 | 37 | 11 |
SCOOP Properties | Decline in performance | |||
Reserve Quantities [Line Items] | |||
Planned unit development | well | 31 | 22 | |
SCOOP Properties | Exclusion of PUD locations | |||
Reserve Quantities [Line Items] | |||
Planned unit development | well | 12 | ||
SCOOP Properties | Rescheduled drilling | |||
Reserve Quantities [Line Items] | |||
Proved undeveloped reserves, postponement of drilling period | 5 years | ||
Louisiana Field | |||
Reserve Quantities [Line Items] | |||
Increase (decrease) in reserve during the period | 3 | ||
Planned unit development | well | 13 | ||
Oil derivatives | |||
Reserve Quantities [Line Items] | |||
Price per unit (usd per barrel or MMbtu) | $ / bbl | 39.54 | 55.85 | 65.56 |
Natural gas, per MMbtu | |||
Reserve Quantities [Line Items] | |||
Price per unit (usd per barrel or MMbtu) | $ / MMBTU | 1.99 | 2.58 | 3.10 |
Natural gas liquids | |||
Reserve Quantities [Line Items] | |||
Price per unit (usd per barrel or MMbtu) | $ / bbl | 15.40 | 21.25 | 32.02 |
Oil and gas properties | |||
Reserve Quantities [Line Items] | |||
Interest capitalized | $ | $ 900 | $ 3,400 | $ 4,500 |
Investment in Grizzly Oil Sands ULC | |||
Reserve Quantities [Line Items] | |||
Equity investment, ownership interest | 24.50% |
Supplemental Information on O_4
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Capitalized Costs Related to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Extractive Industries [Abstract] | ||
Proved properties | $ 9,359,866 | $ 8,909,069 |
Unproved properties | 1,457,043 | 1,686,666 |
Capitalized costs, gross | 10,816,909 | 10,595,735 |
Accumulated depreciation, depletion, amortization and impairment | (8,778,759) | (7,191,957) |
Net capitalized costs | $ 2,038,150 | $ 3,403,778 |
Supplemental Information on O_5
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Costs Incurred In Oil and Gas Property Acquisition and Development Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Extractive Industries [Abstract] | |||
Acquisition | $ 15,260 | $ 37,598 | $ 119,444 |
Development | 276,622 | 594,673 | 714,269 |
Exploratory | 0 | 9,762 | 22,081 |
Total | $ 291,882 | $ 642,033 | $ 855,794 |
Supplemental Information on O_6
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Results of Operations for Producing Activities (Details) | 12 Months Ended | ||
Dec. 31, 2020USD ($)usd_per_mcf | Dec. 31, 2019USD ($)usd_per_mcf | Dec. 31, 2018USD ($)usd_per_mcf | |
Extractive Industries [Abstract] | |||
Revenues | $ 801,251,000 | $ 1,354,766,000 | $ 1,675,180,000 |
Production costs | (537,609,000) | (620,412,000) | (611,965,000) |
Depletion | (229,702,000) | (539,379,000) | (476,517,000) |
Impairment | (1,357,099,000) | (2,039,770,000) | 0 |
Income tax (expense) benefit | (7,290,000) | 7,563,000 | 68,000 |
Results of operations from producing activities | $ (1,330,449,000) | $ (1,837,232,000) | $ 586,766,000 |
Depletion per Mcf of gas equivalent (usd per Mcfe) | usd_per_mcf | 0.61 | 1.08 | 0.96 |
Supplemental Information on O_7
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Oil and Gas Reserves (Details) bbl in Thousands, Bcf in Thousands | 12 Months Ended | ||
Dec. 31, 2020bblBcf | Dec. 31, 2019bblBcf | Dec. 31, 2018bblBcf | |
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | Bcf | 4,528,000 | 4,743,000 | 5,395,000 |
Purchases of reserves | Bcf | 0 | 0 | 0 |
Extensions and discoveries | Bcf | 240,000 | 1,097,000 | 711,000 |
Sales of reserves | Bcf | (75,000) | (77,000) | (45,000) |
Revisions of prior reserve estimates | Bcf | (1,725,000) | (734,000) | (821,000) |
Current production | Bcf | (380,000) | (502,000) | (497,000) |
End of period | Bcf | 2,588,000 | 4,528,000 | 4,743,000 |
Proved developed reserves (Volume) | Bcf | 1,527,000 | 1,984,000 | 2,115,000 |
Proved undeveloped reserves (Volume) | Bcf | 1,061,000 | 2,544,000 | 2,628,000 |
Oil | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | bbl | 18,000 | 21,000 | 19,000 |
Purchases of reserves | bbl | 0 | 0 | 0 |
Extensions and discoveries | bbl | 1,000 | 4,000 | 5,000 |
Sales of reserves | bbl | 0 | (2,000) | 0 |
Revisions of prior reserve estimates | bbl | (4,000) | (2,000) | 0 |
Current production | bbl | (2,000) | (2,000) | (3,000) |
End of period | bbl | 13,000 | 18,000 | 21,000 |
Proved developed reserves (Volume) | bbl | 7,000 | 8,000 | 10,000 |
Proved undeveloped reserves (Volume) | bbl | 7,000 | 10,000 | 11,000 |
Natural Gas | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | Bcf | 4,048,000 | 4,134,000 | 4,825,000 |
Purchases of reserves | Bcf | 0 | 0 | 0 |
Extensions and discoveries | Bcf | 216,000 | 997,000 | 622,000 |
Sales of reserves | Bcf | (74,000) | (63,000) | (43,000) |
Revisions of prior reserve estimates | Bcf | (1,564,000) | (562,000) | (827,000) |
Current production | Bcf | (345,000) | (458,000) | (444,000) |
End of period | Bcf | 2,281,000 | 4,048,000 | 4,134,000 |
Proved developed reserves (Volume) | Bcf | 1,358,000 | 1,757,000 | 1,813,000 |
Proved undeveloped reserves (Volume) | Bcf | 923,000 | 2,291,000 | 2,321,000 |
Natural Gas Liquids | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning of the period | bbl | 62,000 | 81,000 | 76,000 |
Purchases of reserves | bbl | 0 | 0 | 0 |
Extensions and discoveries | bbl | 3,000 | 13,000 | 10,000 |
Sales of reserves | bbl | 0 | 0 | 0 |
Revisions of prior reserve estimates | bbl | (23,000) | (27,000) | 1,000 |
Current production | bbl | (4,000) | (5,000) | (6,000) |
End of period | bbl | 38,000 | 62,000 | 81,000 |
Proved developed reserves (Volume) | bbl | 22,000 | 30,000 | 41,000 |
Proved undeveloped reserves (Volume) | bbl | 16,000 | 32,000 | 40,000 |
Supplemental Information on O_8
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Millions | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Extractive Industries [Abstract] | |||
Future cash flows | $ 4,079 | $ 10,451 | $ 14,483 |
Future development and abandonment costs | (652) | (2,058) | (2,438) |
Future production costs | (2,325) | (4,513) | (5,068) |
Future production taxes | (137) | (333) | (456) |
Future income taxes | 0 | 0 | (943) |
Future net cash flows | 965 | 3,547 | 5,578 |
10% discount to reflect timing of cash flows | (425) | (1,844) | (2,596) |
Standardized measure of discounted future net cash flows | $ 540 | $ 1,703 | $ 2,982 |
Supplemental Information on O_9
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Extractive Industries [Abstract] | |||
Sales and transfers of oil and gas produced, net of production costs | $ (264) | $ (734) | $ (1,063) |
Net changes in prices, production costs, and development costs | (954) | (1,372) | 591 |
Acquisition of oil and gas reserves in place | 0 | 0 | 0 |
Extensions and discoveries | 38 | 388 | 519 |
Previously estimated development costs incurred during the period | 215 | 406 | 402 |
Revisions of previous quantity estimates, less related production costs | (255) | (321) | (357) |
Sales of oil and gas reserves in place | (6) | (49) | (26) |
Accretion of discount | 170 | 298 | 264 |
Net changes in income taxes | 0 | 425 | (185) |
Change in production rates and other | (109) | (319) | 194 |
Total change in standardized measure of discounted future net cash flows | $ (1,165) | $ (1,278) | $ 339 |
Selected Quarterly Financial _3
Selected Quarterly Financial Data (Unaudited) - Schedule of Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 244,727 | $ 136,176 | $ 186,301 | $ 299,338 | $ 336,468 | $ 341,745 | $ 512,451 | $ 372,462 | $ 866,542 | $ 1,563,126 | $ 1,551,701 |
(Loss) income from operations | 19,632 | (346,400) | (555,750) | (480,087) | (1,444,205) | (570,955) | 218,456 | 93,011 | (1,362,605) | (1,703,693) | 398,959 |
Income tax (benefit) expense | 0 | 0 | 0 | 7,290 | 315,815 | (144,047) | (179,331) | 0 | 7,290 | (7,563) | (69) |
Net (loss) income | $ (165,564) | $ (380,963) | $ (561,068) | $ (517,538) | $ (1,814,754) | $ (484,802) | $ 234,956 | $ 62,242 | $ (1,625,133) | $ (2,002,358) | $ 430,560 |
Basic (in dollars per share) | $ (1.03) | $ (2.37) | $ (3.51) | $ (3.24) | $ (11.36) | $ (3.04) | $ 1.47 | $ 0.38 | $ (10.14) | $ (12.49) | $ 2.46 |
Diluted (in dollars per share) | $ (1.03) | $ (2.37) | $ (3.51) | $ (3.24) | $ (11.36) | $ (3.04) | $ 1.47 | $ 0.38 | $ (10.14) | $ (12.49) | $ 2.45 |
Subsequent Events (Details)
Subsequent Events (Details) | 2 Months Ended | 12 Months Ended |
Mar. 01, 2021MMBTU$ / MMBTU | Dec. 31, 2020MMBTU$ / MMBTU | |
Tetco M2 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 60,000 | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | (0.67) | |
Rex Zone 3 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 35,000 | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | (0.21) | |
Subsequent Event | NYMEX WTI | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 2,250 | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 53.07 | |
Subsequent Event | Mont Belvieu C3 Swap - 2021 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 3,100 | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 27.80 | |
Subsequent Event | Mont Belvieu C3 Swap - 2022 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 1,000 | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 27.30 | |
Subsequent Event | Tetco M2 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 36,443 | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | (0.61) | |
Subsequent Event | Rex Zone 3 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 94,505 | |
Weighted average price of derivative swap (usd per MMBtu or Bbls) | (0.22) | |
Subsequent Event | NYMEX Henry Hub - 2021 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 210,000 | |
Subsequent Event | NYMEX Henry Hub - 2021 | Minimum | ||
Subsequent Event [Line Items] | ||
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.67 | |
Subsequent Event | NYMEX Henry Hub - 2021 | Maximum | ||
Subsequent Event [Line Items] | ||
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 3.15 | |
Subsequent Event | NYMEX Henry Hub - 2022 | ||
Subsequent Event [Line Items] | ||
Daily Volume (MMBtu/day) | MMBTU | 340,000 | |
Subsequent Event | NYMEX Henry Hub - 2022 | Minimum | ||
Subsequent Event [Line Items] | ||
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 2.82 | |
Subsequent Event | NYMEX Henry Hub - 2022 | Maximum | ||
Subsequent Event [Line Items] | ||
Weighted average price of derivative swap (usd per MMBtu or Bbls) | 3.40 |