Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2018 | Feb. 11, 2019 | Jun. 30, 2018 | |
Document And Entity Information | |||
Entity Registrant Name | Laredo Petroleum, Inc. | ||
Entity Central Index Key | 1,528,129 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth | false | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 233,924,462 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Entity voluntary filer | No | ||
Entity well known seasoned issuer | Yes | ||
Entity public float | $ 1.5 |
Consolidated balance sheets
Consolidated balance sheets - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 45,151 | $ 112,159 |
Accounts receivable, net | 94,321 | 100,645 |
Derivatives | 39,835 | 6,892 |
Other current assets | 13,445 | 15,686 |
Total current assets | 192,752 | 235,382 |
Oil and natural gas properties, full cost method: | ||
Evaluated properties | 6,752,631 | 6,070,940 |
Unevaluated properties not being depleted | 130,957 | 175,865 |
Less accumulated depletion and impairment | (4,854,017) | (4,657,466) |
Oil and natural gas properties, net | 2,029,571 | 1,589,339 |
Other fixed assets, net | 39,819 | 40,721 |
Property and equipment, net | 2,199,635 | 1,768,385 |
Derivatives | 11,030 | 3,413 |
Other noncurrent assets, net | 16,888 | 16,109 |
Total assets | 2,420,305 | 2,023,289 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 69,504 | 58,341 |
Accrued capital expenditures | 29,975 | 82,721 |
Undistributed revenue and royalties | 48,841 | 37,852 |
Derivatives | 7,359 | 22,950 |
Other current liabilities | 44,786 | 75,555 |
Total current liabilities | 200,465 | 277,419 |
Long-term debt, net | 983,636 | 791,855 |
Derivatives | 0 | 384 |
Asset retirement obligations | 53,387 | 53,962 |
Other noncurrent liabilities | 8,587 | 134,090 |
Total liabilities | 1,246,075 | 1,257,710 |
Commitments and contingencies | ||
Stockholders' equity: | ||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2018 and 2017 | 0 | 0 |
Common stock, $0.01 par value, 450,000,000 shares authorized and 233,936,358 and 242,521,143 issued and outstanding as of December 31, 2018 and 2017, respectively | 2,339 | 2,425 |
Additional paid-in capital | 2,375,286 | 2,432,262 |
Accumulated deficit | (1,203,395) | (1,669,108) |
Total stockholders' equity | 1,174,230 | 765,579 |
Total liabilities and stockholders' equity | $ 2,420,305 | $ 2,023,289 |
Consolidated balance sheets (Pa
Consolidated balance sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock authorized (in shares) | 50,000,000 | 50,000,000 |
Preferred stock issued (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock authorized (in shares) | 450,000,000 | 450,000,000 |
Common stock issued (in shares) | 233,936,358 | 242,521,143 |
Common stock outstanding (in shares) | 233,936,358 | 242,521,143 |
Consolidated statements of oper
Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues: | |||
Total revenues | $ 1,105,775 | $ 822,162 | $ 597,378 |
Costs and expenses: | |||
Lease operating expenses | 91,289 | 75,049 | 75,327 |
Production and ad valorem taxes | 49,457 | 37,802 | 28,586 |
General and administrative | 96,138 | 96,312 | 91,756 |
Depletion, depreciation and amortization | 212,677 | 158,389 | 148,339 |
Impairment expense | 0 | 0 | 162,027 |
Other operating expenses | 4,472 | 4,931 | 5,692 |
Total costs and expenses | 757,283 | 572,490 | 685,340 |
Operating income (loss) | 348,492 | 249,672 | (87,962) |
Non-operating income (expense): | |||
Gain (loss) on derivatives, net | 42,984 | 350 | (87,425) |
Interest expense | (57,904) | (89,377) | (93,298) |
Other income, net | 1,070 | 805 | 175 |
Income from equity method investee (see Note 4.c) | 0 | 8,485 | 9,403 |
Gain on sale of investment in equity method investee (see Note 4.c) | 0 | 405,906 | 0 |
Loss on early redemption of debt | 0 | (23,761) | 0 |
Loss on disposal of assets, net | (5,798) | (1,306) | (790) |
Write-off of debt issuance costs | 0 | 0 | (842) |
Non-operating income (expense), net | (19,648) | 301,102 | (172,777) |
Income (loss) before income taxes | 328,844 | 550,774 | (260,739) |
Income tax benefit (expense): | |||
Current | 807 | (1,800) | 0 |
Deferred | (5,056) | 0 | 0 |
Total income tax expense | (4,249) | (1,800) | 0 |
Net income (loss) | $ 324,595 | $ 548,974 | $ (260,739) |
Net income (loss) per common share: | |||
Basic (in dollars per share) | $ 1.40 | $ 2.30 | $ (1.16) |
Diluted (in dollars per share) | $ 1.39 | $ 2.29 | $ (1.16) |
Weighted-average common shares outstanding: | |||
Basic (in shares) | 232,339 | 239,096 | 225,512 |
Diluted (in shares) | 233,172 | 240,122 | 225,512 |
Oil sales | |||
Revenues: | |||
Total revenues | $ 605,197 | $ 445,012 | $ 318,466 |
NGL sales | |||
Revenues: | |||
Total revenues | 149,843 | 101,438 | 56,982 |
Natural gas sales | |||
Revenues: | |||
Total revenues | 53,490 | 75,057 | 51,037 |
Midstream service revenues | |||
Revenues: | |||
Total revenues | 8,987 | 10,517 | 8,342 |
Costs and expenses: | |||
Costs of purchased oil | 2,872 | 4,099 | 4,077 |
Transportation and marketing expenses | |||
Costs and expenses: | |||
Costs of purchased oil | 11,704 | 0 | 0 |
Sales of purchased oil | |||
Revenues: | |||
Total revenues | 288,258 | 190,138 | 162,551 |
Costs and expenses: | |||
Costs of purchased oil | $ 288,674 | $ 195,908 | $ 169,536 |
Consolidated statements of stoc
Consolidated statements of stockholders' equity - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Additional paid-in capital | Treasury Stock (at cost) | Accumulated deficit |
Balance at beginning of year (in shares) at Dec. 31, 2015 | 213,808 | 0 | |||
Balance at beginning of year at Dec. 31, 2015 | $ 131,447 | $ 2,138 | $ 2,086,652 | $ 0 | $ (1,957,343) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (in shares) | 2,982 | ||||
Restricted stock awards | $ 30 | (30) | |||
Restricted stock forfeitures (in shares) | (457) | ||||
Restricted stock forfeitures | $ (5) | 5 | |||
Vested stock exchanged for tax withholding (in shares) | 296 | ||||
Vested stock exchanged for tax withholding | (1,635) | $ (1,635) | |||
Retirement of treasury stock (in shares) | (296) | (296) | |||
Retirement of treasury stock | $ (3) | (1,632) | $ 1,635 | ||
Exercise of stock options (in shares) | 17 | ||||
Exercise of stock options | 208 | $ 0 | 208 | ||
Equity issuance, net of offering costs (in shares) | 25,875 | ||||
Equity issuances, net of offering costs | 276,052 | $ 259 | 275,793 | ||
Stock-based compensation | 35,240 | 35,240 | |||
Net income (loss) | (260,739) | (260,739) | |||
Balance at end of year (in shares) at Dec. 31, 2016 | 241,929 | 0 | |||
Balance at end of year at Dec. 31, 2016 | 180,573 | $ 2,419 | 2,396,236 | $ 0 | (2,218,082) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (in shares) | 1,237 | ||||
Restricted stock awards | $ 12 | (12) | |||
Restricted stock forfeitures (in shares) | (302) | ||||
Restricted stock forfeitures | $ (3) | 3 | |||
Vested stock exchanged for tax withholding (in shares) | 547 | ||||
Vested stock exchanged for tax withholding | (7,662) | $ (7,662) | |||
Retirement of treasury stock (in shares) | (547) | (547) | |||
Retirement of treasury stock | $ (5) | (7,657) | $ 7,662 | ||
Exercise of stock options (in shares) | 54 | ||||
Exercise of stock options | 397 | 397 | |||
Stock-based compensation | 43,297 | 43,297 | |||
Performance share conversion (in shares) | 150 | ||||
Performance share conversion | $ 2 | (2) | |||
Net income (loss) | 548,974 | 548,974 | |||
Balance at end of year (in shares) at Dec. 31, 2017 | 242,521 | 0 | |||
Balance at end of year at Dec. 31, 2017 | 765,579 | $ 2,425 | 2,432,262 | $ 0 | (1,669,108) |
Increase (Decrease) in Stockholders' Equity | |||||
Adjustment to the beginning balance of accumulated deficit upon adoption of ASC 606 (see Note 5.a) | Accounting Standards Update 2014-09 | 141,118 | 141,118 | |||
Restricted stock awards (in shares) | 3,328 | ||||
Restricted stock awards | $ 33 | (33) | |||
Restricted stock forfeitures (in shares) | (367) | ||||
Restricted stock forfeitures | $ (4) | 4 | |||
Share repurchases (in shares) | 11,049 | ||||
Share repurchases | (97,055) | $ (97,055) | |||
Vested stock exchanged for tax withholding (in shares) | 518 | ||||
Vested stock exchanged for tax withholding | (4,418) | $ (4,418) | |||
Retirement of treasury stock (in shares) | (11,567) | (11,567) | |||
Retirement of treasury stock | $ (115) | (101,358) | $ 101,473 | ||
Exercise of stock options (in shares) | 21 | ||||
Exercise of stock options | 86 | 86 | |||
Stock-based compensation | 44,325 | 44,325 | |||
Net income (loss) | 324,595 | 324,595 | |||
Balance at end of year (in shares) at Dec. 31, 2018 | 233,936 | 0 | |||
Balance at end of year at Dec. 31, 2018 | $ 1,174,230 | $ 2,339 | $ 2,375,286 | $ 0 | $ (1,203,395) |
Consolidated statements of cash
Consolidated statements of cash flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 324,595 | $ 548,974 | $ (260,739) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Deferred income tax expense | 5,056 | 0 | 0 |
Depletion, depreciation and amortization | 212,677 | 158,389 | 148,339 |
Impairment expense | 0 | 0 | 162,027 |
Gain on sale of investment in equity method investee (see Note 4.c) | 0 | (405,906) | 0 |
Loss on early redemption of debt | 0 | 23,761 | 0 |
Non-cash stock-based compensation, net | 36,396 | 35,734 | 29,229 |
Mark-to-market on derivatives: | |||
(Gain) loss on derivatives, net | (42,984) | (350) | 87,425 |
Settlements received for matured derivatives, net | 6,090 | 37,583 | 195,281 |
Settlements received for early terminations of derivatives, net | 0 | 4,234 | 80,000 |
Change in net present value of derivative deferred premiums | 694 | 394 | 232 |
Premiums paid for derivatives | (20,335) | (25,853) | (89,669) |
Amortization of debt issuance costs | 3,331 | 4,086 | 4,279 |
Write-off of debt issuance costs | 0 | 0 | 842 |
Income from equity method investee (see Note 4.c) | 0 | (8,485) | (9,403) |
Cash settlement of performance unit awards | 0 | 0 | (6,394) |
Other, net | 11,857 | 6,067 | 4,596 |
Decrease (increase) in accounts receivable | 4,669 | (12,124) | 832 |
Increase in other current assets | (1,865) | (3,461) | (1,373) |
Decrease (increase) in other noncurrent assets | 124 | (4,774) | 360 |
Increase in accounts payable and accrued liabilities | 11,163 | 9,137 | 5,432 |
Increase (decrease) in undistributed revenues and royalties | 10,989 | 11,014 | (7,735) |
(Decrease) increase in other current liabilities | (23,799) | (2,327) | 13,153 |
(Decrease) increase in other noncurrent liabilities | (854) | 8,821 | (419) |
Net cash provided by operating activities | 537,804 | 384,914 | 356,295 |
Cash flows from investing activities: | |||
Deposit received for potential sale of oil and natural gas properties | 0 | 0 | 3,000 |
Deposit utilized for sale of oil and natural gas properties | 0 | (3,000) | 0 |
Acquisitions of oil and natural gas properties | (17,538) | 0 | (124,660) |
Capital expenditures: | |||
Oil and natural gas properties | (673,584) | (538,122) | (360,679) |
Midstream service assets | (6,784) | (20,887) | (5,240) |
Other fixed assets | (7,308) | (4,905) | (7,611) |
Investment in equity method investee (see Note 4.c) | 0 | (31,808) | (69,609) |
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) | 1,655 | 829,615 | 0 |
Proceeds from dispositions of capital assets, net of selling costs | 12,603 | 64,157 | 397 |
Net cash (used in) provided by investing activities | (690,956) | 295,050 | (564,402) |
Cash flows from financing activities: | |||
Borrowings on Senior Secured Credit Facility | 210,000 | 190,000 | 239,682 |
Payments on Senior Secured Credit Facility | (20,000) | (260,000) | (304,682) |
Early redemption of debt | 0 | (518,480) | 0 |
Proceeds from issuance of common stock, net of offering costs | 0 | 0 | 276,052 |
Share repurchases | (97,055) | 0 | 0 |
Vested stock exchanged for tax withholding | (4,418) | (7,662) | (1,635) |
Proceeds from exercise of stock options | 86 | 397 | 208 |
Payments for debt issuance costs | (2,469) | (4,732) | 0 |
Net cash provided by (used in) financing activities | 86,144 | (600,477) | 209,625 |
Net (decrease) increase in cash and cash equivalents | (67,008) | 79,487 | 1,518 |
Cash and cash equivalents, beginning of period | 112,159 | 32,672 | 31,154 |
Cash and cash equivalents, end of period | $ 45,151 | $ 112,159 | $ 32,672 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Organization Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and midstream and marketing services, primarily in the Permian Basin of West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate. The Company has identified one |
Basis of presentation and signi
Basis of presentation and significant accounting policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Basis of presentation and significant accounting policies | Basis of presentation and significant accounting policies a. Basis of presentation The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income is included in the consolidated statements of operations. See Notes 4.c and 5.a for additional discussion of the Company's former equity method investment. b. Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas , (ii) future cash flows from oil and natural gas properties , (iii) depletion, depreciation and amortization , (iv) impairments , (v) asset retirement obligations , (vi) stock-based compensation , (vii) deferred income taxes , (viii) fair value of assets acquired and liabilities assumed in an acquisition , (ix) fair values of derivatives and deferred premiums and (x) contingent liabilities . As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. c. Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows. d. Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 13 for discussion regarding the Company's exposure to credit risk. e. Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and greater than a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote. Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Oil, NGL and natural gas sales $ 44,958 $ 67,116 Joint operations, net (1) 16,772 8,780 Sales of purchased oil and other products 10,244 19,504 Other 22,347 5,245 Total accounts receivable $ 94,321 $ 100,645 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million as of December 31, 2018 and 2017 . As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of revenues. f. Derivatives Derivatives are recorded at fair value and are presented on a net basis on the "Derivatives" line items on the consolidated balance sheets as assets and/or liabilities. The Company presents the fair value of derivatives net by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. The Company's derivatives were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 9 and 10.a for additional discussion of derivatives and the fair value measurement of derivatives, respectively. g. Other current liabilities and noncurrent liabilities Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Accrued interest payable $ 18,281 $ 18,013 Accrued compensation and benefits 13,317 21,287 Deferred gain on sale of equity method investment (1) — 20,144 Other accrued liabilities 13,188 16,111 Total other current liabilities $ 44,786 $ 75,555 _____________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion regarding the Company's former equity method investee. Other noncurrent liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Deferred gain on sale of equity method investment (1) $ — $ 120,974 Other accrued liabilities 8,587 13,116 Total other noncurrent liabilities $ 8,587 $ 134,090 _____________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion regarding the Company's former equity method investee. h. Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties . Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. See Note 6 Inventory The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is the minimum volume of product in a pipeline system that enables the system to operate, and is generally not available to be withdrawn from the pipeline until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in each of the "Other current assets" and "Other noncurrent assets, net" line items on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is determined utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the year ended December 31, 2016, the Company recorded impairment expense of $1.0 million for materials and supplies inventory. No such inventory impairments were recorded for the years ended December 31, 2018 or 2017. j. Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. See Note 7.e for additional discussion of the Company's debt issuance costs. k. Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience and estimated remaining life per well, (ii) estimated removal and/or remediation costs for midstream service assets and estimated remaining life of midstream service assets, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory and environmental matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable. The following table reconciles the Company's asset retirement obligation liability: For the years ended December 31, (in thousands) 2018 2017 Liability at beginning of year $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 995 616 Accretion expense 4,472 3,791 Liabilities settled upon plugging and abandonment (2,848 ) (408 ) Liabilities removed due to sale of property (1,243 ) (871 ) Revision of estimates — 171 Liability at end of year $ 56,882 $ 55,506 l. Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company carries its derivatives at fair value. See Note 10.a for details regarding the fair value of the Company's derivatives. See Note 10.c for fair value disclosures related to the Company's debt obligations. m. Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock-based awards at the employees' election. n. Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated from oil throughput fees and services provided to third parties for (i) oil and natural gas gathering and transportation systems and related facilities, (ii) gas lift, rig fuel and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure (collectively, "Midstream Services"), and are recognized over time as the customer benefits from these services when provided. See Note 5.b for additional discussion on revenue recognition. o. Fees received for the operation of jointly-owned oil and natural gas properties The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses. The following table presents the fees received for the operation of jointly-owned oil and natural gas properties: For the years ended December 31, (in thousands) 2018 2017 2016 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,507 $ 2,549 $ 2,477 p. Compensation awards Stock-based compensation expense, net, is included in the "General and administrative" line item in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values, less an expected forfeiture rate, of the performance share awards with market criteria and, in prior periods, the performance unit awards. For performance share awards with performance criteria, the grant-date fair value is equal to the Company's stock price on the grant date, less an expected forfeiture rate, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the performance period. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. See Note 8.c for further discussion regarding the restricted stock awards, stock option awards and performance share awards. q. Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2018 or 2017 . See Note 12 for additional information regarding the Company's income taxes. r. Non-cash investing and supplemental cash flow information The following table presents non-cash investing and supplemental cash flow information: For the years ended December 31, (in thousands) 2018 2017 2016 Non-cash investing information: (Decrease) increase in accrued capital expenditures $ (52,746 ) $ 51,876 $ (31,027 ) Change in accrued capital contribution to equity method investee (1) $ — $ — $ (27,583 ) Capitalized stock-based compensation $ 7,929 $ 7,563 $ 6,011 Capitalized asset retirement cost $ 995 $ 787 $ 3,660 Supplemental cash flow information: Cash paid for interest, net of $988, $1,152 and $294 of capitalized interest, respectively (2) $ 53,981 $ 91,548 $ 89,432 Cash paid for income taxes (3) $ 735 $ 5,500 $ — ______________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion of the Company's former equity method investee. (2) See Note 7.f for additional discussion of the Company's interest expense. (3) See Note 12 |
Recently issued or adopted acco
Recently issued or adopted accounting pronouncements | 12 Months Ended |
Dec. 31, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recently issued or adopted accounting pronouncements | Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs and a final rule issued by the SEC listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the year ended December 31, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606 , Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption . ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 5 for further discussion of the ASC 606 adoption impact on the Company's consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption was permitted. The primary effect on the Company's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has a team, including third-party consultants, to implement the standard and has implemented the software that will be used to track and account for lease activity. As of December 31, 2018, the Company anticipates that the adoption and implementation of ASC 842 will result in approximately a $25.0 million to $40.0 million increase in assets and liabilities on the consolidated balance sheet in 2019, but will not result in a material impact to the consolidated statement of operations. This estimate may vary based on any additional contracts entered into subsequent to December 31, 2018. The Company has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. The transition will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted (January 1, 2019). The Company will utilize the transition package of expedients to leases that commenced before the effective date. The Company expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. See Note 4.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU. d. Fair value measurements In August 2018, the FASB issued new guidance in ASC 820, Fair Value Measurement , to modify disclosure requirements. Of the amendments in the ASU, the below items affected the Company's fair value measurement disclosures in Note 10 . Removed disclosure requirements that should be applied retrospectively to all periods presented are: (i) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the policy for timing of transfers between levels and (iii) the valuation processes for Level 3 fair value measurements. A modified disclosure requirement that should be applied prospectively is to clarify that the measurement uncertainty disclosure communicates information about the uncertainty in measurement as of the reporting date. A new disclosure requirement that should be applied prospectively is to disclose the range and weighted-average of significant unobservable inputs used to develop Level 3 fair value measurements. The Company has elected to early adopt this guidance upon the issuance of the ASU and has modified its disclosures accordingly. e. SEC disclosure update and simplification In August 2018, the SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification |
Acquisitions and divestitures
Acquisitions and divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisitions and divestitures | Acquisitions and divestitures a. 2018 Acquisitions of evaluated and unevaluated oil and natural gas properties During the year ended December 31, 2018, through multiple transactions, the Company acquired 966 net acres of additional leasehold and working interests in 48 producing wells in Glasscock County, Texas for an aggregate purchase price of $17.5 million , net of post-closing adjustments. These acquisitions were accounted for as asset acquisitions. b. 2018 Divestitures of evaluated and unevaluated oil and natural gas properties and midstream service assets During the year ended December 31, 2018, through multiple transactions, the Company completed the sale of 3,070 net acres and working interests in 24 producing wells and associated midstream service assets in Glasscock County and Howard County in Texas to third-party buyers for an aggregate sales price of $12.0 million , net of post-closing adjustments. Of this amount, $11.5 million , net of post-closing adjustments, was recorded as adjustments to oil and natural gas properties pursuant to the rules governing full cost accounting. A loss of $1.0 million from the sale of the associated midstream service assets was included in the line item "Loss on disposal of assets, net" in the consolidated statements of operations. Effective at the closings, the operations and cash flows of these oil and natural gas properties and midstream service assets were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. These divestitures did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. c. 2017 Medallion sale Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted fo r under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the consolidated statements of operations on the "Income from equity method investee" line item. On October 30, 2017, LMS , together with Medallion Midstream Holdings, LLC ("MMH") , which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group ("EMG") , completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP") , for cash consideration of $ 1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $ 829.6 million , before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million for total net cash proceeds before taxes of $831.3 million . The proceeds were used to pay down borrowings on the Senior Secured Credit Facility in full, to redeem the May 2022 Notes (defined below) and for working capital purposes . The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid. The Medallion Sale does not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion under which LMS receives firm transportation of the Company's crude oil production from Reagan County and Glasscock County in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018. The deferred gain is included in the consolidated balance sheets in each of the "Other current liabilities" and "Other noncurrent liabilities" line items as of December 31, 2017. See Note 5.a for discussion of the impact to the deferred gain upon the adoption of ASC 606. d. 2017 Divestiture of evaluated and unevaluated oil and natural gas properties In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million , net of working capital and post-closing adjustments. A significant portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. e. 2016 Acquisitions of evaluated and unevaluated oil and natural gas properties The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 10.a . During the year ended December 31, 2016, the Company acquired 9,200 net acres of additional leasehold and working interests in 81 producing vertical wells in western Glasscock County and Reagan County which included production of approximately 300 net barrels of oil equivalent ("BOE") per day within the Company's core development area for an aggregate purchase price of $ 124.7 million subject to customary closing adjustments. The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723 f. Exchange of evaluated oil and natural gas properties |
Revenue recognition
Revenue recognition | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue recognition | Revenue recognition a. Impact of ASC 606 adoption Upon adoption of ASC 606 on January 1, 2018, for the year ended December 31, 2018 , the Company reclassified certain firm transportation payments on excess pipeline capacity and other contractual penalties, historically included in the "Other operating expenses" line item in the consolidated statements of operations, and netted them with the revenue stream from which they derive as these payments to customers do not relate to the provision of a distinct good or service to the customer. In addition, there was an impact upon adoption related to the treatment of the gain on the Medallion Sale discussed below. The impact of the adoption of ASC 606 on the results of operations for the year ended December 31, 2018 is as follows: (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 607,870 $ 605,197 $ (2,673 ) NGL sales $ 150,822 $ 149,843 $ (979 ) Natural gas sales $ 54,511 $ 53,490 $ (1,021 ) Costs and expenses: Other operating expenses $ 9,145 $ 4,472 $ (4,673 ) Net income $ 324,595 $ 324,595 $ — At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. See Note 4.c for further discussion of the Medallion Sale and the TA. Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to GIP, (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the beginning balance of accumulated deficit, presented in the consolidated statements of stockholders' equity , in accordance with the modified retrospective approach of adoption. See Note 12 for discussion of the income tax effect of the adoption of ASC 606. b. Revenue recognition See Note 2.n for a summary of revenue recognition policies, a more detailed discussion of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. Under certain of its customer contracts, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream service revenues Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2018 or 2017. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less . For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the year ended December 31, 2018 |
Property and equipment
Property and equipment | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property and equipment | Note 6 — Property and equipment a. Oil and natural gas properties The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are evaluated. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Oil and natural gas properties consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Oil and natural gas properties, net $ 2,029,571 $ 1,589,339 The following table presents depletion and depletion per BOE sold of the Company's evaluated oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands except per BOE data) 2018 2017 2016 Depletion of evaluated oil and natural gas properties $ 196,458 $ 143,592 $ 134,105 Depletion per BOE sold $ 7.90 $ 6.75 $ 7.39 The Company excludes the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties . The Company capitalizes a portion of its interest costs to its unevaluated properties . Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. See Note 18 for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission (" SEC ") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials (" Benchmark Prices "). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead (" Realized Prices "). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2018 December 31, 2017 December 31, 2016 Benchmark Prices: Oil ($/Bbl) $ 62.04 $ 47.79 $ 39.25 NGL ($/Bbl) (1) $ 31.46 $ 26.13 $ 18.24 Natural gas ($/MMBtu) $ 1.76 $ 2.63 $ 2.33 Realized Prices: Oil ($/Bbl) $ 59.29 $ 46.34 $ 37.44 NGL ($/Bbl) $ 21.42 $ 18.45 $ 11.72 Natural gas ($/Mcf) $ 1.38 $ 2.06 $ 1.78 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. Full cost ceiling impairment expense for the year ended December 31, 2016 was $161.1 million . This amount is included in the "Impairment expense" line item in the consolidated statements of operations. There were no full cost ceiling impairments recorded during the years ended December 31, 2018 or 2017. See Note 2.h for discussion of the Company's significant accounting policy for oil and natural gas properties. The following table presents capitalized employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Capitalized employee-related costs $ 25,372 $ 25,553 $ 19,222 b. Midstream service assets Midstream service assets, which consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost, are recorded at cost, net of impairment. See Note 2.k for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation expense for midstream service assets was $10.1 million , $8.9 million and $8.3 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Midstream service assets $ 172,308 $ 171,427 Less accumulated depreciation and impairment (42,063 ) (33,102 ) Total midstream service assets, net $ 130,245 $ 138,325 c. Other fixed assets Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation and amortization expense for other fixed assets was $6.1 million , $5.9 million , and $5.9 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Vehicles $ 10,660 $ 9,661 Computer hardware and software 9,222 11,696 Buildings 7,804 7,618 Leasehold improvements 7,608 7,590 Aircraft 6,402 6,402 Other 3,735 5,990 Depreciable total 45,431 48,957 Less accumulated depreciation and amortization (23,871 ) (23,150 ) Depreciable total, net 21,560 25,807 Land 18,259 14,914 Total other fixed assets, net $ 39,819 $ 40,721 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Debt a. March 2023 Notes On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes") , and entered into an Indenture (the "Base Indenture"), as supplemented by the Supplemental Indenture (the "Supplemental Indenture" and, together with the Base Indenture, the "Indenture"), among Laredo, LMS and GCM, as guarantors, and Wells Fargo Bank, National Association, as trustee. The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the underwriters' discount and the estimated outstanding offering expenses. In April 2015, the Company used the net proceeds of the offering to fund a portion of the Company's redemption of previously issued senior unsecured notes. The March 2023 Notes became callable by the Company on March 15, 2018. The Company may redeem, at its option, all or part of the March 2023 Notes at any time on or after March 15, 2018, at a price of 104.688% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption. b. January 2022 Notes On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes") , and entered into an Indenture (the "2014 Indenture") among Laredo, LMS as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases. The January 2022 Notes were issued pursuant to the 2014 Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The January 2022 Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers' discount and the estimated outstanding offering expenses. The Company used the net proceeds of the offering for general working capital purposes. The January 2022 Notes became callable by the Company on January 15, 2017. The Company may redeem, at its option, all or part of the January 2022 Notes at any time on and after January 15, 2019, at a price of 101.406% of face value with call premiums declining to 100% of face value on January 15, 2020 and thereafter plus accrued and unpaid interest to the date of redemption. c. May 2022 Notes On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes were due to mature on May 1, 2022 and bore an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases. On November 29, 2017 (the " May 2022 Notes Redemption Date ") , utilizing a portion of the proceeds from the Medallion Sale, the entire $500.0 million outstanding principal amount of the May 2022 Notes was redeemed at a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest up to, but not including, the May 2022 Notes Redemption Date. The Company recognized a loss on extinguishment of $23.8 million related to the difference between the redemption price and the net carrying amount of the extinguished May 2022 Notes. d. Senior Secured Credit Facility The Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility") matures on April 19, 2023 , provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of December 31, 2018 , the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion , a borrowing base of $1.3 billion and an aggregate elected commitment of $1.2 billion , with $190.0 million outstanding and was subject to an interest rate of 3.75% . The borrowing base is subject to a semi-annual redetermination occurring by May 1 and November 1 of each year based on the lenders' evaluation of the Company's oil, NGL and natural gas reserves . As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 0.25% to 1.25% , based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility; and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one -month, two -month, three -month, six -month or, to the extent available, 12 -month interest periods (and in the case of six -month and 12 -month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate plus an applicable margin, which ranges from 1.25% to 2.25% , based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility . Laredo is required to pay a quarterly commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5% , based on the ratio of outstanding revolving credit to the aggregate elected commitment under the Senior Secured Credit Facility. The Senior Secured Credit Facility is secured by a first-priority lien on Laredo and the Guarantors' assets and stock, including oil and natural gas properties, constituting at least 85% of the present value of the Company's proved reserves . Further, the Company is subject to various financial and non-financial covenants on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00 . As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions . Additionally, the Company must maintain as of the last day of each calendar quarter a ratio of (a) its total debt (excluding reimbursement obligations in respect of undrawn letters of credit, if no loans are outstanding under the Senior Secured Credit Facility) minus a maximum of $50 million of unrestricted and unencumbered cash and cash equivalents, to (b) "Consolidated EBITDAX," as defined in the Senior Secured Credit Facility, for any period of four consecutive calendar quarters ending on the last day of such applicable calendar quarter of not greater than 4.25 to 1.00 . Prior to the Company entering into the Fifth Amended and Restated Credit Agreement as of May 2, 2017, at the end of each calendar quarter, the Company was required to maintain a ratio of (I) its consolidated net income (loss) (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus other non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of consolidated net interest expense plus letter of credit fees of not less than 2.50 to 1.00 , in each case for the four quarters then ending. The Company was in compliance with these covenants for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million . As of December 31, 2018 , the Company had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility . No letters of credit were outstanding as of December 31, 2017 . e. Debt issuance costs The Company capitalized $2.5 million of debt issuance costs during the year ended December 31, 2018 as a result of entering into the Third Amendment to the Senior Secured Credit Facility. The Company capitalized $4.7 million of debt issuance costs during the year ended December 31, 2017 as a result of entering into the Fifth Amended and Restated Credit Agreement. No debt issuance costs were capitalized during the year ended December 31, 2016. The Company wrote-off $5.3 million of debt issuance costs during the year ended December 31, 2017 as a result of the early redemption of the May 2022 Notes, which are included in the "Loss on early redemption of debt" line item in the consolidated statements of operations. The Company wrote-off $0.8 million of debt issuance costs during the year ended December 31, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the "Write-off of debt issuance costs" line item in the consolidated statements of operations. No debt issuance costs were written off during the year ended December 31, 2018. The Company had total debt issuance costs of $13.3 million and $14.2 million , net of accumulated amortization of $24.2 million and $20.8 million , as of December 31, 2018 and 2017 , respectively. Debt issuance costs related to the Company's senior unsecured notes are included in the "Long-term debt, net" line item on the consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in the "Other noncurrent assets, net" line item on the consolidated balance sheets. See Note 7.g for additional discussion of debt issuance costs. The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2018 2019 $ 3,385 2020 3,385 2021 3,385 2022 2,490 2023 669 Total $ 13,314 f. Interest expense The following table presents amounts that have been incurred and charged to interest expense: For the years ended December 31, (in thousands) 2018 2017 2016 Cash payments for interest $ 54,969 $ 92,700 $ 89,726 Amortization of debt issuance costs and other adjustments 3,655 3,968 3,922 Change in accrued interest 268 (6,139 ) (56 ) Interest costs incurred 58,892 90,529 93,592 Less capitalized interest (988 ) (1,152 ) (294 ) Total interest expense $ 57,904 $ 89,377 $ 93,298 g. Long-term debt, net The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,010 ) $ 446,990 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,354 ) 346,646 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 190,000 — 190,000 — — — Total $ 990,000 $ (6,364 ) $ 983,636 $ 800,000 $ (8,145 ) $ 791,855 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.0 million and $6.0 million as of December 31, 2018 and 2017 |
Stockholders' equity, stock-bas
Stockholders' equity, stock-based compensation and defined contribution plan | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stockholders' equity, stock-based compensation and defined contribution plan | Stockholders' equity, stock-based compensation and defined contribution plan a. Share repurchase program In February 2018, the Company's board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. During the year ended December 31, 2018, the Company repurchased 11,048,742 shares of common stock at a weighted-average price of $8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. b. Equity offerings On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of $136.3 million , after underwriting discounts, commissions and offering expenses. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of Laredo's common stock, which resulted in net proceeds to the Company of $20.5 million , after underwriting discounts, commissions and offering expenses. On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million , after underwriting discounts, commissions and offering expenses. There were no offerings of Laredo's stock during the years ended December 31, 2018 or 2017. c. Stock-based compensation The Company's Long-Term Incentive Plan (the "LTIP") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules that mainly include (i) 33% , 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately on the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vested fully on the first anniversary of the grant date. The following table reflects the restricted stock award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average grant-date fair value (per award) Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 Granted 1,237 $ 13.87 Forfeited (302 ) $ 12.87 Vested (1,644 ) $ 13.75 Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,328 $ 8.34 Forfeited (367 ) $ 10.13 Vested (1) (1,934 ) $ 11.92 Outstanding as of December 31, 2018 4,196 $ 9.91 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2018 was $16.6 million . The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of December 31, 2018 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $20.5 million . Such cost is expected to be recognized over a weighted-average period of 1.79 years. Stock option awards Stock option awards granted under the LTIP vest and become exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Granted 391 $ 14.12 Exercised (54 ) $ 7.43 Expired or canceled (60 ) $ 20.41 Outstanding as of December 31, 2017 2,647 $ 12.70 7.12 Exercised (1) (21 ) $ 4.10 Expired or canceled (53 ) $ 18.92 Forfeited (40 ) $ 9.23 Outstanding as of December 31, 2018 2,533 $ 12.69 5.99 Vested and exercisable as of December 31, 2018 (2) 1,697 $ 14.75 5.32 Expected to vest as of December 31, 2018 (3) 836 $ 8.53 7.34 _____________________________________________________________________________ (1) The total intrinsic value of exercised stock option awards for the year ended December 31, 2018 was $0.1 million . (2) The vested and exercisable stock option awards as of December 31, 2018 had no aggregate intrinsic value. (3) The stock option awards expected to vest as of December 31, 2018 had no an aggregate intrinsic value. The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four -year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of December 31, 2018 , unrecognized stock-based compensation related to stock option awards expected to vest was $3.9 million . Such cost is expected to be recognized over a weighted-average period of 1.51 years. The assumptions used to estimate the fair value of stock option awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.14 % 1.58 % 1.44 % Expected option life (2) 6.25 years 6.25 years 6.25 years Expected volatility (3) 60.84 % 61.94 % 61.34 % Fair value per stock option award $ 8.22 $ 9.75 $ 4.44 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own volatility in order to develop the expected volatility. In accordance with the LTIP and stock option agreement, the stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the stock option award will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause. Performance share awards Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include the RTSR Performance Percentage (as defined below), the ATSR Appreciation (as defined below) and the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and the associated expense is recognized on a straight-line basis over the three -year requisite service period of the awards. For portions of awards with performance criteria, which is the ROACE Percentage (as defined below), the grant-date fair value is equal to the Company's stock price on the grant date, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the three-year performance period. Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain market and performance criteria. The following table reflects the performance share award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share Weighted-average Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Outstanding as of December 31, 2016 2,325 $ 18.35 Granted 696 $ 18.96 Forfeited (76 ) $ 18.12 Vested (1) (200 ) $ 28.56 Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (2) 1,389 $ 9.22 Forfeited (244 ) $ 14.93 Vested (3) (454 ) $ 16.23 Outstanding as of December 31, 2018 3,436 $ 13.74 _____________________________________________________________________________ (1) These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and market criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017. (2) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $9.22 per unit grant-date fair value consists of a (i) $10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. As of December 31, 2018, the estimated probability of how many shares will be earned at the end of the three-year performance period was estimated to be 50% , resulting in expense of $4.18 per unit for the (.50) ROACE Factor for the year ended December 31, 2018. The grant-date fair value of the market criteria portion of the award is locked in at $10.08 per unit for the combined (.25) RTSR Factor and (.25) ATSR Factor and, as a result, the expense for the total award is $7.13 per unit for the year ended December 31, 2018. (3) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the 36th percentile of its peer group for relative TSR. As such, the units were not converted into the Company's common stock during the first quarter of 2018. The performance share awards granted on April 1, 2016 and May 25, 2016 had a performance period of January 1, 2016 to December 31, 2018 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the ninth percentile of its peer group for relative TSR. As such, the 1,502,868 units were not converted into the Company's common stock during the first quarter of 2019. As of December 31, 2018 , unrecognized stock-based compensation related to the performance share awards expected to vest was $11.9 million . Such cost is expected to be recognized over a weighted-average period of 1.59 years. The assumptions used to estimate the fair value of the performance share awards granted as of the dates presented are as follows: February 16, 2018 (3) February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.34 % 1.44 % 1.02 % 0.87 % Dividend yield — % — % — % — % Expected volatility (2) 65.49 % 74.00 % 74.73 % 71.54 % Closing stock price on grant date $ 8.36 $ 14.12 $ 12.36 $ 7.71 Fair value per performance share award $ 10.08 $ 18.96 $ 17.86 $ 9.83 _____________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) These are the assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted. The market criteria portion of the performance share award represents 50% of each of the amount of stock potentially payable, if any, and the grant-date fair value of the award. Stock-based compensation expense The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Restricted stock award compensation $ 25,271 $ 22,223 $ 21,609 Stock option award compensation 3,862 4,762 4,519 Performance share award compensation 15,192 16,312 9,112 Total stock-based compensation, gross 44,325 43,297 35,240 Less amounts capitalized in evaluated oil and natural gas properties (7,929 ) (7,563 ) (6,011 ) Total stock-based compensation, net $ 36,396 $ 35,734 $ 29,229 Performance unit awards The performance unit awards issued to management in 2013 were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the fair values of these awards at the grant date and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation was based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies defined in each respective award agreement. The liability and related compensation expense of these awards for each period was recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service had already been provided. The 44,481 settled 2013 performance unit awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. d. Defined contribution plan The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt. The following table presents the cost recognized for the Company's defined contribution plan for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Contributions $ 2,156 $ 1,929 $ 1,789 |
Net income (loss) per common sh
Net income (loss) per common share | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Net income (loss) per common share | Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. The dilutive effects of these awards were calculated utilizing the treasury stock method. See Note 8.c for additional discussion on these awards. The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2018 2017 2016 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 324,595 $ 548,974 $ (260,739 ) Weighted-average common shares outstanding (denominator): Basic (1) 232,339 239,096 225,512 Non-vested restricted stock awards (2) 813 880 — Outstanding stock option awards (3) 20 122 — Non-vested performance share awards (4) — 24 — Diluted 233,172 240,122 225,512 Net income (loss) per common share: Basic $ 1.40 $ 2.30 $ (1.16 ) Diluted $ 1.39 $ 2.29 $ (1.16 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share was computed taking into account share repurchases that occurred during the year ended December 31, 2018 and equity offerings that occurred during the year ended December 31, 2016. See Notes 8.a and 8.b for additional discussion of the Company's share repurchase program and equity offerings, respectively. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these non-vested restricted stock awards would be anti-dilutive mainly due to the grant-date fair value per common share for the awards being greater than the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 8.c |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives Due to the inherent volatility in oil, NGL and natural gas prices, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in derivative transactions, such as puts, swaps, collars, basis swaps and, in the past, call spreads to hedge price risk associated with a portion of the Company's anticipated production. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations . The following discussion regarding the Company's transaction types and settlement indexes pertain to the years ended December 31, 2018 , 2017 and 2016 as well as the open positions as of December 31, 2018 . Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be paid at inception or deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual month in the contract period, the put option expires with no settlement for that particular month, except with regard to the deferred premium, if any. Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. Each collar transaction has an established price floor and ceiling. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is at or between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume. Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price and less than or equal to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Other than the oil basis swaps, the Company's oil derivatives are settled based on the month's arithmetic average of the daily settlement prices for the NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract . The oil basis swaps are settled based on the differential between the basis swaps' fixed differential price as compared to the differential between the arithmetic average of each day's index prices for the first nearby month on the pricing dates in each calculation period with the index prices being either (i) the Argus Americas Crude's West Texas Intermediate ("WTI") Midland-weighted average and the Cushing-based NYMEX West Texas Intermediate Light Sweet Crude Oil Futures Contract, (ii) the Argus Americas Crude's WTI Midland-weighted average and the Cushing-based WTI formula basis or (iii) the Argus Americas Crude's WTI Houston-weighted average and the WTI Midland-weighted average. The Company's NGL derivatives are settled based on the month's arithmetic average of the daily average of the high and low OPIS index prices for Mont Belvieu Purity Ethane, TET and Non-TET Propane, Non-TET Normal Butane, Non-TET Isobutane and Non-TET Natural Gasoline. Other than the natural gas basis swaps, the Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA or the NYMEX index price for Henry Hub for the calculation period. The natural gas basis swaps are settled based on the differential between the basis swaps' fixed differential price as compared to the differential between the Inside FERC index price for West Texas WAHA and the NYMEX index price for Henry Hub for the calculation period. During the year ended December 31, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the hedge restructuring. The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 During the year ended December 31, 2016, the Company completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount to the Company of $80.0 million , which was settled in full by applying the proceeds to pay the premiums on two new derivatives entered into during the hedge restructuring. The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through December 31, 2018 , and represents derivatives in place through December 2021 on annual production volumes : Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 730,000 366,000 365,000 Weighted-average price ($/Bbl) $ 14.07 $ 13.60 $ 13.02 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 182,500 — — Weighted-average price ($/Bbl) $ 46.62 $ — $ — Total NGL volume hedged (Bbl) 912,500 366,000 365,000 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 16,425,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 ) See Note 2.f for discussion of derivatives significant accounting policies, and see Note 17.b for a summary of open derivative positions as of December 31, 2018 for derivatives that were entered into through February 13, 2019 |
Fair value measurements
Fair value measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair value measurements | Fair value measurements The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. a. Fair value measurement on a recurring basis The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in the "Derivatives" line items on the consolidated balance sheets as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the As of December 31, 2018: Assets Current: Oil derivatives $ — $ 44,425 $ — $ 44,425 $ (7,907 ) $ 36,518 NGL derivatives — 1,974 — 1,974 — 1,974 Natural gas derivatives — 18,991 — 18,991 (3,267 ) 15,724 Oil derivative deferred premiums — — — — (14,381 ) (14,381 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 10,626 $ — $ 10,626 $ — $ 10,626 NGL derivatives — 1,024 — 1,024 — 1,024 Natural gas derivatives — 108 — 108 (728 ) (620 ) Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,059 ) $ — $ (9,059 ) $ 7,907 $ (1,152 ) NGL derivatives — — — — — — Natural gas derivatives — (7,290 ) — (7,290 ) 3,267 (4,023 ) Oil derivative deferred premiums — — (16,565 ) (16,565 ) 14,381 (2,184 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — NGL derivatives — — — — — — Natural gas derivatives — (728 ) — (728 ) 728 — Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 60,071 $ (16,565 ) $ 43,506 $ — $ 43,506 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets As of December 31, 2017: Assets Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price(s), appropriate risk-adjusted discount rates and forward price curve models for substantially similar instruments generated from a compilation of data gathered from third parties. The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates. The deferred premiums are included in the "Derivatives" line items on the consolidated balance sheets, and as of December 31, 2018 , their input rates range from 2.31% to 3.32% with a net fair value weighted-average rate of 2.76% . The following table presents payments required for derivative deferred premiums as of December 31, 2018 for the calendar years presented: (in thousands) December 31, 2018 2019 $ 15,502 2020 1,295 Total $ 16,797 A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2018 2017 2016 Balance of Level 3 at beginning of year $ (28,683 ) $ (8,998 ) $ (14,619 ) Change in net present value of derivative deferred premiums (1) (694 ) (394 ) (232 ) Purchases and settlements of derivative deferred premiums: Purchases (7,523 ) (25,733 ) (7,715 ) Settlements (2) 20,335 6,442 13,568 Balance of Level 3 at end of year $ (16,565 ) $ (28,683 ) $ (8,998 ) _____________________________________________________________________________ (1) These amounts are included in the "Interest expense" line item in the consolidated statements of operations. (2) The amount for the year ended December 31, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's hedge restructuring upon their early termination. See Note 2.f See Note 2.i for the Level 2 fair value hierarchy input assumptions used in estimating the NRV of materials and supplies inventory used to account for the impairment of materials and supplies inventory recorded during the year ended December 31, 2016 . There were no impairments of materials and supplies inventory recorded during the years ended December 31, 2018 or 2017 . See Note 4.e for the Level 3 fair value hierarchy input assumptions used in estimating the fair values of assets acquired and liabilities assumed for acquisitions of evaluated and unevaluated oil and natural gas properties accounted for as a business combination for the year ended December 31, 2016. There were no acquisitions of evaluated and unevaluated oil and natural gas properties accounted for as business combinations for the years ended December 31, 2018 or 2017 . Impairment losses are recorded on long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. There were no long-lived asset impairments recorded during the years ended December 31, 2018 , 2017 or 2016 c. Items not accounted for at fair value The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ 450,000 $ 402,885 $ 450,000 $ 454,500 March 2023 Notes 350,000 316,624 350,000 364,105 Senior Secured Credit Facility 190,000 190,054 — — Total $ 990,000 $ 909,563 $ 800,000 $ 818,605 _____________________________________________________________________________ (1) The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the as of December 31, 2018 and 2017 Level 1 fair value hierarchy quoted market price for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2018 was estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments. See Note 10.a |
Income taxes
Income taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income taxes | Income taxes The Company is subject to federal and state income taxes and the Texas franchise tax. The following table presents the federal and state income taxes included in the income tax expense "Current" and "Deferred" line items in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Current income tax benefit: Federal $ — $ — $ — State 807 (1,800 ) — Deferred income tax expense: Federal — — — State (5,056 ) — — Total income tax expense $ (4,249 ) $ (1,800 ) $ — As of December 31, 2018, a Texas deferred tax liability of $5.1 million has been recorded, which is included in the "Other noncurrent liabilities" line item on the consolidated balance sheets, along with the corresponding deferred income tax expense for the year ended December 31, 2018. Additionally, a current tax refund of $0.8 million of Texas franchise tax was received as a result of differences in estimated versus actual taxable income from the gain on the Medallion Sale and is recorded as a current income tax benefit. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act, among other things, (i) reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) imposes new limitations on the utilization of net operating losses and (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. The Company recognizes the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The enactment date in the U.S. is the date the bill becomes law, which is when the President signs the bill. For the year ended December 31, 2017, current tax expense recorded of $1.8 million is comprised of Texas franchise tax, mainly as a result of the Medallion Sale. Additionally, the Company paid Alternative Minimum Tax ("AMT") related to the Medallion Sale. The payment of AMT creates an AMT credit carryforward. Due to changes in the Tax Act, AMT credit carryforwards do not expire and are now refundable over the next five years, and therefore, as of December 31, 2018 , a receivable has been recorded in the amount of $4.8 million , of which $2.4 million is included in the "Accounts receivable, net" line item and $2.4 million is included in the "Other noncurrent assets, net" line item on the consolidated balance sheets. The following table presents the expected years in which the Company's AMT credit carryforward will be refunded: (in thousands) December 31, 2018 2019 $ 2,408 2020 1,203 2021 602 2022 602 AMT credit carryforward $ 4,815 Income tax expense differed from amounts computed by applying the applicable federal income tax rate of 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2018 2017 2016 Income tax (expense) benefit computed by applying the statutory rate $ (69,057 ) $ (192,141 ) $ 91,259 Decrease (increase) in deferred tax valuation allowance 74,289 417,518 (86,569 ) State income tax and change in valuation allowance (9,070 ) 696 (370 ) Change in tax rate applicable to net deferred tax assets — (226,263 ) — Stock-based compensation tax deficiency — (64 ) (4,144 ) Other items (411 ) (1,546 ) (176 ) Total income tax expense $ (4,249 ) $ (1,800 ) $ — The effective tax rates for the Company's operations were 1% for the year ended December 31, 2018 , and 0% for each of the years ended December 31, 2017 and 2016 . The Company's effective tax rate is affected by changes in tax rates, valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. The Company's effective tax rate is expected to remain at 1% , due to the full valuation allowance against the Company's federal and Oklahoma net deferred tax assets. On January 1, 2018, the Company adopted ASC 606 using the modified retrospective approach of adoption with the cumulative effect recognized as an adjustment to the beginning balance of accumulated deficit, presented in the consolidated statements of stockholders' equity . As the effect on income taxes of adoption and transition to ASC 606 are direct effects of the change, the beginning balances of the federal and state deferred tax assets and the offsetting valuation allowances relating to the reclassification of the $141.1 million deferred gain on Medallion Sale were reduced by $30.7 million . See Note 5.a for further discussion of the impact of ASC 606 adoption. A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During the years ended December 31, 2018 and 2017 , in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil, NGL and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2018 and 2017 , management determined it was more likely than not that the net deferred tax assets were not realizable. The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of December 31, 2018, a total valuation allowance of $237.3 million had been recorded against the deferred tax assets. The following table presents significant components of the Company's net deferred tax liability as of December 31: (in thousands) 2018 2017 Net operating loss carryforward $ 392,276 $ 355,100 Oil and natural gas properties, midstream service assets and other fixed assets (168,031 ) (80,153 ) Stock-based compensation 19,845 14,025 Derivatives (8,188 ) 3,788 Gain (loss) on sale of assets (7,693 ) 40,177 Other 3,997 8,465 Net deferred tax asset before valuation allowance 232,206 341,402 Valuation allowance (237,262 ) (341,402 ) Net deferred tax liability $ (5,056 ) $ — The following presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2018 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,406,873 Total $ 1,859,821 The Company had federal net operating loss carry-forwards totaling $1.9 billion and state of Oklahoma net operating loss carryforwards totaling $36.2 million as of December 31, 2018 , which begin expiring in 2026 and 2032, respectively. Due to the passing of the Tax Act, $122.7 million of the federal net operating loss carry-forward will not expire but may be limited in future periods. As of December 31, 2018 , the Company believes it is more likely than not that a portion of the net operating loss carry-forwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2018 , the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused and future projections of Oklahoma sourced income. The Company files a single return. The Company's income tax returns for the years 2015 through 2018 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carryforwards typically does not begin to run until the year the attribute is utilized in a tax return. See Note 2.q |
Credit risk
Credit risk | 12 Months Ended |
Dec. 31, 2018 | |
Risks and Uncertainties [Abstract] | |
Credit risk | Credit risk The Company's oil, NGL and natural gas production sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies . The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. The majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability of the Company's significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company's financial results. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. See Notes 2.e and 5 for additional information regarding the Company's accounts receivable and revenue recognition, respectively. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties, each of whom is also a lender in the Company's Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with the Company's derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis. As of December 31, 2018 , the Company had receivables of $50.9 million from the fair values of open derivative contracts . See "Part II, Item 7a. Quantitative and Qualitative Disclosures About Market Risk—Commodity price exposure" located elsewhere in this Annual Report and Notes 2.f , 9 , 10.a and 17.b for additional information regarding the Company's derivatives. The Company had four customers that accounted for 29.5% , 24.2% , 16.2% and 16.0% of total oil, NGL and natural gas sales for the year ended December 31, 2018 , and three customers that accounted for 33.8% , 23.9% , and 23.3% of total oil, NGL and natural gas sales accounts receivable as of December 31, 2018 . The Company had four customers that accounted for (i) 39.3% , 26.1% , 17.4% and 12.6% of total oil, NGL and natural gas sales for the year ended December 31, 2017 , and (ii) 34.6% , 27.3% , 15.6% and 15.4% of total oil, NGL and natural gas sales accounts receivable as of December 31, 2017 . The Company had three customers that accounted for 48.5% , 23.0% and 17.0% of total oil, NGL and natural gas sales for the year ended December 31, 2016 . The Company had two partners that accounted for 46.7% and 30.9% of total joint operations, net accounts receivable as of December 31, 2018 . The Company had one partner that accounted for 21.4% of total joint operations, net accounts receivable as of December 31, 2017 . The Company had two customers that accounted for 63.9% and 36.1% of total sales of purchased oil for the year ended December 31, 2018 , and one customer that accounted for 100.0% of total sales of purchased oil and other products accounts receivable as of December 31, 2018 . The Company had one customer that accounted for 97.5% of total sales of purchased oil for the year ended December 31, 2017 , with the same customer accounting for 99.7% of total sales of purchased oil and other products accounts receivable as of December 31, 2017 . The Company had one customer that accounted for 100.0% of total sales of purchased oil for the year ended December 31, 2016 . The Company's cash balances that are insured by the FDIC up to $250,000 per bank did not exceed this amount as of December 31, 2018 . The Company had $48.2 million in cash balances on deposit with three banks as of December 31, 2018 that were not insured by the FDIC. Management believes that the risk of loss is mitigated by the banks' reputation and financial position. See "Part I, Item 3. Legal Proceedings" located elsewhere in this Annual Report and Note 14 |
Commitments and contingencies
Commitments and contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and contingencies | Commitments and contingencies a. Lease commitments The Company leases office space under operating leases expiring on various dates through 2027 . The following table presents future minimum rental payments required: (in thousands) December 31, 2018 2019 $ 3,092 2020 3,179 2021 3,128 2022 2,560 2023 1,358 Thereafter 4,556 Total future minimum rental payments required $ 17,873 The Company subleases office space with $5.9 million total future minimum rentals to be received as of December 31, 2018 . The following table presents rent expense: For the years ended December 31, (in thousands) 2018 2017 2016 Rent expense $ 2,735 $ 2,696 $ 2,664 Rent income for the year ended December 31, 2018 totaled $0.6 million . Rent income for the year ended December 31, 2017 totaled de minimis amounts. No such amounts were included for the year ended December 31, 2016 . The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the leases. In accordance with GAAP, the Company records rent expense and rent income on a straight-line basis and a deferred lease liability and deferred lease asset, respectively, for the difference between the straight-line amount and the actual amounts of the lease payments and lease receipts. Deferred lease liability, net is included in the "Other current liabilities" and "Other noncurrent liabilities" line items on the consolidated balance sheets. Rent expense and rent income are included in the "General and administrative" line item and "Interest and other income" line item, respectively, in the consolidated statements of operations. b. Litigation From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, except with regard to the specific litigation noted below, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity. On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and the Company effective October 1, 2016 through June 30, 2020 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the crude oil purchase agreement, court costs and attorneys' fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement, which covered the sale to Shell of 19,000 barrels of crude oil per day of the Company's gross production as well as the purchase by the Company of like-quantity crude oil from Shell. On December 11, 2017, Shell filed its First Amended Petition, in which it asserted nine causes of action, including multiple new claims for breach of contract and fraud. Effective May 1, 2018, Shell terminated the crude oil purchase agreement and ceased purchasing the Company's crude oil and selling crude oil to the Company under the terms of such agreement. As a result, the Company filed its Second Amended Answer and Original Counterclaim against Shell on June 15, 2018, in which the Company denies all allegations by Shell and seeks damages in excess of $150.0 million resulting from Shell's breach and wrongful termination of the crude oil purchase agreement. Shell filed a Second Amended Petition on June 1, 2018, in which it asserted a new cause of action against the Company for alleged repudiation of Shell's proposed reformed version of the crude oil purchase agreement, a version never signed or agreed to by the Company. Through April 30, 2018, the last day before Shell's wrongfully termination of the crude oil purchase agreement, the Company had accounted for the costs and crude oil price realization as reflected in the terms of the crude oil purchase agreement. The accompanying consolidated balance sheets do not include any amounts for damage claims or attorneys' fees sought by Shell. As of December 31, 2018 , the Company had estimated an aggregate amount of $37.4 million that is the subject of Shell's claims, which is generally based on the contractual amount in dispute under the pricing election that is the subject of Shell's claims applied to the barrels of crude oil purchased and sold through the date on which Shell wrongfully terminated the crude oil purchase agreement. As a result of such termination, the Company's estimate of this unrecorded amount is not anticipated to materially increase in the future. This estimate does not include damages sought by Shell pursuant to its latest repudiation claim asserted in its Second Amended Petition or amounts sought by Shell for recovery of attorneys' fees incurred for the prosecution of its claims. The Company is unable to determine a probability of the outcome of this litigation at this time. The Company believes Shell's claims are meritless and the termination by Shell is improper and a breach of the crude oil purchase agreement. The Company therefore intends to vigorously defend itself against Shell's claims and pursue its rights under the terminated crude oil purchase agreement to seek all appropriate damages from Shell. c. Drilling contracts The Company has committed to several drilling contracts with third parties to facilitate the Company's drilling plans . Certain of these contracts are for a term of multiple months and contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for the years ended December 31, 2018 , 2017 or 2016 . Future commitments of $16.5 million as of December 31, 2018 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of these contracts in 2019. d. Firm sale and transportation commitments The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred firm transportation payments on excess pipeline capacity and other contractual penalties of $4.7 million , $1.1 million and $2.2 million during the years ended December 31, 2018 , 2017 and 2016 , respectively. In the consolidated statements of operations, these firm transportation payments on excess pipeline capacity and other contractual penalties are netted with their respective revenue stream for the year ended December 31, 2018 , and are included in the "Other operating expenses" line item for the years ended December 31, 2017 and 2016. Future commitments of $365.9 million as of December 31, 2018 are not recorded in the accompanying consolidated balance sheets. For information regarding the impact of the adoption of ASC 606 on the TA related to Medallion and the presentation of firm transportation payments on excess pipeline capacity and other contractual penalties, see Notes 4.c and 5 . e. Sand purchase and supply agreement During the year ended December 31, 2018, the Company entered into a sand purchase and supply agreement, for a term of one year, whereby it has committed to buy a certain volume of in-basin sand, utilized in the Company's completion activities, for a fixed price. As of December 31, 2018 , under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it would incur a shortfall payment of $3.9 million at the end of the contract period. f. Federal and state regulations Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations. g. Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no material significant liabilities of this nature existed as of December 31, 2018 or 2017 |
Related parties
Related parties | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Parties | Related parties a. Medallion Medallion was a related party and an equity method investee until the Medallion Sale in October 2017. See Note 4.c for discussion of the Medallion Sale. For the year ended December 31, 2017, a de minimis amount related to Medallion was included in the "Loss on disposal of assets, net" line item in the consolidated statements of operations. No such amounts were included for the years ended December 31, 2018 or 2016. b. Helmerich & Payne, Inc. The Company has a drilling contract with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P. The following table presents accounts payable and accrued liabilities related to H&P included in the consolidated balance sheets: (in thousands) December 31, 2018 December 31, 2017 Accounts payable and accrued liabilities $ 399 $ — The following table presents the capital expenditures for oil and natural gas properties related to H&P included in the consolidated statements of cash flows: For the years ended December 31, (in thousands) 2018 2017 2016 Oil and natural gas properties $ 3,040 $ — $ — |
Subsidiary guarantors
Subsidiary guarantors | 12 Months Ended |
Dec. 31, 2018 | |
Condensed Financial Information Disclosure [Abstract] | |
Subsidiary guarantors | Subsidiary guarantors The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the May 2022 Notes until the May 2022 Notes Redemption Date ), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2018 and 2017 and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2018 , 2017 and 2016 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the year ended December 31, 2016, certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost. No such transfers occurred during the years ended December 31, 2018 or 2017. Condensed consolidating balance sheet December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 83,424 $ 10,897 $ — $ 94,321 Other current assets 97,045 1,386 — 98,431 Oil and natural gas properties, net 2,043,009 9,113 (22,551 ) 2,029,571 Midstream service assets, net — 130,245 — 130,245 Other fixed assets, net 39,751 68 — 39,819 Investment in subsidiaries 128,380 — (128,380 ) — Other noncurrent assets, net 23,783 4,135 — 27,918 Total assets $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Accounts payable and accrued liabilities $ 54,167 $ 15,337 $ — $ 69,504 Other current liabilities 121,297 9,664 — 130,961 Long-term debt, net 983,636 — — 983,636 Other noncurrent liabilities 59,511 2,463 — 61,974 Total stockholders' equity 1,196,781 128,380 (150,931 ) 1,174,230 Total liabilities and stockholders' equity $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Total stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Condensed consolidating statement of operations For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 809,396 $ 365,633 $ (69,254 ) $ 1,105,775 Total costs and expenses 466,895 353,806 (63,418 ) 757,283 Operating income 342,501 11,827 (5,836 ) 348,492 Interest expense (57,904 ) — — (57,904 ) Other non-operating income (expense), net 50,083 (1,049 ) (10,778 ) 38,256 Income before income tax 334,680 10,778 (16,614 ) 328,844 Total income tax expense (4,249 ) — — (4,249 ) Net income $ 330,431 $ 10,778 $ (16,614 ) $ 324,595 Condensed consolidating statement of operations For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 623,028 $ 266,455 $ (67,321 ) $ 822,162 Total costs and expenses 376,938 254,398 (58,846 ) 572,490 Operating income 246,090 12,057 (8,475 ) 249,672 Interest expense (89,377 ) — — (89,377 ) Gain on sale of investment in equity method investee (see Note 4.c) — 405,906 — 405,906 Other non-operating income (expense), net 402,536 8,083 (426,046 ) (15,427 ) Income before income tax 559,249 426,046 (434,521 ) 550,774 Total income tax expense (1,800 ) — — (1,800 ) Net income $ 557,449 $ 426,046 $ (434,521 ) $ 548,974 Condensed consolidating statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense (93,298 ) — — (93,298 ) Other non-operating income (expense), net (73,669 ) 9,381 (15,191 ) (79,479 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Total income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 ) Condensed consolidating statement of cash flows For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 528,281 $ 20,301 $ (10,778 ) $ 537,804 Change in investments between affiliates 5,175 (15,953 ) 10,778 — Capital expenditures and other (686,608 ) (6,003 ) — (692,611 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 1,655 — 1,655 Net cash provided by financing activities 86,144 — — 86,144 Net decrease in cash and cash equivalents (67,008 ) — — (67,008 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 45,150 $ 1 $ — $ 45,151 Condensed consolidating statement of cash flows For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 778,851 $ 32,109 $ (426,046 ) $ 384,914 Change in investments between affiliates 383,613 (809,659 ) 426,046 — Capital expenditures and other (482,500 ) (52,065 ) — (534,565 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 829,615 — — 829,615 Net cash used in financing activities (600,477 ) — — (600,477 ) Net increase in cash and cash equivalents 79,487 — — 79,487 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 112,158 $ 1 $ — $ 112,159 Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672 |
Subsequent events
Subsequent events | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent events | Subsequent events a. Senior Secured Credit Facility On January 14, 2019 and February 12, 2019, the Company borrowed $30.0 million and $20.0 million , respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $240.0 million as of February 13, 2019 . b. Derivatives The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through February 13, 2019 , and represents derivatives in place through December 2021 on annual production volumes: Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 2,233,000 366,000 912,500 Weighted-average price ($/Bbl) $ 14.21 $ 13.60 $ 12.01 Swaps - Non-TET Propane: Hedged volume (Bbl) 1,736,800 1,244,400 730,000 TABLE CONTINUES ON NEXT PAGE Year 2019 Year 2020 Year 2021 Weighted-average price ($/Bbl) $ 27.97 $ 26.58 $ 25.52 Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 668,000 439,200 255,500 Weighted-average price ($/Bbl) $ 30.73 $ 28.69 $ 27.72 Swaps - Non-TET Isobutane: Hedged volume (Bbl) 167,000 109,800 67,525 Weighted-average price ($/Bbl) $ 31.08 $ 29.99 $ 28.79 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 583,300 402,600 237,250 Weighted-average price ($/Bbl) $ 45.83 $ 45.15 $ 44.31 Total NGL volume hedged (Bbl) 5,388,100 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 ) See Note 9 |
Supplemental oil, NGL and natur
Supplemental oil, NGL and natural gas disclosures (unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental oil, NGL and natural gas disclosures (unaudited) | Supplemental oil, NGL and natural gas disclosures (unaudited) a. Costs incurred in oil and natural gas property acquisition, exploration and development activities The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Property acquisition costs: Evaluated $ 15,072 $ — $ 5,905 Unevaluated 2,790 — 119,923 Exploration costs 23,884 36,257 41,333 Development costs 607,790 560,919 298,942 Total costs incurred $ 649,536 $ 597,176 $ 466,103 b. Aggregate capitalized oil, NGL and natural gas costs The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment: (in thousands) December 31, 2018 December 31, 2017 Gross capitalized costs: Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Total gross capitalized costs 6,883,588 6,246,805 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Net capitalized costs $ 2,029,571 $ 1,589,339 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2018 , by year in which such costs were incurred: (in thousands) 2018 2017 2016 2015 and prior Total Unevaluated properties not being depleted $ 38,815 $ 15,076 $ 56,826 $ 20,240 $ 130,957 Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil and natural gas leasehold where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation. c. Results of operations of oil, NGL and natural gas producing activities The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs): For the years ended December 31, (in thousands) 2018 2017 2016 Revenues: Oil, NGL and natural gas sales $ 808,530 $ 621,507 $ 426,485 Production costs: Lease operating expenses 91,289 75,049 75,327 Production and ad valorem taxes 49,457 37,802 28,586 Transportation and marketing expenses 11,704 — — Total production costs 152,450 112,851 103,913 Other costs: Depletion 196,458 143,592 134,105 Accretion of asset retirement obligations 4,233 3,567 3,274 Impairment expense — — 161,064 Income tax expense (1) 4,554 — — Total other costs 205,245 147,159 298,443 Results of operations $ 450,835 $ 361,497 $ 24,129 _____________________________________________________________________________ (1) During each of the years ended December 31, 2018, 2017 and 2016, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax expense was computed utilizing the Company's effective rate of 1% for the year ended December 31, 2018 and 0% for each of the years ended December 31, 2017 and 2016, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's consolidated income tax expense for the period. d. Net proved oil, NGL and natural gas reserves Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2018 , 2017 and 2016 . In accordance with SEC regulations, the reserves as of December 31, 2018 , 2017 and 2016 were estimated using the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead . See Note 6.a for additional discussion. The Company's reserves as of December 31, 2018 , 2017 and 2016 are reported in three streams: oil, NGL and natural gas. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available. The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2018 , 2017 and 2016, all of which are located within the U.S. Year ended December 31, 2018 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 79,413 67,371 414,592 215,883 Revisions of previous estimates (20,921 ) 11,089 72,028 2,173 Extensions, discoveries and other additions 13,330 15,112 93,762 44,069 Acquisitions of reserves in place 596 457 2,810 1,521 Divestitures of reserves in place (349 ) (123 ) (756 ) (598 ) Production (10,175 ) (7,259 ) (44,680 ) (24,881 ) End of year 61,894 86,647 537,756 238,167 Proved developed reserves: Beginning of year 68,877 60,441 371,946 191,309 End of year 55,893 79,241 491,828 217,105 Proved undeveloped reserves: Beginning of year 10,536 6,930 42,646 24,574 End of year 6,001 7,406 45,928 21,062 Year ended December 31, 2017 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 63,940 50,350 316,857 167,100 Revisions of previous estimates 9,818 13,158 74,247 35,351 Extensions, discoveries and other additions 15,250 9,711 59,759 34,921 Divestitures of reserves in place (120 ) (48 ) (299 ) (218 ) Production (9,475 ) (5,800 ) (35,972 ) (21,270 ) End of year 79,413 67,371 414,592 215,883 Proved developed reserves: Beginning of year 53,156 42,950 270,291 141,155 End of year 68,877 60,441 371,946 191,309 Proved undeveloped reserves: Beginning of year 10,784 7,400 46,566 25,945 End of year 10,536 6,930 42,646 24,574 Year ended December 31, 2016 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Acquisitions of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945 For the year ended December 31, 2018, the Company's positive revision of 2,173 MBOE of previously estimated quantities consisted of (i) 11,364 MBOE of negative revisions from performance driven mainly by steeper oil decline curves and tighter well spacing, and a decrease in the Realized Price for natural gas, (ii) 7,045 MBOE of positive revisions from increases in the Realized Prices for oil and NGL and other changes to proved developed producing wells and (iii) 6,492 MBOE of positive revisions due to proved undeveloped locations that were removed from the development plan in prior years, eight of these locations were drilled in 2018 and two are scheduled to be drilled in 2019. Extensions, discoveries and other additions of 44,069 MBOE during the year ended December 31, 2018 consisted of (i) 25,617 MBOE that resulted from new wells drilled during the year and (ii) 18,452 MBOE that resulted from new horizontal proved undeveloped locations added during the year. For the year ended December 31, 2017, the Company's positive revision of 35,351 MBOE of previously estimated quantities consisted of (i) 16,916 MBOE from positive performance, price increases and other changes to proved developed producing wells and (ii) 18,435 MBOE of revisions due to proved undeveloped locations that were removed from the development plan in prior years, 10 of these locations were drilled in 2017 and eight were scheduled to be drilled in 2018. Extensions, discoveries and other additions of 34,921 MBOE during the year ended December 31, 2017 consisted of (i) 18,985 MBOE that resulted from new wells drilled during the year and (ii) 15,936 MBOE that resulted from new horizontal proved undeveloped locations added during the year. For the year ended December 31, 2016, the Company's positive revision of 34,082 MBOE of previously estimated quantities is primarily attributable to the combination of positive performance, lower operating costs and other changes to proved developed producing wells. 26,049 MBOE is due to a combination of positive performance, reduction in operating costs and other factors. Previously estimated quantities of 2,292 MBOE were removed due to derecognizing certain proved undeveloped locations and proved developed non-producing targets due to changes in development and drilling plans. In addition, 10,325 MBOE of revisions is due to proved undeveloped locations that were removed from the development plan in prior years, four of these locations were drilled in 2016 and seven were scheduled to be drilled in 2017. Extensions, discoveries and other additions of 24,940 MBOE during the year ended December 31, 2016 consisted of 13,302 MBOE that resulted from new wells drilled during the year and 11,638 MBOE that resulted from new horizontal proved undeveloped locations added during the year. e. Standardized measure of discounted future net cash flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2018 , 2017 and 2016 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead . All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net revenues. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10% . The Company's unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling as of March 31, 2016 , but did not record any similar impairments for the years ended December 31, 2018 or 2017 . See Note 6.a for discussion of the Benchmark Prices, Realized Prices and the 2016 full cost ceiling impairment recorded. The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Future cash inflows $ 6,266,862 $ 5,777,533 $ 3,548,567 Future production costs (1,977,401 ) (1,675,837 ) (1,238,369 ) Future development costs (257,310 ) (307,689 ) (290,505 ) Future income tax expenses (226,183 ) (237,153 ) — Future net cash flows 3,805,968 3,556,854 2,019,693 10% discount for estimated timing of cash flows (1,691,731 ) (1,786,533 ) (1,041,199 ) Standardized measure of discounted future net cash flows $ 2,114,237 $ 1,770,321 $ 978,494 It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Standardized measure of discounted future net cash flows, beginning of year $ 1,770,321 $ 978,494 $ 830,747 Changes in the year resulting from: Sales, less production costs (656,080 ) (508,656 ) (322,573 ) Revisions of previous quantity estimates (179,912 ) 289,150 179,297 Extensions, discoveries and other additions 521,605 296,129 133,472 Net change in prices and production costs 365,902 474,831 (80,102 ) Changes in estimated future development costs 7,246 10,989 22,153 Previously estimated development costs incurred during the period 207,865 192,332 189,085 Acquisitions of reserves in place 11,411 — 3,422 Divestitures of reserves in place (6,015 ) (793 ) — Accretion of discount 181,693 97,849 83,075 Net change in income taxes (10,340 ) (46,610 ) — Timing differences and other (99,459 ) (13,394 ) (60,082 ) Standardized measure of discounted future net cash flows, end of year $ 2,114,237 $ 1,770,321 $ 978,494 Estimates of economically recoverable oil, NGL and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories |
Supplemental quarterly financia
Supplemental quarterly financial data (unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Supplemental quarterly financial data (unaudited) | Supplemental quarterly financial data (unaudited) The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2018 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 259,696 $ 351,046 $ 279,746 $ 215,287 Operating income 93,192 94,767 104,410 56,123 Net income 86,520 33,452 55,050 149,573 Net income per common share: Basic $ 0.36 $ 0.14 $ 0.24 $ 0.65 Diluted $ 0.36 $ 0.14 $ 0.24 $ 0.65 Year ended December 31, 2017 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter (1) Revenues $ 189,006 $ 187,001 $ 205,818 $ 240,337 Operating income 51,326 52,061 60,452 85,833 Net income 68,276 61,110 11,027 408,561 Net income per common share: Basic $ 0.29 $ 0.26 $ 0.05 $ 1.71 Diluted $ 0.28 $ 0.25 $ 0.05 $ 1.70 _____________________________________________________________________________ (1) |
Basis of presentation and sig_2
Basis of presentation and significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Basis of presentation | Basis of presentation |
Use of estimates in the preparation of consolidated financial statements | Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas , (ii) future cash flows from oil and natural gas properties , (iii) depletion, depreciation and amortization , (iv) impairments , (v) asset retirement obligations , (vi) stock-based compensation , (vii) deferred income taxes , (viii) fair value of assets acquired and liabilities assumed in an acquisition , (ix) fair values of derivatives and deferred premiums and (x) contingent liabilities . As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. |
Reclassifications | Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows. |
Cash and cash equivalents | Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in |
Accounts receivable | Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 |
Derivatives | Derivatives Derivatives are recorded at fair value and are presented on a net basis on the "Derivatives" line items on the consolidated balance sheets as assets and/or liabilities. The Company presents the fair value of derivatives net by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. The Company's derivatives were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 9 and 10.a for additional discussion of derivatives and the fair value measurement of derivatives, respectively. |
Oil and natural gas properties | Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties . Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. See Note 6 the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties . The Company capitalizes a portion of its interest costs to its unevaluated properties . Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. See Note 18 for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission (" SEC ") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials (" Benchmark Prices "). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead (" Realized Prices "). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. |
Midstream service assets | Midstream service assets, which consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost, are recorded at cost, net of impairment. See Note 2.k for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 |
Inventory | Inventory |
Debt issuance costs | Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. |
Asset retirement obligations | Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience and estimated remaining life per well, (ii) estimated removal and/or remediation costs for midstream service assets and estimated remaining life of midstream service assets, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory and environmental matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable. |
Fair value measurements | Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. Fair value measurements The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. |
Treasury stock | Treasury stock |
Revenue recognition | Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated from oil throughput fees and services provided to third parties for (i) oil and natural gas gathering and transportation systems and related facilities, (ii) gas lift, rig fuel and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure (collectively, "Midstream Services"), and are recognized over time as the customer benefits from these services when provided. Revenue recognition See Note 2.n for a summary of revenue recognition policies, a more detailed discussion of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. Under certain of its customer contracts, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream service revenues Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2018 or 2017. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less . For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the year ended December 31, 2018 |
Fees received for the operation of jointly-owned oil and natural gas properties | Fees received for the operation of jointly-owned oil and natural gas properties |
Compensation awards | Compensation awards Stock-based compensation expense, net, is included in the "General and administrative" line item in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values, less an expected forfeiture rate, of the performance share awards with market criteria and, in prior periods, the performance unit awards. For performance share awards with performance criteria, the grant-date fair value is equal to the Company's stock price on the grant date, less an expected forfeiture rate, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the performance period. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. See Note 8.c for further discussion regarding the restricted stock awards, stock option awards and performance share awards. 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the consolidated balance sheets. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules that mainly include (i) 33% , 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately on the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vested fully on the first anniversary of the grant date. |
Income taxes | Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. |
Recently issued or adopted accounting pronouncements | Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs and a final rule issued by the SEC listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the year ended December 31, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606 , Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption . ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 5 for further discussion of the ASC 606 adoption impact on the Company's consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption was permitted. The primary effect on the Company's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has a team, including third-party consultants, to implement the standard and has implemented the software that will be used to track and account for lease activity. As of December 31, 2018, the Company anticipates that the adoption and implementation of ASC 842 will result in approximately a $25.0 million to $40.0 million increase in assets and liabilities on the consolidated balance sheet in 2019, but will not result in a material impact to the consolidated statement of operations. This estimate may vary based on any additional contracts entered into subsequent to December 31, 2018. The Company has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. The transition will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted (January 1, 2019). The Company will utilize the transition package of expedients to leases that commenced before the effective date. The Company expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. See Note 4.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU. d. Fair value measurements In August 2018, the FASB issued new guidance in ASC 820, Fair Value Measurement , to modify disclosure requirements. Of the amendments in the ASU, the below items affected the Company's fair value measurement disclosures in Note 10 . Removed disclosure requirements that should be applied retrospectively to all periods presented are: (i) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the policy for timing of transfers between levels and (iii) the valuation processes for Level 3 fair value measurements. A modified disclosure requirement that should be applied prospectively is to clarify that the measurement uncertainty disclosure communicates information about the uncertainty in measurement as of the reporting date. A new disclosure requirement that should be applied prospectively is to disclose the range and weighted-average of significant unobservable inputs used to develop Level 3 fair value measurements. The Company has elected to early adopt this guidance upon the issuance of the ASU and has modified its disclosures accordingly. e. SEC disclosure update and simplification In August 2018, the SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification |
Other fixed assets | Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten |
Variable interest entity | The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the consolidated statements of operations on the "Income from equity method investee" line item. |
Business combinations | Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 10.a |
Net income (loss) per common share | Net income (loss) per common share |
Credit risk | Credit risk The Company's oil, NGL and natural gas production sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies . The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. The majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability of the Company's significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company's financial results. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. See Notes 2.e and 5 for additional information regarding the Company's accounts receivable and revenue recognition, respectively. The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties, each of whom is also a lender in the Company's Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with the Company's derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard |
Basis of presentation and sig_3
Basis of presentation and significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of components of accounts receivable | Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Oil, NGL and natural gas sales $ 44,958 $ 67,116 Joint operations, net (1) 16,772 8,780 Sales of purchased oil and other products 10,244 19,504 Other 22,347 5,245 Total accounts receivable $ 94,321 $ 100,645 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million as of December 31, 2018 and 2017 |
Schedule of components of other current liabilities | Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Accrued interest payable $ 18,281 $ 18,013 Accrued compensation and benefits 13,317 21,287 Deferred gain on sale of equity method investment (1) — 20,144 Other accrued liabilities 13,188 16,111 Total other current liabilities $ 44,786 $ 75,555 _____________________________________________________________________________ (1) See Notes 4.c and 5.a |
Schedule of components of other noncurrent liabilities | Other noncurrent liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Deferred gain on sale of equity method investment (1) $ — $ 120,974 Other accrued liabilities 8,587 13,116 Total other noncurrent liabilities $ 8,587 $ 134,090 _____________________________________________________________________________ (1) See Notes 4.c and 5.a |
Schedule of asset retirement obligation liability | The following table reconciles the Company's asset retirement obligation liability: For the years ended December 31, (in thousands) 2018 2017 Liability at beginning of year $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 995 616 Accretion expense 4,472 3,791 Liabilities settled upon plugging and abandonment (2,848 ) (408 ) Liabilities removed due to sale of property (1,243 ) (871 ) Revision of estimates — 171 Liability at end of year $ 56,882 $ 55,506 |
Schedule of fees received from operation of jointly owned oil and natural gas properties | The following table presents the fees received for the operation of jointly-owned oil and natural gas properties: For the years ended December 31, (in thousands) 2018 2017 2016 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,507 $ 2,549 $ 2,477 |
Schedule of non-cash investing and supplemental cash flow information | The following table presents non-cash investing and supplemental cash flow information: For the years ended December 31, (in thousands) 2018 2017 2016 Non-cash investing information: (Decrease) increase in accrued capital expenditures $ (52,746 ) $ 51,876 $ (31,027 ) Change in accrued capital contribution to equity method investee (1) $ — $ — $ (27,583 ) Capitalized stock-based compensation $ 7,929 $ 7,563 $ 6,011 Capitalized asset retirement cost $ 995 $ 787 $ 3,660 Supplemental cash flow information: Cash paid for interest, net of $988, $1,152 and $294 of capitalized interest, respectively (2) $ 53,981 $ 91,548 $ 89,432 Cash paid for income taxes (3) $ 735 $ 5,500 $ — ______________________________________________________________________________ (1) See Notes 4.c and 5.a for additional discussion of the Company's former equity method investee. (2) See Note 7.f for additional discussion of the Company's interest expense. (3) See Note 12 |
Acquisitions and divestitures (
Acquisitions and divestitures (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Final estimate of the fair values of the assets acquired and liabilities assumed | The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723 |
Revenue recognition (Tables)
Revenue recognition (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Impact of adoption of ASC 606 | The impact of the adoption of ASC 606 on the results of operations for the year ended December 31, 2018 is as follows: (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 607,870 $ 605,197 $ (2,673 ) NGL sales $ 150,822 $ 149,843 $ (979 ) Natural gas sales $ 54,511 $ 53,490 $ (1,021 ) Costs and expenses: Other operating expenses $ 9,145 $ 4,472 $ (4,673 ) Net income $ 324,595 $ 324,595 $ — |
Property and equipment (Tables)
Property and equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Benchmark Prices and Realized Prices used in the full cost ceiling calculation | The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2018 December 31, 2017 December 31, 2016 Benchmark Prices: Oil ($/Bbl) $ 62.04 $ 47.79 $ 39.25 NGL ($/Bbl) (1) $ 31.46 $ 26.13 $ 18.24 Natural gas ($/MMBtu) $ 1.76 $ 2.63 $ 2.33 Realized Prices: Oil ($/Bbl) $ 59.29 $ 46.34 $ 37.44 NGL ($/Bbl) $ 21.42 $ 18.45 $ 11.72 Natural gas ($/Mcf) $ 1.38 $ 2.06 $ 1.78 _____________________________________________________________________________ (1) |
Schedule of employee-related costs capitalized to oil and natural gas properties | The following table presents capitalized employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Capitalized employee-related costs $ 25,372 $ 25,553 $ 19,222 |
Schedule of property and equipment | Oil and natural gas properties consisted of the following components as of the dates presented: (in thousands) December 31, 2018 December 31, 2017 Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Oil and natural gas properties, net $ 2,029,571 $ 1,589,339 The following table presents depletion and depletion per BOE sold of the Company's evaluated oil and natural gas properties for the periods presented: For the years ended December 31, (in thousands except per BOE data) 2018 2017 2016 Depletion of evaluated oil and natural gas properties $ 196,458 $ 143,592 $ 134,105 Depletion per BOE sold $ 7.90 $ 6.75 $ 7.39 (in thousands) December 31, 2018 December 31, 2017 Vehicles $ 10,660 $ 9,661 Computer hardware and software 9,222 11,696 Buildings 7,804 7,618 Leasehold improvements 7,608 7,590 Aircraft 6,402 6,402 Other 3,735 5,990 Depreciable total 45,431 48,957 Less accumulated depreciation and amortization (23,871 ) (23,150 ) Depreciable total, net 21,560 25,807 Land 18,259 14,914 Total other fixed assets, net $ 39,819 $ 40,721 (in thousands) December 31, 2018 December 31, 2017 Midstream service assets $ 172,308 $ 171,427 Less accumulated depreciation and impairment (42,063 ) (33,102 ) Total midstream service assets, net $ 130,245 $ 138,325 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of future amortization of debt issuance costs | The following table presents future amortization expense of debt issuance costs: (in thousands) December 31, 2018 2019 $ 3,385 2020 3,385 2021 3,385 2022 2,490 2023 669 Total $ 13,314 |
Schedule of amounts incurred and charged to interest expenses | The following table presents amounts that have been incurred and charged to interest expense: For the years ended December 31, (in thousands) 2018 2017 2016 Cash payments for interest $ 54,969 $ 92,700 $ 89,726 Amortization of debt issuance costs and other adjustments 3,655 3,968 3,922 Change in accrued interest 268 (6,139 ) (56 ) Interest costs incurred 58,892 90,529 93,592 Less capitalized interest (988 ) (1,152 ) (294 ) Total interest expense $ 57,904 $ 89,377 $ 93,298 |
Schedule of net presentation of the Company's long-term debt and debt issuance cost | The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,010 ) $ 446,990 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,354 ) 346,646 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 190,000 — 190,000 — — — Total $ 990,000 $ (6,364 ) $ 983,636 $ 800,000 $ (8,145 ) $ 791,855 _____________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.0 million and $6.0 million as of December 31, 2018 and 2017 |
Stockholders' equity, stock-b_2
Stockholders' equity, stock-based compensation and defined contribution plan (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of restricted stock award activity | The following table reflects the restricted stock award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average grant-date fair value (per award) Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 Granted 1,237 $ 13.87 Forfeited (302 ) $ 12.87 Vested (1,644 ) $ 13.75 Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,328 $ 8.34 Forfeited (367 ) $ 10.13 Vested (1) (1,934 ) $ 11.92 Outstanding as of December 31, 2018 4,196 $ 9.91 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2018 was $16.6 million |
Schedule of stock option award activity | The following table reflects the stock option award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average exercise price and weighted-average remaining contractual term) Stock Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Granted 391 $ 14.12 Exercised (54 ) $ 7.43 Expired or canceled (60 ) $ 20.41 Outstanding as of December 31, 2017 2,647 $ 12.70 7.12 Exercised (1) (21 ) $ 4.10 Expired or canceled (53 ) $ 18.92 Forfeited (40 ) $ 9.23 Outstanding as of December 31, 2018 2,533 $ 12.69 5.99 Vested and exercisable as of December 31, 2018 (2) 1,697 $ 14.75 5.32 Expected to vest as of December 31, 2018 (3) 836 $ 8.53 7.34 _____________________________________________________________________________ (1) The total intrinsic value of exercised stock option awards for the year ended December 31, 2018 was $0.1 million . (2) The vested and exercisable stock option awards as of December 31, 2018 had no aggregate intrinsic value. (3) The stock option awards expected to vest as of December 31, 2018 had no |
Schedule of fair value of stock option awards granted assumptions | The assumptions used to estimate the fair value of stock option awards granted as of the dates presented are as follows: February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.14 % 1.58 % 1.44 % Expected option life (2) 6.25 years 6.25 years 6.25 years Expected volatility (3) 60.84 % 61.94 % 61.34 % Fair value per stock option award $ 8.22 $ 9.75 $ 4.44 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3) |
Schedule of vesting rights options | In accordance with the LTIP and stock option agreement, the stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % |
Schedule of performance share award activity | The following table reflects the performance share award activity for the years ended December 31, 2016 , 2017 and 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share Weighted-average Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Outstanding as of December 31, 2016 2,325 $ 18.35 Granted 696 $ 18.96 Forfeited (76 ) $ 18.12 Vested (1) (200 ) $ 28.56 Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (2) 1,389 $ 9.22 Forfeited (244 ) $ 14.93 Vested (3) (454 ) $ 16.23 Outstanding as of December 31, 2018 3,436 $ 13.74 _____________________________________________________________________________ (1) These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and market criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017. (2) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $9.22 per unit grant-date fair value consists of a (i) $10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. As of December 31, 2018, the estimated probability of how many shares will be earned at the end of the three-year performance period was estimated to be 50% , resulting in expense of $4.18 per unit for the (.50) ROACE Factor for the year ended December 31, 2018. The grant-date fair value of the market criteria portion of the award is locked in at $10.08 per unit for the combined (.25) RTSR Factor and (.25) ATSR Factor and, as a result, the expense for the total award is $7.13 per unit for the year ended December 31, 2018. (3) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% |
Schedule of fair value of performance share awards granted assumptions | The assumptions used to estimate the fair value of the performance share awards granted as of the dates presented are as follows: February 16, 2018 (3) February 17, 2017 May 25, 2016 April 1, 2016 Risk-free interest rate (1) 2.34 % 1.44 % 1.02 % 0.87 % Dividend yield — % — % — % — % Expected volatility (2) 65.49 % 74.00 % 74.73 % 71.54 % Closing stock price on grant date $ 8.36 $ 14.12 $ 12.36 $ 7.71 Fair value per performance share award $ 10.08 $ 18.96 $ 17.86 $ 9.83 _____________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) These are the assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted. The market criteria portion of the performance share award represents 50% |
Schedule of stock-based compensation expense | The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Restricted stock award compensation $ 25,271 $ 22,223 $ 21,609 Stock option award compensation 3,862 4,762 4,519 Performance share award compensation 15,192 16,312 9,112 Total stock-based compensation, gross 44,325 43,297 35,240 Less amounts capitalized in evaluated oil and natural gas properties (7,929 ) (7,563 ) (6,011 ) Total stock-based compensation, net $ 36,396 $ 35,734 $ 29,229 |
Schedule of costs recognized for defined contribution plan | The following table presents the cost recognized for the Company's defined contribution plan for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Contributions $ 2,156 $ 1,929 $ 1,789 |
Net income (loss) per common _2
Net income (loss) per common share (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share | The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2018 2017 2016 Net income (loss) (numerator): Net income (loss)—basic and diluted $ 324,595 $ 548,974 $ (260,739 ) Weighted-average common shares outstanding (denominator): Basic (1) 232,339 239,096 225,512 Non-vested restricted stock awards (2) 813 880 — Outstanding stock option awards (3) 20 122 — Non-vested performance share awards (4) — 24 — Diluted 233,172 240,122 225,512 Net income (loss) per common share: Basic $ 1.40 $ 2.30 $ (1.16 ) Diluted $ 1.39 $ 2.29 $ (1.16 ) _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share was computed taking into account share repurchases that occurred during the year ended December 31, 2018 and equity offerings that occurred during the year ended December 31, 2016. See Notes 8.a and 8.b for additional discussion of the Company's share repurchase program and equity offerings, respectively. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these non-vested restricted stock awards would be anti-dilutive mainly due to the grant-date fair value per common share for the awards being greater than the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the year ended December 31, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 8.c |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivatives terminated | The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 |
Schedule of open positions and derivatives in place | The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through December 31, 2018 , and represents derivatives in place through December 2021 on annual production volumes : Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 730,000 366,000 365,000 Weighted-average price ($/Bbl) $ 14.07 $ 13.60 $ 13.02 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 182,500 — — Weighted-average price ($/Bbl) $ 46.62 $ — $ — Total NGL volume hedged (Bbl) 912,500 366,000 365,000 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 16,425,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 ) |
Fair value measurements (Tables
Fair value measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis | The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in the "Derivatives" line items on the consolidated balance sheets as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the As of December 31, 2018: Assets Current: Oil derivatives $ — $ 44,425 $ — $ 44,425 $ (7,907 ) $ 36,518 NGL derivatives — 1,974 — 1,974 — 1,974 Natural gas derivatives — 18,991 — 18,991 (3,267 ) 15,724 Oil derivative deferred premiums — — — — (14,381 ) (14,381 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 10,626 $ — $ 10,626 $ — $ 10,626 NGL derivatives — 1,024 — 1,024 — 1,024 Natural gas derivatives — 108 — 108 (728 ) (620 ) Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,059 ) $ — $ (9,059 ) $ 7,907 $ (1,152 ) NGL derivatives — — — — — — Natural gas derivatives — (7,290 ) — (7,290 ) 3,267 (4,023 ) Oil derivative deferred premiums — — (16,565 ) (16,565 ) 14,381 (2,184 ) Natural gas derivative deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — NGL derivatives — — — — — — Natural gas derivatives — (728 ) — (728 ) 728 — Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 60,071 $ (16,565 ) $ 43,506 $ — $ 43,506 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets As of December 31, 2017: Assets Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) |
Actual cash payments required for deferred premium contracts | The following table presents payments required for derivative deferred premiums as of December 31, 2018 for the calendar years presented: (in thousands) December 31, 2018 2019 $ 15,502 2020 1,295 Total $ 16,797 |
Summary of changes in assets classified as Level 3 measurements | A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2018 2017 2016 Balance of Level 3 at beginning of year $ (28,683 ) $ (8,998 ) $ (14,619 ) Change in net present value of derivative deferred premiums (1) (694 ) (394 ) (232 ) Purchases and settlements of derivative deferred premiums: Purchases (7,523 ) (25,733 ) (7,715 ) Settlements (2) 20,335 6,442 13,568 Balance of Level 3 at end of year $ (16,565 ) $ (28,683 ) $ (8,998 ) _____________________________________________________________________________ (1) These amounts are included in the "Interest expense" line item in the consolidated statements of operations. (2) The amount for the year ended December 31, 2016 includes $3.9 million |
Schedule of carrying amounts and fair value of debt | The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2018 December 31, 2017 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2022 Notes $ 450,000 $ 402,885 $ 450,000 $ 454,500 March 2023 Notes 350,000 316,624 350,000 364,105 Senior Secured Credit Facility 190,000 190,054 — — Total $ 990,000 $ 909,563 $ 800,000 $ 818,605 _____________________________________________________________________________ (1) The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the as of December 31, 2018 and 2017 Level 1 fair value hierarchy quoted market price for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2018 was estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments. See Note 10.a |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of income tax expense | The following table presents the federal and state income taxes included in the income tax expense "Current" and "Deferred" line items in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Current income tax benefit: Federal $ — $ — $ — State 807 (1,800 ) — Deferred income tax expense: Federal — — — State (5,056 ) — — Total income tax expense $ (4,249 ) $ (1,800 ) $ — |
Schedule of AMT credit carryforwards | The following table presents the expected years in which the Company's AMT credit carryforward will be refunded: (in thousands) December 31, 2018 2019 $ 2,408 2020 1,203 2021 602 2022 602 AMT credit carryforward $ 4,815 |
Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations | Income tax expense differed from amounts computed by applying the applicable federal income tax rate of 21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2018 2017 2016 Income tax (expense) benefit computed by applying the statutory rate $ (69,057 ) $ (192,141 ) $ 91,259 Decrease (increase) in deferred tax valuation allowance 74,289 417,518 (86,569 ) State income tax and change in valuation allowance (9,070 ) 696 (370 ) Change in tax rate applicable to net deferred tax assets — (226,263 ) — Stock-based compensation tax deficiency — (64 ) (4,144 ) Other items (411 ) (1,546 ) (176 ) Total income tax expense $ (4,249 ) $ (1,800 ) $ — |
Schedule of net deferred tax assets | The following table presents significant components of the Company's net deferred tax liability as of December 31: (in thousands) 2018 2017 Net operating loss carryforward $ 392,276 $ 355,100 Oil and natural gas properties, midstream service assets and other fixed assets (168,031 ) (80,153 ) Stock-based compensation 19,845 14,025 Derivatives (8,188 ) 3,788 Gain (loss) on sale of assets (7,693 ) 40,177 Other 3,997 8,465 Net deferred tax asset before valuation allowance 232,206 341,402 Valuation allowance (237,262 ) (341,402 ) Net deferred tax liability $ (5,056 ) $ — |
Summary of federal net operating loss carryforwards | The following presents the Company's federal net operating loss carryforwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2018 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,406,873 Total $ 1,859,821 |
Commitments and contingencies (
Commitments and contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum annual lease commitments | The Company leases office space under operating leases expiring on various dates through 2027 . The following table presents future minimum rental payments required: (in thousands) December 31, 2018 2019 $ 3,092 2020 3,179 2021 3,128 2022 2,560 2023 1,358 Thereafter 4,556 Total future minimum rental payments required $ 17,873 |
Schedule of rent expense | The following table presents rent expense: For the years ended December 31, (in thousands) 2018 2017 2016 Rent expense $ 2,735 $ 2,696 $ 2,664 |
Related parties (Tables)
Related parties (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Oil and gas related party transactions | The following table presents accounts payable and accrued liabilities related to H&P included in the consolidated balance sheets: (in thousands) December 31, 2018 December 31, 2017 Accounts payable and accrued liabilities $ 399 $ — The following table presents the capital expenditures for oil and natural gas properties related to H&P included in the consolidated statements of cash flows: For the years ended December 31, (in thousands) 2018 2017 2016 Oil and natural gas properties $ 3,040 $ — $ — |
Subsidiary guarantors (Tables)
Subsidiary guarantors (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Condensed Financial Information Disclosure [Abstract] | |
Schedule of condensed consolidating balance sheet | Condensed consolidating balance sheet December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 83,424 $ 10,897 $ — $ 94,321 Other current assets 97,045 1,386 — 98,431 Oil and natural gas properties, net 2,043,009 9,113 (22,551 ) 2,029,571 Midstream service assets, net — 130,245 — 130,245 Other fixed assets, net 39,751 68 — 39,819 Investment in subsidiaries 128,380 — (128,380 ) — Other noncurrent assets, net 23,783 4,135 — 27,918 Total assets $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Accounts payable and accrued liabilities $ 54,167 $ 15,337 $ — $ 69,504 Other current liabilities 121,297 9,664 — 130,961 Long-term debt, net 983,636 — — 983,636 Other noncurrent liabilities 59,511 2,463 — 61,974 Total stockholders' equity 1,196,781 128,380 (150,931 ) 1,174,230 Total liabilities and stockholders' equity $ 2,415,392 $ 155,844 $ (150,931 ) $ 2,420,305 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Total stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 |
Schedule of condensed consolidating statement of operations | Condensed consolidating statement of operations For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 809,396 $ 365,633 $ (69,254 ) $ 1,105,775 Total costs and expenses 466,895 353,806 (63,418 ) 757,283 Operating income 342,501 11,827 (5,836 ) 348,492 Interest expense (57,904 ) — — (57,904 ) Other non-operating income (expense), net 50,083 (1,049 ) (10,778 ) 38,256 Income before income tax 334,680 10,778 (16,614 ) 328,844 Total income tax expense (4,249 ) — — (4,249 ) Net income $ 330,431 $ 10,778 $ (16,614 ) $ 324,595 Condensed consolidating statement of operations For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 623,028 $ 266,455 $ (67,321 ) $ 822,162 Total costs and expenses 376,938 254,398 (58,846 ) 572,490 Operating income 246,090 12,057 (8,475 ) 249,672 Interest expense (89,377 ) — — (89,377 ) Gain on sale of investment in equity method investee (see Note 4.c) — 405,906 — 405,906 Other non-operating income (expense), net 402,536 8,083 (426,046 ) (15,427 ) Income before income tax 559,249 426,046 (434,521 ) 550,774 Total income tax expense (1,800 ) — — (1,800 ) Net income $ 557,449 $ 426,046 $ (434,521 ) $ 548,974 Condensed consolidating statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense (93,298 ) — — (93,298 ) Other non-operating income (expense), net (73,669 ) 9,381 (15,191 ) (79,479 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Total income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 ) |
Schedule of condensed consolidating statement of cash flows | Condensed consolidating statement of cash flows For the year ended December 31, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 528,281 $ 20,301 $ (10,778 ) $ 537,804 Change in investments between affiliates 5,175 (15,953 ) 10,778 — Capital expenditures and other (686,608 ) (6,003 ) — (692,611 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 1,655 — 1,655 Net cash provided by financing activities 86,144 — — 86,144 Net decrease in cash and cash equivalents (67,008 ) — — (67,008 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 45,150 $ 1 $ — $ 45,151 Condensed consolidating statement of cash flows For the year ended December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 778,851 $ 32,109 $ (426,046 ) $ 384,914 Change in investments between affiliates 383,613 (809,659 ) 426,046 — Capital expenditures and other (482,500 ) (52,065 ) — (534,565 ) Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) — 829,615 — — 829,615 Net cash used in financing activities (600,477 ) — — (600,477 ) Net increase in cash and cash equivalents 79,487 — — 79,487 Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 112,158 $ 1 $ — $ 112,159 Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672 |
Subsequent events (Tables)
Subsequent events (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Schedule of subsequent derivatives entered into | The following table summarizes open derivative positions as of December 31, 2018 for derivatives that were entered into through February 13, 2019 , and represents derivatives in place through December 2021 on annual production volumes: Year 2019 Year 2020 Year 2021 Oil: Puts: Hedged volume (Bbl) 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 47.45 $ 45.00 $ — Hedged volume with deferred premium (Bbl) 4,745,000 — — Weighted-average deferred premium price ($/Bbl) $ 3.21 $ — $ — Swaps: Hedged volume (Bbl) 657,000 695,400 — Weighted-average price ($/Bbl) $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI NYMEX: Hedged volume (Bbl) 1,840,000 — — Weighted-average price ($/Bbl) $ (2.89 ) $ — $ — WTI Midland to WTI formula basis: Hedged volume (Bbl) 552,000 — — Weighted-average price ($/Bbl) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 2,233,000 366,000 912,500 Weighted-average price ($/Bbl) $ 14.21 $ 13.60 $ 12.01 Swaps - Non-TET Propane: Hedged volume (Bbl) 1,736,800 1,244,400 730,000 TABLE CONTINUES ON NEXT PAGE Year 2019 Year 2020 Year 2021 Weighted-average price ($/Bbl) $ 27.97 $ 26.58 $ 25.52 Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 668,000 439,200 255,500 Weighted-average price ($/Bbl) $ 30.73 $ 28.69 $ 27.72 Swaps - Non-TET Isobutane: Hedged volume (Bbl) 167,000 109,800 67,525 Weighted-average price ($/Bbl) $ 31.08 $ 29.99 $ 28.79 Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 583,300 402,600 237,250 Weighted-average price ($/Bbl) $ 45.83 $ 45.15 $ 44.31 Total NGL volume hedged (Bbl) 5,388,100 2,562,000 2,202,775 Natural gas: Henry Hub NYMEX Swaps: Hedged volume (MMBtu) 21,900,000 — — Weighted-average price ($/MMBtu) $ 3.23 $ — $ — Basis Swaps: Hedged volume (MMBtu) 39,055,000 32,574,000 23,360,000 Weighted-average price ($/MMBtu) $ (1.51 ) $ (0.76 ) $ (0.47 ) |
Supplemental oil, NGL and nat_2
Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of costs incurred in the acquisition, exploration and development of oil and natural gas assets | The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: For the years ended December 31, (in thousands) 2018 2017 2016 Property acquisition costs: Evaluated $ 15,072 $ — $ 5,905 Unevaluated 2,790 — 119,923 Exploration costs 23,884 36,257 41,333 Development costs 607,790 560,919 298,942 Total costs incurred $ 649,536 $ 597,176 $ 466,103 |
Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment | The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment: (in thousands) December 31, 2018 December 31, 2017 Gross capitalized costs: Evaluated properties $ 6,752,631 $ 6,070,940 Unevaluated properties not being depleted 130,957 175,865 Total gross capitalized costs 6,883,588 6,246,805 Less accumulated depletion and impairment (4,854,017 ) (4,657,466 ) Net capitalized costs $ 2,029,571 $ 1,589,339 |
Summary of oil and natural gas property costs not being amortized by year | The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2018 , by year in which such costs were incurred: (in thousands) 2018 2017 2016 2015 and prior Total Unevaluated properties not being depleted $ 38,815 $ 15,076 $ 56,826 $ 20,240 $ 130,957 |
Summary of results of oil and natural gas producing activities (excluding corporate overhead and interest costs) | The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs): For the years ended December 31, (in thousands) 2018 2017 2016 Revenues: Oil, NGL and natural gas sales $ 808,530 $ 621,507 $ 426,485 Production costs: Lease operating expenses 91,289 75,049 75,327 Production and ad valorem taxes 49,457 37,802 28,586 Transportation and marketing expenses 11,704 — — Total production costs 152,450 112,851 103,913 Other costs: Depletion 196,458 143,592 134,105 Accretion of asset retirement obligations 4,233 3,567 3,274 Impairment expense — — 161,064 Income tax expense (1) 4,554 — — Total other costs 205,245 147,159 298,443 Results of operations $ 450,835 $ 361,497 $ 24,129 _____________________________________________________________________________ (1) During each of the years ended December 31, 2018, 2017 and 2016, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax expense was computed utilizing the Company's effective rate of 1% for the year ended December 31, 2018 and 0% |
Schedule of analysis of change in estimated quantities of oil and natural gas reserves located within United States | The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2018 , 2017 and 2016, all of which are located within the U.S. Year ended December 31, 2018 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 79,413 67,371 414,592 215,883 Revisions of previous estimates (20,921 ) 11,089 72,028 2,173 Extensions, discoveries and other additions 13,330 15,112 93,762 44,069 Acquisitions of reserves in place 596 457 2,810 1,521 Divestitures of reserves in place (349 ) (123 ) (756 ) (598 ) Production (10,175 ) (7,259 ) (44,680 ) (24,881 ) End of year 61,894 86,647 537,756 238,167 Proved developed reserves: Beginning of year 68,877 60,441 371,946 191,309 End of year 55,893 79,241 491,828 217,105 Proved undeveloped reserves: Beginning of year 10,536 6,930 42,646 24,574 End of year 6,001 7,406 45,928 21,062 Year ended December 31, 2017 Oil NGL (MBbl) Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 63,940 50,350 316,857 167,100 Revisions of previous estimates 9,818 13,158 74,247 35,351 Extensions, discoveries and other additions 15,250 9,711 59,759 34,921 Divestitures of reserves in place (120 ) (48 ) (299 ) (218 ) Production (9,475 ) (5,800 ) (35,972 ) (21,270 ) End of year 79,413 67,371 414,592 215,883 Proved developed reserves: Beginning of year 53,156 42,950 270,291 141,155 End of year 68,877 60,441 371,946 191,309 Proved undeveloped reserves: Beginning of year 10,784 7,400 46,566 25,945 End of year 10,536 6,930 42,646 24,574 Year ended December 31, 2016 Oil NGL Natural gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Acquisitions of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945 |
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Future cash inflows $ 6,266,862 $ 5,777,533 $ 3,548,567 Future production costs (1,977,401 ) (1,675,837 ) (1,238,369 ) Future development costs (257,310 ) (307,689 ) (290,505 ) Future income tax expenses (226,183 ) (237,153 ) — Future net cash flows 3,805,968 3,556,854 2,019,693 10% discount for estimated timing of cash flows (1,691,731 ) (1,786,533 ) (1,041,199 ) Standardized measure of discounted future net cash flows $ 2,114,237 $ 1,770,321 $ 978,494 |
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves: For the years ended December 31, (in thousands) 2018 2017 2016 Standardized measure of discounted future net cash flows, beginning of year $ 1,770,321 $ 978,494 $ 830,747 Changes in the year resulting from: Sales, less production costs (656,080 ) (508,656 ) (322,573 ) Revisions of previous quantity estimates (179,912 ) 289,150 179,297 Extensions, discoveries and other additions 521,605 296,129 133,472 Net change in prices and production costs 365,902 474,831 (80,102 ) Changes in estimated future development costs 7,246 10,989 22,153 Previously estimated development costs incurred during the period 207,865 192,332 189,085 Acquisitions of reserves in place 11,411 — 3,422 Divestitures of reserves in place (6,015 ) (793 ) — Accretion of discount 181,693 97,849 83,075 Net change in income taxes (10,340 ) (46,610 ) — Timing differences and other (99,459 ) (13,394 ) (60,082 ) Standardized measure of discounted future net cash flows, end of year $ 2,114,237 $ 1,770,321 $ 978,494 |
Supplemental quarterly financ_2
Supplemental quarterly financial data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of results of operations by quarter | The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2018 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 259,696 $ 351,046 $ 279,746 $ 215,287 Operating income 93,192 94,767 104,410 56,123 Net income 86,520 33,452 55,050 149,573 Net income per common share: Basic $ 0.36 $ 0.14 $ 0.24 $ 0.65 Diluted $ 0.36 $ 0.14 $ 0.24 $ 0.65 Year ended December 31, 2017 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter (1) Revenues $ 189,006 $ 187,001 $ 205,818 $ 240,337 Operating income 51,326 52,061 60,452 85,833 Net income 68,276 61,110 11,027 408,561 Net income per common share: Basic $ 0.29 $ 0.26 $ 0.05 $ 1.71 Diluted $ 0.28 $ 0.25 $ 0.05 $ 1.70 _____________________________________________________________________________ (1) |
Organization (Details)
Organization (Details) | 12 Months Ended |
Dec. 31, 2018segment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of segments | 1 |
Basis of presentation and sig_4
Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Accounts receivable | ||
Term of past due balances to be reviewed individually for collectability (in days) | 90 days | |
Oil, NGL and natural gas sales | $ 44,958 | $ 67,116 |
Joint operations, net | 16,772 | 8,780 |
Sales of purchased oil and other products | 10,244 | 19,504 |
Other | 22,347 | 5,245 |
Total accounts receivable | 94,321 | 100,645 |
Allowance for doubtful accounts of accounts receivable for joint operations | $ 100 | $ 100 |
Basis of presentation and sig_5
Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||
Total other current assets | $ 13,445 | $ 15,686 |
Basis of presentation and sig_6
Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||
Accrued interest payable | $ 18,281 | $ 18,013 |
Accrued compensation and benefits | 13,317 | 21,287 |
Deferred gain on sale of equity method investment | 0 | 20,144 |
Other accrued liabilities | 13,188 | 16,111 |
Total other current liabilities | $ 44,786 | $ 75,555 |
Basis of presentation and sig_7
Basis of presentation and significant accounting policies - Other noncurrent liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||
Deferred gain on sale of equity method investment | $ 0 | $ 120,974 |
Other accrued liabilities | 8,587 | 13,116 |
Total other noncurrent liabilities | $ 8,587 | $ 134,090 |
Basis of presentation and sig_8
Basis of presentation and significant accounting policies - Inventory (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Materials and supplies | |||
Impairment expense | $ 0 | $ 0 | $ 162,027,000 |
Materials and Supplies | Nonrecurring | Level 2 | |||
Materials and supplies | |||
Impairment expense | $ 0 | $ 0 | $ 1,000,000 |
Basis of presentation and sig_9
Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liability at beginning of year | $ 55,506 | $ 52,207 |
Liabilities added due to acquisitions, drilling, midstream service asset construction and other | 995 | 616 |
Accretion expense | 4,472 | 3,791 |
Liabilities settled upon plugging and abandonment | (2,848) | (408) |
Liabilities removed due to sale of property | (1,243) | (871) |
Revision of estimates | 0 | 171 |
Liability at end of year | $ 56,882 | $ 55,506 |
Basis of presentation and si_10
Basis of presentation and significant accounting policies - Fees received for the operation of jointly-owned oil and natural gas properties (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
General and administrative expense | |||
Fees received for the operation of jointly-owned oil and natural gas properties | $ 2,507 | $ 2,549 | $ 2,477 |
Basis of presentation and si_11
Basis of presentation and significant accounting policies - Income taxes (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||
Unrecognized tax benefits | $ 0 | $ 0 |
Basis of presentation and si_12
Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Non-cash investing information: | |||
(Decrease) increase in accrued capital expenditures | $ (52,746) | $ 51,876 | $ (31,027) |
Change in accrued capital contribution to equity method investee | 0 | 0 | (27,583) |
Capitalized stock-based compensation | 7,929 | 7,563 | 6,011 |
Capitalized asset retirement cost | 995 | 787 | 3,660 |
Supplemental cash flow information: | |||
Cash paid for interest, net of capitalized interest | 53,981 | 91,548 | 89,432 |
Capitalized interest | 988 | 1,152 | 294 |
Cash paid for income taxes | $ 735 | $ 5,500 | $ 0 |
Recently issued or adopted ac_2
Recently issued or adopted accounting pronouncements (Details) - Scenario, Forecast - Accounting Standards Update 2016-02 [Member] $ in Millions | Jan. 01, 2019USD ($) |
Minimum | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Increase in assets | $ 25 |
Increase in liabilities | 25 |
Maximum | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Increase in assets | 40 |
Increase in liabilities | $ 40 |
Acquisitions and divestitures -
Acquisitions and divestitures - 2018 Acquisitions of evaluated and unevaluated oil and natural gas properties (Details) - Leasehold interests and Working interests $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($)aproperty | |
Business Acquisition [Line Items] | |
Area of land (in acres) | a | 966 |
Number of real estate properties | property | 48 |
Oil and natural gas properties | $ | $ 17.5 |
Acquisitions and divestitures_2
Acquisitions and divestitures - 2018 Divestitures of evaluated and unevaluated oil and natural gas properties and midstream service assets (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($)aproperty | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Loss on disposal of assets, net | $ 5,798 | $ 1,306 | $ 790 |
Disposal group, disposed of by sale, not discontinued operations | Glasscock and Howard | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Area of land (in acres) | a | 3,070 | ||
Number of real estate properties | property | 24 | ||
Proceeds after transaction costs | $ 12,000 | ||
Oil and gas property, disposal consideration | 11,500 | ||
Loss on disposal of assets, net | $ 1,000 |
Acquisitions and divestitures_3
Acquisitions and divestitures - 2017 Medallion sale (Details) - USD ($) $ in Thousands | Feb. 01, 2018 | Oct. 30, 2017 | Feb. 01, 2018 | Oct. 29, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Contributions to Medallion | $ 0 | $ 31,808 | $ 69,609 | ||||
Minimum volume commitments | 4,700 | 1,100 | 2,200 | ||||
Net proceeds from disposition of equity method investee | 1,655 | 829,615 | $ 0 | ||||
Accounts receivable, net | $ 94,321 | 100,645 | |||||
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Ownership percentage | 49.00% | ||||||
Ownership percentage held by investment partner | 51.00% | ||||||
Percentage required for key decisions | 75.00% | ||||||
Percent of ownership interest sold | 100.00% | ||||||
Ownership percentage sold | 49.00% | ||||||
Net proceeds from disposition of equity method investee | $ 1,700 | $ 829,600 | $ 831,300 | ||||
Maximum loss exposure amount | $ 141,100 | ||||||
Global Infrastructure Partners | Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary | |||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||
Cash consideration received in sale | $ 1,825,000 |
Acquisitions and divestitures_4
Acquisitions and divestitures - 2017 divestiture of evaluated and unevaluated oil and natural gas properties (Details) - Midland Basin - Disposal group, disposed of by sale, not discontinued operations $ in Millions | Jan. 31, 2017USD ($)aproperty |
Business Acquisition [Line Items] | |
Area of land (in acres) | a | 2,900 |
Number of real estate properties | property | 16 |
Sales Price | $ 59.7 |
Proceeds after transaction costs | $ 59.5 |
Acquisitions and divestitures_5
Acquisitions and divestitures - 2016 acquisitions of evaluated and unevaluated oil and natural gas properties (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)aBoeproperty | |
Business Acquisition [Line Items] | |||
Cash consideration | $ 17,538 | $ 0 | $ 124,660 |
Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Area of land (in acres) | a | 9,200 | ||
Number of real estate properties | property | 81 | ||
Production, barrels of oil equivalents | Boe | 300 | ||
Sale price | $ 124,700 | ||
Total assets acquired | 125,828 | ||
Asset retirement obligations | (1,105) | ||
Net assets acquired | 124,723 | ||
Cash consideration | 124,723 | ||
Evaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Fair value of net assets: | 4,800 | ||
Unevaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Fair value of net assets: | 119,923 | ||
Asset retirement cost | Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Fair value of net assets: | $ 1,105 |
Revenue recognition - Impact of
Revenue recognition - Impact of ASC 606 adoption (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | $ 215,287 | $ 279,746 | $ 351,046 | $ 259,696 | $ 240,337 | $ 205,818 | $ 187,001 | $ 189,006 | $ 1,105,775 | $ 822,162 | $ 597,378 |
Other operating expenses | 4,472 | 4,931 | 5,692 | ||||||||
Net income | $ 149,573 | $ 55,050 | $ 33,452 | $ 86,520 | $ 408,561 | $ 11,027 | $ 61,110 | $ 68,276 | 324,595 | 548,974 | (260,739) |
As computed under ASC 605 | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Other operating expenses | 9,145 | ||||||||||
Net income | 324,595 | ||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease) | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Other operating expenses | (4,673) | ||||||||||
Net income | 0 | ||||||||||
Oil sales | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | 605,197 | 445,012 | 318,466 | ||||||||
Oil sales | As computed under ASC 605 | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | 607,870 | ||||||||||
Oil sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease) | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | (2,673) | ||||||||||
NGL sales | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | 149,843 | 101,438 | 56,982 | ||||||||
NGL sales | As computed under ASC 605 | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | 150,822 | ||||||||||
NGL sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease) | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | (979) | ||||||||||
Natural gas sales | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | 53,490 | $ 75,057 | $ 51,037 | ||||||||
Natural gas sales | As computed under ASC 605 | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | 54,511 | ||||||||||
Natural gas sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Increase/(decrease) | |||||||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||||||
Revenues | $ (1,021) |
Revenue recognition - Additiona
Revenue recognition - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Deferred gain to be recognized in retained earnings | $ (1,203,395) | $ (1,669,108) |
Revenue, Practical Expedient, Remaining Performance Obligation, Description | the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less | |
Minimum | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Settlement statements and payment period | 30 days | |
Maximum | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Settlement statements and payment period | 90 days | |
Medallion Gathering and Processing LLC | Variable Interest Entity, not primary beneficiary | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Maximum loss exposure amount | 141,100 | |
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Deferred gain to be recognized in retained earnings | $ 141,100 |
Property and equipment - Oil an
Property and equipment - Oil and natural gas properties (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)$ / MMBTU$ / MMcf$ / bbl$ / Boe | Dec. 31, 2017USD ($)$ / MMBTU$ / MMcf$ / bbl$ / Boe | Dec. 31, 2016USD ($)$ / MMBTU$ / MMcf$ / bbl$ / Boe | |
Property, Plant and Equipment [Line Items] | |||
Evaluated properties | $ 6,752,631,000 | $ 6,070,940,000 | |
Unevaluated properties not being depleted | 130,957,000 | 175,865,000 | |
Less accumulated depletion and impairment | (4,854,017,000) | (4,657,466,000) | |
Oil and natural gas properties, net | 2,029,571,000 | 1,589,339,000 | |
Depletion of evaluated oil and natural gas properties | $ 196,458,000 | $ 143,592,000 | $ 134,105,000 |
Depletion per BOE sold (in USD per BOE) | $ / Boe | 7.90 | 6.75 | 7.39 |
Discount rate used in calculating full cost ceiling (as a percent) | 10.00% | ||
Non-cash full cost ceiling impairment | $ 0 | $ 0 | $ 161,100,000 |
Capitalized employee-related costs | $ 25,372,000 | $ 25,553,000 | $ 19,222,000 |
Crude Oil | |||
Property, Plant and Equipment [Line Items] | |||
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl | 62.04 | 47.79 | 39.25 |
Realized prices (in USD per barrel or Mcf) | $ / bbl | 59.29 | 46.34 | 37.44 |
Natural Gas Liquids | |||
Property, Plant and Equipment [Line Items] | |||
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl | 31.46 | 26.13 | 18.24 |
Realized prices (in USD per barrel or Mcf) | $ / bbl | 21.42 | 18.45 | 11.72 |
Natural Gas | |||
Property, Plant and Equipment [Line Items] | |||
Benchmark prices (in USD per barrel or MMBtu) | $ / MMBTU | 1.76 | 2.63 | 2.33 |
Realized prices (in USD per barrel or Mcf) | $ / MMcf | 1.38 | 2.06 | 1.78 |
Property and equipment - Midstr
Property and equipment - Midstream service assets (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Total midstream service assets, net | $ 130,245,000 | $ 138,325,000 | |
Depletion, depreciation and amortization | 212,677,000 | 158,389,000 | $ 148,339,000 |
Impairment expense | 0 | 0 | 162,027,000 |
Midstream service assets | |||
Property, Plant and Equipment [Line Items] | |||
Midstream service assets | 172,308,000 | 171,427,000 | |
Less accumulated depreciation and impairment | (42,063,000) | (33,102,000) | |
Total midstream service assets, net | 130,245,000 | 138,325,000 | |
Depletion, depreciation and amortization | 10,100,000 | 8,900,000 | 8,300,000 |
Impairment expense | $ 0 | $ 0 | $ 0 |
Midstream service assets | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 10 years | ||
Midstream service assets | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 20 years |
Property and equipment - Other
Property and equipment - Other fixed assets (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Depreciation, depletion and amortization | $ 212,677 | $ 158,389 | $ 148,339 |
Total other fixed assets, net | 39,819 | 40,721 | |
Other fixed assets | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation, depletion and amortization | 6,100 | 5,900 | $ 5,900 |
Vehicles | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 10,660 | 9,661 | |
Computer hardware and software | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 9,222 | 11,696 | |
Buildings | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 7,804 | 7,618 | |
Leasehold improvements | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 7,608 | 7,590 | |
Aircraft | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 6,402 | 6,402 | |
Other | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 3,735 | 5,990 | |
Depreciable total, net | |||
Property, Plant and Equipment [Line Items] | |||
Other fixed assets, net | 45,431 | 48,957 | |
Less accumulated depreciation and impairment | (23,871) | (23,150) | |
Total other fixed assets, net | 21,560 | 25,807 | |
Land | |||
Property, Plant and Equipment [Line Items] | |||
Total other fixed assets, net | $ 18,259 | $ 14,914 | |
Minimum | Other fixed assets | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 3 years | ||
Maximum | Other fixed assets | |||
Property, Plant and Equipment [Line Items] | |||
Useful life | 10 years |
Debt - March 2023 Notes (Detail
Debt - March 2023 Notes (Details) - Senior Notes - March 2023 Notes | Mar. 18, 2015USD ($) |
Debt Instrument [Line Items] | |
Face amount of debt | $ 350,000,000 |
Stated rate | 6.25% |
Net proceeds from offering | $ 343,600,000 |
Anytime on or after March 15, 2018 | |
Debt Instrument [Line Items] | |
Redemption price | 104.688% |
Debt - January 2022 Notes (Deta
Debt - January 2022 Notes (Details) - Senior Notes - January 2022 Notes | Jan. 23, 2014USD ($) |
Debt Instrument [Line Items] | |
Face amount of debt | $ 450,000,000 |
Stated rate | 5.625% |
Net proceeds from offering | $ 442,200,000 |
Before March 15, 2018 | |
Debt Instrument [Line Items] | |
Redemption price | 101.406% |
Debt - May 2022 Notes (Details)
Debt - May 2022 Notes (Details) - USD ($) | Nov. 29, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Apr. 27, 2012 |
Debt Instrument [Line Items] | |||||
Loss on early redemption of debt | $ 0 | $ 23,761,000 | $ 0 | ||
Senior Notes | May 2022 Notes | |||||
Debt Instrument [Line Items] | |||||
Face amount of debt | $ 500,000,000 | ||||
Repurchased amount | $ 500,000,000 | ||||
Stated rate | 7.375% | ||||
Redemption price | 103.688% | ||||
Loss on early redemption of debt | $ 23,800,000 |
Debt - Senior Secured Credit Fa
Debt - Senior Secured Credit Facility (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | ||
Unrestricted and unencumbered cash and cash equivalents maximum | $ 50,000,000 | |
Secured Debt | Minimum | Base Rate | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate | 0.25% | |
Secured Debt | Maximum | Base Rate | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate | 1.25% | |
Secured Debt | Line of Credit | ||
Debt Instrument [Line Items] | ||
Collateral as a percentage of present value of proved reserves | 85.00% | |
Current ratio requirement (not less than) | 1 | |
Consolidated interest coverage ratio (not less than) | 4.25 | |
Secured Debt | Senior Secured Credit Facility | ||
Debt Instrument [Line Items] | ||
Consolidated interest coverage ratio (not less than) | 2.50 | |
Secured Debt | Senior Secured Credit Facility | Minimum | ||
Debt Instrument [Line Items] | ||
Commitment fee on unused capacity | 0.375% | |
Secured Debt | Senior Secured Credit Facility | Minimum | London Interbank Offered Rate (LIBOR) | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate | 1.25% | |
Secured Debt | Senior Secured Credit Facility | Maximum | ||
Debt Instrument [Line Items] | ||
Commitment fee on unused capacity | 0.50% | |
Secured Debt | Senior Secured Credit Facility | Maximum | London Interbank Offered Rate (LIBOR) | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate | 2.25% | |
Line of Credit | Secured Debt | ||
Debt Instrument [Line Items] | ||
Borrowing capacity | $ 2,000,000,000 | |
Aggregate elected commitment | 1,300,000,000 | |
Current borrowing capacity | 1,200,000,000 | |
Line of credit | $ 190,000,000 | |
Line of credit, interest rate | 3.75% | |
Letters of credit | Secured Debt | ||
Debt Instrument [Line Items] | ||
Borrowing capacity | $ 80,000,000 | |
Letters of credit outstanding | $ 14,700,000 | $ 0 |
Debt - Debt issuance costs (Det
Debt - Debt issuance costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | |||
Payments for debt issuance costs | $ 2,469 | $ 4,732 | $ 0 |
Write-off of debt issuance costs | 0 | 0 | 842 |
Total debt issuance costs, including line of credit | 13,300 | 14,200 | |
Accumulated amortization | 24,200 | 20,800 | |
Future amortization expense of deferred loan costs | |||
2,019 | 3,385 | ||
2,020 | 3,385 | ||
2,021 | 3,385 | ||
2,022 | 2,490 | ||
2,023 | 669 | ||
Total | 13,314 | ||
Secured Debt | |||
Debt Instrument [Line Items] | |||
Write-off of debt issuance costs | $ 5,300 | ||
Line of Credit | |||
Debt Instrument [Line Items] | |||
Write-off of debt issuance costs | $ 0 | $ 800 |
Debt - Interest expense (Detail
Debt - Interest expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |||
Cash payments for interest | $ 54,969 | $ 92,700 | $ 89,726 |
Amortization of debt issuance costs and other adjustments | 3,655 | 3,968 | 3,922 |
Change in accrued interest | 268 | (6,139) | (56) |
Interest costs incurred | 58,892 | 90,529 | 93,592 |
Less capitalized interest | (988) | (1,152) | (294) |
Total interest expense | $ 57,904 | $ 89,377 | $ 93,298 |
Debt - Long-term debt, net (Det
Debt - Long-term debt, net (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Long-term debt | $ 990,000 | $ 800,000 |
Debt issuance costs, net | (6,364) | (8,145) |
Long-term debt, net | 983,636 | 791,855 |
Senior Notes | January 2022 Notes | ||
Debt Instrument [Line Items] | ||
Long-term debt | 450,000 | 450,000 |
Debt issuance costs, net | (3,010) | (3,987) |
Long-term debt, net | 446,990 | 446,013 |
Senior Notes | March 2023 Notes | ||
Debt Instrument [Line Items] | ||
Long-term debt | 350,000 | 350,000 |
Debt issuance costs, net | (3,354) | (4,158) |
Long-term debt, net | 346,646 | 345,842 |
Senior Secured Credit Facility | Line of Credit | ||
Debt Instrument [Line Items] | ||
Long-term debt | 190,000 | 0 |
Debt issuance costs, net | 0 | 0 |
Long-term debt, net | 190,000 | 0 |
Senior Secured Credit Facility | Line of Credit | Other Noncurrent Assets | ||
Debt Instrument [Line Items] | ||
Debt issuance costs, net | $ 7,000 | $ 6,000 |
Stockholders' equity, stock-b_3
Stockholders' equity, stock-based compensation and defined contribution plan - Share repurchase program (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Feb. 28, 2018 | |
Equity [Abstract] | ||
Share repurchase program, authorized amount | $ 200,000,000 | |
Shares repurchased (in shares) | 11,048,742 | |
Weighted-average price per repurchased share (in dollars per share) | $ 8.78 | |
Shares repurchased and retired, value | $ 97,100,000 |
Stockholders' equity, stock-b_4
Stockholders' equity, stock-based compensation and defined contribution plan - Equity offerings (Details) - USD ($) $ in Thousands | Aug. 09, 2016 | Jul. 19, 2016 | May 16, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Class of Stock [Line Items] | ||||||
Proceeds from issuance of common stock, net of offering costs | $ 0 | $ 0 | $ 276,052 | |||
Common Stock | ||||||
Class of Stock [Line Items] | ||||||
Stock issued during the period (in shares) | 13,000,000 | 10,925,000 | 0 | 0 | ||
Proceeds from issuance of common stock, net of offering costs | $ 136,300 | $ 119,300 | ||||
Over-Allotment Option | Common Stock | ||||||
Class of Stock [Line Items] | ||||||
Stock issued during the period (in shares) | 1,950,000 | |||||
Proceeds from issuance of common stock, net of offering costs | $ 20,500 |
Stockholders' equity, stock-b_5
Stockholders' equity, stock-based compensation and defined contribution plan - Additional Information (Details) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016$ / sharesshares | Dec. 31, 2018USD ($)installmentanniversariesshares | Dec. 31, 2017shares | Dec. 31, 2016shares | Dec. 31, 2015shares | |
401(k) Plan | |||||
Equity and stock-based compensation | |||||
Tax-deferred contributions of eligible employees as a percentage of their annual compensation | 100.00% | ||||
Employer matching contribution (as a percent) | 6.00% | ||||
Percentage of employer contributions vested upon receipt | 100.00% | ||||
Restricted stock awards | |||||
Equity and stock-based compensation | |||||
Unrecognized equity and stock-based compensation expense | $ | $ 20.5 | ||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 9 months 14 days | ||||
Options outstanding (in shares) | 4,196,000 | 3,169,000 | 3,878,000 | 2,539,000 | |
Restricted stock awards | One Year From Grant Date | |||||
Equity and stock-based compensation | |||||
Vesting rights | 33.00% | ||||
Restricted stock awards | Two Years from Grant Date | |||||
Equity and stock-based compensation | |||||
Vesting rights | 33.00% | ||||
Restricted stock awards | Three Years from Grant Date | |||||
Equity and stock-based compensation | |||||
Vesting rights | 34.00% | ||||
Stock option awards | |||||
Equity and stock-based compensation | |||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 6 months 3 days | ||||
Number of installments over which awards vest and are exercisable | installment | 4 | ||||
Number of anniversaries over which awards vest and are exercisable | anniversaries | 4 | ||||
Requisite service period (in years) | 4 years | ||||
Unrecognized stock-based compensation expense | $ | $ 3.9 | ||||
Post employment, vested awards expiration period (in years) | 1 year | ||||
Options, life of award (in years) | 10 years | ||||
Post employment, vested awards expiration period (in days) | 90 days | ||||
Performance unit awards | |||||
Equity and stock-based compensation | |||||
Options outstanding (in shares) | 3,436,000 | 2,745,000 | 2,325,000 | 874,000 | |
Long Term Incentive Plan | |||||
Equity and stock-based compensation | |||||
Number of shares authorized (in shares) | 24,350,000 | ||||
February 2014, February 2015, May 25, and April 1 Performance Share Awards | Performance unit awards | February 2014, February 2015, May 25, and April 1 | |||||
Equity and stock-based compensation | |||||
Unrecognized equity and stock-based compensation expense | $ | $ 11.9 | ||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 7 months 2 days | ||||
Requisite service period (in years) | 3 years | ||||
February 2013 Awards | Performance Unit Awards | |||||
Equity and stock-based compensation | |||||
Exercised (in shares) | 44,481 | ||||
Cash paid for performance units (in dollars per share) | $ / shares | $ 143.75 |
Stockholders' equity, stock-b_6
Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock awards activity (Details) - Restricted stock awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Restricted stock awards | |||
Outstanding at the beginning of the period (in shares) | 3,169 | 3,878 | 2,539 |
Granted (in shares) | 3,328 | 1,237 | 2,982 |
Forfeited (in shares) | (367) | (302) | (457) |
Vested (in shares) | (1,934) | (1,644) | (1,186) |
Outstanding at the end of the period (in shares) | 4,196 | 3,169 | 3,878 |
Weighted-average grant-date fair value (per award) | |||
Outstanding at the beginning of the period (in dollars per share) | $ 12.81 | $ 12.88 | $ 15.26 |
Fair value per performance share (in dollars per share) | 8.34 | 13.87 | 12.28 |
Forfeited (in dollars per share) | 10.13 | 12.87 | 13.95 |
Vested (in dollars per share) | 11.92 | 13.75 | 16.07 |
Outstanding at the end of the period (in dollars per share) | $ 9.91 | $ 12.81 | $ 12.88 |
Intrinsic value of vested restricted stock awards | $ 16.6 |
Stockholders' equity, stock-b_7
Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock option awards activity (Details) - Stock option awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Stock option awards | ||||
Outstanding at the beginning of the period (in shares) | 2,647 | 2,370 | 1,778 | |
Granted (in shares) | 391 | 1,016 | ||
Exercised (in shares) | (21) | (54) | (17) | |
Expired or canceled (in shares) | (53) | (60) | (109) | |
Forfeited (in shares) | (40) | (298) | ||
Outstanding at the end of the period (in shares) | 2,533 | 2,647 | 2,370 | 1,778 |
Vested (in shares) | 1,697 | |||
Vested, exercisable, and expected to vest at end of period (in shares) | 836 | |||
Weighted-average exercise price (per award) | ||||
Outstanding at the end of the period (in dollars per share) | $ 12.70 | $ 12.54 | $ 17.86 | |
Granted (in dollars per share) | 14.12 | 4.18 | ||
Exercised (in dollars per share) | 4.10 | 7.43 | 11.93 | |
Expired or canceled (in dollars per share) | 18.92 | 20.41 | 21.71 | |
Forfeited (in dollars per share) | 9.23 | 12.49 | ||
Outstanding at end of the period (in dollars per share) | 12.69 | $ 12.70 | $ 12.54 | $ 17.86 |
Vested and exercisable at end of period (in dollars per share) | 14.75 | |||
Vested, exercisable, and expected to vest at end of period (in dollars per share) | $ 8.53 | |||
Weighted-average remaining contractual term (years) | ||||
Outstanding at the end of the period | 5 years 11 months 26 days | 7 years 1 month 13 days | 7 years 8 months 15 days | 7 years 10 months 28 days |
Vested and exercisable at the end of the period | 5 years 3 months 25 days | |||
Vested, exercisable, and expected to vest at end of period | 7 years 4 months 2 days | |||
Total intrinsic value of exercised stock option awards | $ 0.1 | |||
Intrinsic value, options exercisable | 0 | |||
Aggregate intrinsic value, vested and expected to vest | $ 0 |
Stockholders' equity, stock-b_8
Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock option awards assumptions used to estimate the fair value (Details) - Stock option awards | 12 Months Ended |
Dec. 31, 2018$ / shares | |
February 17, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Risk-free interest rate | 2.14% |
Expected option life (in years) | 6 years 3 months |
Expected volatility | 60.84% |
Fair value per option (in dollars per share) | $ 8.22 |
February 17, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Risk-free interest rate | 1.58% |
Expected option life (in years) | 6 years 3 months |
Expected volatility | 61.94% |
Fair value per option (in dollars per share) | $ 9.75 |
May 25, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Risk-free interest rate | 1.44% |
Expected option life (in years) | 6 years 3 months |
Expected volatility | 61.34% |
Fair value per option (in dollars per share) | $ 4.44 |
Stockholders' equity, stock-b_9
Stockholders' equity, stock-based compensation and defined contribution plan - Restricted stock option awards full years of continuous employment (Details) - Stock option awards | 12 Months Ended |
Dec. 31, 2018 | |
Less than one | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 0.00% |
Cumulative percentage of option exercisable | 0.00% |
One | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 25.00% |
Two | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 50.00% |
Three | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 75.00% |
Four | |
Equity and stock-based compensation | |
Incremental percentage of option exercisable | 25.00% |
Cumulative percentage of option exercisable | 100.00% |
Stockholders' equity, stock-_10
Stockholders' equity, stock-based compensation and defined contribution plan - Performance shares award activity (Details) | Feb. 16, 2018$ / shares | Feb. 17, 2017$ / shares | May 25, 2016$ / shares | Apr. 01, 2016$ / shares | Mar. 31, 2018$ / sharesshares | Sep. 30, 2018$ / sharesshares | Dec. 31, 2018$ / sharesshares | Dec. 31, 2017$ / sharesshares | Dec. 31, 2016$ / sharesshares |
Weighted-average grant-date fair value (per award) | |||||||||
RTSR Factor weight | 25.00% | ||||||||
ATSR Factor weight | 25.00% | ||||||||
ROACE Factor weight | 50.00% | 50.00% | |||||||
Performance unit awards | |||||||||
Performance share awards | |||||||||
Outstanding at the beginning of the period (in shares) | shares | 2,745,000 | 2,745,000 | 2,745,000 | 2,325,000 | 874,000 | ||||
Granted (in shares) | shares | 1,389,000 | 696,000 | 1,801,000 | ||||||
Forfeited (in shares) | shares | (244,000) | (76,000) | (350,000) | ||||||
Vested (in shares) | shares | (454,000) | (200,000) | |||||||
Outstanding at the end of the period (in shares) | shares | 3,436,000 | 2,745,000 | 2,325,000 | ||||||
Weighted-average grant-date fair value (per award) | |||||||||
Outstanding at the beginning of the period (in dollars per share) | $ 17.77 | $ 17.77 | $ 17.77 | $ 18.35 | $ 20.06 | ||||
Granted (in dollars per share) | $ 10.08 | $ 18.96 | $ 17.86 | $ 9.83 | 9.22 | 18.96 | 17.71 | ||
Forfeited (in dollars per share) | 14.93 | 18.12 | 19.34 | ||||||
Vested (in dollars per share) | 16.23 | 28.56 | |||||||
Outstanding at the end of the period (in dollars per share) | 13.74 | $ 17.77 | $ 18.35 | ||||||
February 27, 2014 | Performance unit awards | |||||||||
Weighted-average grant-date fair value (per award) | |||||||||
Performance share conversion ratio | 0.75 | ||||||||
Performance share conversion (in shares) | shares | 150,388 | ||||||||
February 16, 2018 | Performance Shares With Market Criteria | |||||||||
Weighted-average grant-date fair value (per award) | |||||||||
Granted (in dollars per share) | $ 10.08 | ||||||||
RTSR Factor weight | 25.00% | ||||||||
ATSR Factor weight | 25.00% | ||||||||
February 16, 2018 | Performance Shares With Performance Criteria | |||||||||
Weighted-average grant-date fair value (per award) | |||||||||
Granted (in dollars per share) | $ 8.36 | $ 7.13 | |||||||
ROACE Factor weight | 50.00% | ||||||||
Estimated probability of criteria being met over 3 year performance period | 50.00% | ||||||||
Estimated probability, expense per unit (in dollars per share) | $ 4.18 | ||||||||
February 16, 2018 | Performance unit awards | |||||||||
Weighted-average grant-date fair value (per award) | |||||||||
Granted (in dollars per share) | $ 9.22 | ||||||||
Estimated probability of criteria being met over 3 year performance period | 50.00% | ||||||||
February 27, 2015 | |||||||||
Weighted-average grant-date fair value (per award) | |||||||||
RTSR Factor weight | 0.00% | ||||||||
2016 Performance Share Award | April 1, 2016 and May 25, 2016 | Performance unit awards | |||||||||
Performance share awards | |||||||||
Outstanding at the end of the period (in shares) | shares | 1,502,868 | ||||||||
Weighted-average grant-date fair value (per award) | |||||||||
RTSR Factor weight | 0.00% |
Stockholders' equity, stock-_11
Stockholders' equity, stock-based compensation and defined contribution plan - Performance share awards assumptions used to estimate the fair value (Details) - Performance unit awards - $ / shares | Feb. 16, 2018 | Feb. 17, 2017 | May 25, 2016 | Apr. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Risk-free interest rate | 2.34% | 1.44% | 1.02% | 0.87% | |||
Dividend yield (as a percent) | 0.00% | 0.00% | 0.00% | 0.00% | |||
Expected volatility | 65.49% | 74.00% | 74.73% | 71.54% | |||
Closing stock price on grant date (in dollars per share) | $ 8.36 | $ 14.12 | $ 12.36 | $ 7.71 | |||
Fair value per performance share (in dollars per share) | $ 10.08 | $ 18.96 | $ 17.86 | $ 9.83 | $ 9.22 | $ 18.96 | $ 17.71 |
February 16, 2018 | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Fair value per performance share (in dollars per share) | $ 9.22 | ||||||
Estimated probability of criteria being met over 3 year performance period | 50.00% |
Stockholders' equity, stock-_12
Stockholders' equity, stock-based compensation and defined contribution plan - Stock-based compensation award expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Equity and stock-based compensation | |||
Total stock-based compensation, gross | $ 44,325 | $ 43,297 | $ 35,240 |
Less amounts capitalized in evaluated oil and natural gas properties | (7,929) | (7,563) | (6,011) |
Total stock-based compensation, net | 36,396 | 35,734 | 29,229 |
Restricted stock awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | 25,271 | 22,223 | 21,609 |
Stock option awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | 3,862 | 4,762 | 4,519 |
Performance unit awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | $ 15,192 | $ 16,312 | $ 9,112 |
Stockholders' equity, stock-_13
Stockholders' equity, stock-based compensation and defined contribution plan - Cost recognized for the Company's defined contribution plan (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
401(k) Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Contributions | $ 2,156 | $ 1,929 | $ 1,789 |
Net income (loss) per common _3
Net income (loss) per common share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||||||||||
Diluted (in dollars per share) | $ 0.65 | $ 0.24 | $ 0.14 | $ 0.36 | $ 1.70 | $ 0.05 | $ 0.25 | $ 0.28 | $ 1.39 | $ 2.29 | $ (1.16) |
Net income (numerator): | |||||||||||
Net income (loss) | $ 149,573 | $ 55,050 | $ 33,452 | $ 86,520 | $ 408,561 | $ 11,027 | $ 61,110 | $ 68,276 | $ 324,595 | $ 548,974 | $ (260,739) |
Weighted-average common shares outstanding (denominator): | |||||||||||
Weighted-average common shares outstanding—basic (in shares) | 232,339 | 239,096 | 225,512 | ||||||||
Net income (loss) per common share: | |||||||||||
Basic (in dollars per share) | $ 0.65 | $ 0.24 | $ 0.14 | $ 0.36 | $ 1.71 | $ 0.05 | $ 0.26 | $ 0.29 | $ 1.40 | $ 2.30 | $ (1.16) |
Diluted (in shares) | 233,172 | 240,122 | 225,512 | ||||||||
Non-vested restricted stock awards | |||||||||||
Weighted-average common shares outstanding (denominator): | |||||||||||
Non-vested restricted stock awards (in shares) | 813 | 880 | 0 | ||||||||
Outstanding stock option awards | |||||||||||
Weighted-average common shares outstanding (denominator): | |||||||||||
Non-vested restricted stock awards (in shares) | 20 | 122 | 0 | ||||||||
Non-vested performance share awards | |||||||||||
Weighted-average common shares outstanding (denominator): | |||||||||||
Non-vested restricted stock awards (in shares) | 0 | 24 | 0 |
Derivatives - Derivatives narra
Derivatives - Derivatives narrative (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)derivative | Dec. 31, 2016USD ($)derivative | |
Derivative [Line Items] | |||
Settlements received for early terminations of derivatives, net | $ 0 | $ 4,234 | $ 80,000 |
Commodity derivatives | Derivatives not designated as hedges | |||
Derivative [Line Items] | |||
Settlements received for early terminations of derivatives, net | $ 4,200 | $ 80,000 | |
Number of restructuring derivatives entered | derivative | 1 | 2 |
Derivatives - Commodity derivat
Derivatives - Commodity derivative contracts terminated (Details) - Early Contract Termination - Crude Oil - January 2018 - December 2018 | 12 Months Ended |
Dec. 31, 2017$ / bblbbl | |
Derivative [Line Items] | |
Aggregate volumes (Bbl) | bbl | 1,095,000 |
Floor price (dollars per Bbl and MMBtu) | 52.12 |
Ceiling price (dollars per Bbl and MMBtu) | 52.12 |
Derivatives - Derivative positi
Derivatives - Derivative positions (Details) - Scenario, Forecast - Derivatives not designated as hedges | 12 Months Ended | ||
Dec. 31, 2021BoeMMBTU$ / MMBTU$ / bbl | Dec. 31, 2020BoeMMBTU$ / MMBTU$ / bbl | Dec. 31, 2019BoeMMBTU$ / MMBTU$ / bbl | |
Put Instrument 1 | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 366,000 | 8,030,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 45 | 47.45 |
Put Instrument 2 | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 4,745,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 3.21 |
Swap | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 695,400 | 657,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 52.18 | 53.45 |
Swap | Natural Gas | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | MMBTU | 0 | 0 | 21,900,000 |
Weighted-average price (dollars per bbl) | $ / MMBTU | 0 | 0 | 3.23 |
Collar | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 1,134,600 | 0 |
Collar | Floor | Crude Oil | |||
Derivative [Line Items] | |||
Weighted-average price (dollars per bbl) | $ / bbl | 45 | 45 | 0 |
Collar | Ceiling | Crude Oil | |||
Derivative [Line Items] | |||
Weighted-average price (dollars per bbl) | $ / bbl | 71 | 76.13 | 0 |
Commodity | Natural Gas Liquids | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 365,000 | 366,000 | 912,500 |
Commodity | Floor | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 2,196,000 | 8,687,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 45 | 47.27 | 47.91 |
Commodity | Ceiling | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 1,830,000 | 657,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 71 | 67.03 | 53.45 |
Basis Swap | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 1,840,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | (2.89) |
Basis Swap 2 | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 552,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | (4.37) |
Basis Swap 3 | Crude Oil | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 1,810,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 7.30 |
Basis Swap 4 | Natural Gas | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | MMBTU | 16,425,000 | 32,574,000 | 39,055,000 |
Weighted-average price (dollars per bbl) | $ / MMBTU | (0.47) | (0.76) | (1.51) |
Swaps - Purity Ethane | Swap | Natural Gas Liquids | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 365,000 | 366,000 | 730,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 13.02 | 13.60 | 14.07 |
Swaps - Non-TET Natural Gasoline | Swap | Natural Gas Liquids | |||
Derivative [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 182,500 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 46.62 |
Fair value measurements - Fair
Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Net fair value presented on the consolidated balance sheets | $ 39,835 | $ 6,892 |
Net fair value presented on the consolidated balance sheets | 11,030 | 3,413 |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (7,359) | (22,950) |
Net fair value presented on the consolidated balance sheets | 0 | (384) |
Net derivative asset (liability) positions | 43,506 | (13,029) |
Level 1 | ||
Liabilities | ||
Net derivative asset (liability) positions | 0 | 0 |
Level 2 | ||
Liabilities | ||
Net derivative asset (liability) positions | 60,071 | 15,654 |
Level 3 | ||
Liabilities | ||
Net derivative asset (liability) positions | (16,565) | (28,683) |
Oil derivatives | Commodity derivatives | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 36,518 | 3,706 |
Net fair value presented on the consolidated balance sheets | 10,626 | 5,526 |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (1,152) | (8,756) |
Net fair value presented on the consolidated balance sheets | 0 | 3,698 |
Oil derivatives | Natural Gas Liquids | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 0 | |
Net fair value presented on the consolidated balance sheets | 0 | |
Oil derivatives | Deferred Premiums | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | (14,381) | (87) |
Net fair value presented on the consolidated balance sheets | 0 | (2,113) |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (2,184) | (18,115) |
Net fair value presented on the consolidated balance sheets | 0 | (5,016) |
Natural Gas Liquids | Commodity derivatives | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 1,974 | |
Net fair value presented on the consolidated balance sheets | 1,024 | |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Natural Gas | Commodity derivatives | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 15,724 | 5,729 |
Net fair value presented on the consolidated balance sheets | (620) | 0 |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (4,023) | 4,817 |
Net fair value presented on the consolidated balance sheets | 0 | 934 |
Natural Gas | Deferred Premiums | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 0 | (2,456) |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | 0 | (896) |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Current Assets | Oil derivatives | Commodity derivatives | ||
Assets | ||
Total gross fair value | 44,425 | 7,427 |
Amounts offset | (7,907) | (3,721) |
Current Assets | Oil derivatives | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Amounts offset | 0 | |
Current Assets | Oil derivatives | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Amounts offset | (14,381) | (87) |
Current Assets | Oil derivatives | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Oil derivatives | Level 1 | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Current Assets | Oil derivatives | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Oil derivatives | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 44,425 | 7,427 |
Current Assets | Oil derivatives | Level 2 | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Current Assets | Oil derivatives | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Oil derivatives | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Oil derivatives | Level 3 | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Current Assets | Oil derivatives | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Natural Gas Liquids | Commodity derivatives | ||
Assets | ||
Total gross fair value | 1,974 | |
Amounts offset | 0 | |
Current Assets | Natural Gas Liquids | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Current Assets | Natural Gas Liquids | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 1,974 | |
Current Assets | Natural Gas Liquids | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Current Assets | Natural Gas | Commodity derivatives | ||
Assets | ||
Total gross fair value | 18,991 | 10,546 |
Amounts offset | (3,267) | (4,817) |
Current Assets | Natural Gas | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | (2,456) |
Current Assets | Natural Gas | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Natural Gas | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Natural Gas | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 18,991 | 10,546 |
Current Assets | Natural Gas | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Natural Gas | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Assets | Natural Gas | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Oil derivatives | Commodity derivatives | ||
Assets | ||
Total gross fair value | 10,626 | 11,613 |
Amounts offset | 0 | (6,087) |
Noncurrent Assets | Oil derivatives | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Amounts offset | 0 | |
Noncurrent Assets | Oil derivatives | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | (2,113) |
Noncurrent Assets | Oil derivatives | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Oil derivatives | Level 1 | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent Assets | Oil derivatives | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Oil derivatives | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 10,626 | 11,613 |
Noncurrent Assets | Oil derivatives | Level 2 | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent Assets | Oil derivatives | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Oil derivatives | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Oil derivatives | Level 3 | Natural Gas Liquids | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent Assets | Oil derivatives | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Natural Gas Liquids | Commodity derivatives | ||
Assets | ||
Total gross fair value | 1,024 | |
Amounts offset | 0 | |
Noncurrent Assets | Natural Gas Liquids | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent Assets | Natural Gas Liquids | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 1,024 | |
Noncurrent Assets | Natural Gas Liquids | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent Assets | Natural Gas | Commodity derivatives | ||
Assets | ||
Total gross fair value | 108 | 934 |
Amounts offset | (728) | (934) |
Noncurrent Assets | Natural Gas | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | 0 |
Noncurrent Assets | Natural Gas | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Natural Gas | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Natural Gas | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 108 | 934 |
Noncurrent Assets | Natural Gas | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Natural Gas | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent Assets | Natural Gas | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (9,059) | (12,477) |
Amounts offset | 7,907 | 3,721 |
Current Liabilities | Oil derivatives | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | (16,565) | (18,202) |
Amounts offset | 14,381 | 87 |
Current Liabilities | Oil derivatives | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Oil derivatives | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Oil derivatives | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (9,059) | (12,477) |
Current Liabilities | Oil derivatives | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Oil derivatives | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Oil derivatives | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | (16,565) | (18,202) |
Current Liabilities | Natural Gas Liquids | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | 0 |
Current Liabilities | Natural Gas Liquids | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Natural Gas Liquids | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Natural Gas Liquids | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Natural Gas | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (7,290) | 0 |
Amounts offset | 3,267 | 4,817 |
Current Liabilities | Natural Gas | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | (3,352) |
Amounts offset | 0 | 2,456 |
Current Liabilities | Natural Gas | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Natural Gas | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Natural Gas | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (7,290) | 0 |
Current Liabilities | Natural Gas | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Natural Gas | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current Liabilities | Natural Gas | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | (3,352) |
Noncurrent Liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | (2,389) |
Amounts offset | 0 | 6,087 |
Noncurrent Liabilities | Oil derivatives | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | (7,129) |
Amounts offset | 0 | 2,113 |
Noncurrent Liabilities | Oil derivatives | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Oil derivatives | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Oil derivatives | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | (2,389) |
Noncurrent Liabilities | Oil derivatives | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Oil derivatives | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Oil derivatives | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | (7,129) |
Noncurrent Liabilities | Natural Gas Liquids | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | 0 |
Noncurrent Liabilities | Natural Gas Liquids | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Natural Gas Liquids | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Natural Gas Liquids | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Natural Gas | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (728) | 0 |
Amounts offset | 728 | 934 |
Noncurrent Liabilities | Natural Gas | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Amounts offset | 0 | 0 |
Noncurrent Liabilities | Natural Gas | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Natural Gas | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Natural Gas | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (728) | 0 |
Noncurrent Liabilities | Natural Gas | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Natural Gas | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent Liabilities | Natural Gas | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | $ 0 | $ 0 |
Fair value measurements - Addit
Fair value measurements - Additional Information (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Impairment expense | $ 0 | $ 0 | $ 162,027,000 |
Deferred Premiums | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivatives, deferred premium paid | 3,900,000 | ||
Measurement Input, Discount Rate | Deferred Premiums | Minimum | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Discount rate used (as a percent) | 0.0231 | ||
Measurement Input, Discount Rate | Deferred Premiums | Maximum | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Discount rate used (as a percent) | 0.0332 | ||
Measurement Input, Discount Rate | Deferred Premiums | Weighted Average | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Discount rate used (as a percent) | 0.0276 | ||
Nonrecurring | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Impairment expense | 0 | $ 0 | |
Oil and natural gas properties | $ 0 | 0 | |
Nonrecurring | Materials and Supplies | Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Impairment expense | 0 | $ 0 | |
Nonrecurring | Long-Lived Assets | Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Impairment expense | $ 0 |
Fair value measurements - Actua
Fair value measurements - Actual cash payments (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Fair Value Disclosures [Abstract] | |
2,019 | $ 15,502 |
2,020 | 1,295 |
Total | $ 16,797 |
Fair value measurements - Roll
Fair value measurements - Roll forward (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in assets classified as Level 3 measurements | |||
Change in net present value of derivative deferred premiums | $ 694 | $ 394 | $ 232 |
Deferred Premiums | |||
Changes in assets classified as Level 3 measurements | |||
Balance of Level 3 at beginning of year | (28,683) | (8,998) | (14,619) |
Change in net present value of derivative deferred premiums | (694) | (394) | (232) |
Purchases and settlements of derivative deferred premiums: | |||
Purchases | (7,523) | (25,733) | (7,715) |
Settlements | 20,335 | 6,442 | 13,568 |
Balance of Level 3 at end of year | $ (16,565) | $ (28,683) | $ (8,998) |
Fair value measurements - Fai_2
Fair value measurements - Fair value of debt (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Reported Value Measurement | ||
Debt Instrument [Line Items] | ||
Debt | $ 990,000 | $ 800,000 |
Reported Value Measurement | January 2022 Notes | Senior Notes | ||
Debt Instrument [Line Items] | ||
Debt | 450,000 | 450,000 |
Reported Value Measurement | March 2023 Notes | Senior Notes | ||
Debt Instrument [Line Items] | ||
Debt | 350,000 | 350,000 |
Reported Value Measurement | Line of Credit | Secured Debt | ||
Debt Instrument [Line Items] | ||
Debt | 190,000 | 0 |
Estimate of Fair Value Measurement | ||
Debt Instrument [Line Items] | ||
Debt | 909,563 | 818,605 |
Estimate of Fair Value Measurement | January 2022 Notes | Senior Notes | ||
Debt Instrument [Line Items] | ||
Debt | 402,885 | 454,500 |
Estimate of Fair Value Measurement | March 2023 Notes | Senior Notes | ||
Debt Instrument [Line Items] | ||
Debt | 316,624 | 364,105 |
Estimate of Fair Value Measurement | Line of Credit | Secured Debt | ||
Debt Instrument [Line Items] | ||
Debt | $ 190,054 | $ 0 |
Income taxes - Income tax expen
Income taxes - Income tax expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current income tax benefit: | |||
Federal | $ 0 | $ 0 | $ 0 |
State | 807 | (1,800) | 0 |
Deferred income tax expense: | |||
Federal | 0 | 0 | 0 |
State | (5,056) | 0 | 0 |
Total income tax expense | $ (4,249) | $ (1,800) | $ 0 |
Income taxes - Additional infor
Income taxes - Additional information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Examination [Line Items] | |||
State tax | $ (807) | $ 1,800 | $ 0 |
AMT credit carryforward | $ 4,800 | ||
Effective tax rate (as a percent) | 1.00% | 0.00% | 0.00% |
Accumulated deficit | $ (1,203,395) | $ (1,669,108) | |
Valuation allowance (decrease) | 237,262 | 341,402 | |
Amount of federal net operating loss carry-forward limited in future periods | 122,700 | ||
Federal | |||
Income Tax Examination [Line Items] | |||
Net operating loss carry-forwards | 1,859,821 | ||
Texas | State | |||
Income Tax Examination [Line Items] | |||
Deferred tax liability | 5,100 | ||
Proceeds tax refund | 800 | ||
State tax | 1,800 | ||
Oklahoma | State | |||
Income Tax Examination [Line Items] | |||
Net operating loss carry-forwards | 36,200 | ||
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | |||
Income Tax Examination [Line Items] | |||
Accumulated deficit | 141,100 | ||
Valuation allowance (decrease) | $ (30,700) | ||
Accounts Receivable | |||
Income Tax Examination [Line Items] | |||
AMT credit carryforward | 2,400 | ||
Other Noncurrent Assets | |||
Income Tax Examination [Line Items] | |||
AMT credit carryforward | $ 2,400 |
Income taxes - Schedule of refu
Income taxes - Schedule of refund of AMT carryforward (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Income Tax Disclosure [Abstract] | |
2,019 | $ 2,408 |
2,020 | 1,203 |
2,021 | 602 |
2,022 | 602 |
AMT credit carryforward | $ 4,815 |
Income taxes - Income tax recon
Income taxes - Income tax reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Income tax (expense) benefit computed by applying the statutory rate | $ (69,057) | $ (192,141) | $ 91,259 |
Decrease (increase) in deferred tax valuation allowance | 74,289 | 417,518 | (86,569) |
State income tax and change in valuation allowance | (9,070) | 696 | (370) |
Change in tax rate applicable to net deferred tax assets | 0 | (226,263) | 0 |
Stock-based compensation tax deficiency | 0 | (64) | (4,144) |
Other items | (411) | (1,546) | (176) |
Total income tax expense | $ (4,249) | $ (1,800) | $ 0 |
Income taxes - Net deferred tax
Income taxes - Net deferred tax liability (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Significant components of deferred tax assets | ||
Net operating loss carryforward | $ 392,276 | $ 355,100 |
Oil and natural gas properties, midstream service assets and other fixed assets | (168,031) | (80,153) |
Stock-based compensation | 19,845 | 14,025 |
Derivatives, liability | (8,188) | |
Derivatives, asset | 3,788 | |
Gain (loss) on sale of assets | (7,693) | 40,177 |
Other | 3,997 | 8,465 |
Net deferred tax asset before valuation allowance | 232,206 | 341,402 |
Valuation allowance | (237,262) | (341,402) |
Net deferred tax liability | $ (5,056) | $ 0 |
Income taxes - Operating losses
Income taxes - Operating losses (Details) - Federal $ in Thousands | Dec. 31, 2018USD ($) |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 1,859,821 |
2,026 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 2,741 |
2,027 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 38,651 |
2,028 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 228,661 |
2,029 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 101,932 |
2,030 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 80,963 |
Thereafter | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 1,406,873 |
Credit risk (Details)
Credit risk (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Concentration Risk [Line Items] | |||||
Net fair value presented on the consolidated balance sheets | $ 39,835 | $ 6,892 | $ 39,835 | $ 6,892 | |
Cash balances exceeded by balance insured by FDIC | $ 48,200 | $ 48,200 | |||
Customers | Oil, NGL, and Natural Gas Sales | Customer one | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 29.50% | 39.30% | 48.50% | ||
Customers | Oil, NGL, and Natural Gas Sales | Customer two | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 24.20% | 26.10% | 23.00% | ||
Customers | Oil, NGL, and Natural Gas Sales | Customer three | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 16.20% | 17.40% | 17.00% | ||
Customers | Oil, NGL, and Natural Gas Sales | Customer four | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 16.00% | 12.60% | |||
Customers | Purchased Oil Sales | Customer one | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 63.90% | 97.50% | 100.00% | ||
Customers | Purchased Oil Sales | Customer two | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 36.10% | ||||
Credit Concentration Risk | Trade Accounts Receivable | Customer one | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 33.80% | 34.60% | |||
Credit Concentration Risk | Trade Accounts Receivable | Customer two | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 23.90% | 27.30% | |||
Credit Concentration Risk | Trade Accounts Receivable | Customer three | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 23.30% | 15.60% | |||
Credit Concentration Risk | Trade Accounts Receivable | Customer four | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 15.40% | ||||
Credit Concentration Risk | Purchased Oil and Other Products Sales | Customer one | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 100.00% | 99.70% | |||
Credit Concentration Risk | Partner One | Joint operations accounts receivable | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 46.70% | 21.40% | |||
Credit Concentration Risk | Partner Two | Joint operations accounts receivable | |||||
Concentration Risk [Line Items] | |||||
Concentration risk (as a percent) | 30.90% | ||||
Estimate of Fair Value Measurement | |||||
Concentration Risk [Line Items] | |||||
Net fair value presented on the consolidated balance sheets | $ 50,900 | $ 50,900 |
Commitments and contingencies -
Commitments and contingencies - Lease commitments (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Lease commitments | |||
2,019 | $ 3,092,000 | ||
2,020 | 3,179,000 | ||
2,021 | 3,128,000 | ||
2,022 | 2,560,000 | ||
2,023 | 1,358,000 | ||
Thereafter | 4,556,000 | ||
Total future minimum rental payments required | 17,873,000 | ||
Total minimum rentals to be received | 5,900,000 | ||
Rent expense | |||
Rent expense | 2,735,000 | $ 2,696,000 | $ 2,664,000 |
Rent income | 600,000 | 0 | |
Estimate of possible loss | 37,400,000 | ||
Minimum volume commitments | 4,700,000 | 1,100,000 | $ 2,200,000 |
Materially significant loss liabilities | 0 | $ 0 | |
Drilling Contracts | |||
Rent expense | |||
Future commitments | 16,500,000 | ||
Firm Sale And Transportation Commitments | |||
Rent expense | |||
Future commitments | $ 365,900,000 |
Commitments and contingencies_2
Commitments and contingencies - Litigation (Details) $ in Millions | Dec. 31, 2018USD ($)bbl | Jun. 15, 2018USD ($) | Dec. 11, 2017Claim |
Commitments and Contingencies Disclosure [Abstract] | |||
Barrels of crude oil | bbl | 19,000 | ||
Number of causes of action | Claim | 9 | ||
Damages from breach of agreement | $ 150 | ||
Estimate of possible loss | $ 37.4 |
Commitments and contingencies_3
Commitments and contingencies - Drilling contracts (Details) - Drilling Contracts - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Penalties for early contract termination | $ 0 | $ 0 | $ 0 |
Future commitments | $ 16,500,000 |
Commitments and contingencies_4
Commitments and contingencies - Firm sale and transportation commitments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Minimum volume commitments | $ 4.7 | $ 1.1 | $ 2.2 |
Firm Sale And Transportation Commitments | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Future commitments | $ 365.9 |
Commitments and contingencies_5
Commitments and contingencies - Sand purchase and supply agreement (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Sand purchase and supply agreement term | 1 year |
Shortfall payment amount | $ 3.9 |
Commitments and contingencies_6
Commitments and contingencies - Environmental (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Commitments and Contingencies Disclosure [Abstract] | ||
Materially significant loss liabilities | $ 0 | $ 0 |
Related parties (Details)
Related parties (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | $ 673,584 | $ 538,122 | $ 360,679 |
Helmerich & Payne, Inc. | Affiliated Entity | |||
Related Party Transaction [Line Items] | |||
Accounts payable and accrued liabilities | 399 | 0 | |
Oil and natural gas properties | $ 3,040 | $ 0 | $ 0 |
Subsidiary guarantors - Balance
Subsidiary guarantors - Balance sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Subsidiary guarantees | ||||
Accounts receivable, net | $ 94,321 | $ 100,645 | ||
Other current assets | 98,431 | 134,737 | ||
Oil and natural gas properties, net | 2,029,571 | 1,589,339 | ||
Midstream service assets, net | 130,245 | 138,325 | ||
Other fixed assets, net | 39,819 | 40,721 | ||
Investment in subsidiaries | 0 | 0 | ||
Other noncurrent assets, net | 27,918 | 19,522 | ||
Total assets | 2,420,305 | 2,023,289 | ||
Accounts payable and accrued liabilities | 69,504 | 58,341 | ||
Other current liabilities | 130,961 | 219,078 | ||
Long-term debt, net | 983,636 | 791,855 | ||
Other noncurrent liabilities | 61,974 | 188,436 | ||
Total stockholders' equity | 1,174,230 | 765,579 | $ 180,573 | $ 131,447 |
Total liabilities and stockholders' equity | 2,420,305 | 2,023,289 | ||
Reportable Legal Entities | Laredo | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 83,424 | 79,413 | ||
Other current assets | 97,045 | 132,219 | ||
Oil and natural gas properties, net | 2,043,009 | 1,596,834 | ||
Midstream service assets, net | 0 | 0 | ||
Other fixed assets, net | 39,751 | 40,344 | ||
Investment in subsidiaries | 128,380 | (7,566) | ||
Other noncurrent assets, net | 23,783 | 15,526 | ||
Total assets | 2,415,392 | 1,856,770 | ||
Accounts payable and accrued liabilities | 54,167 | 34,550 | ||
Other current liabilities | 121,297 | 193,104 | ||
Long-term debt, net | 983,636 | 791,855 | ||
Other noncurrent liabilities | 59,511 | 54,967 | ||
Total stockholders' equity | 1,196,781 | 782,294 | ||
Total liabilities and stockholders' equity | 2,415,392 | 1,856,770 | ||
Reportable Legal Entities | Subsidiary Guarantors | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 10,897 | 21,232 | ||
Other current assets | 1,386 | 2,518 | ||
Oil and natural gas properties, net | 9,113 | 9,220 | ||
Midstream service assets, net | 130,245 | 138,325 | ||
Other fixed assets, net | 68 | 377 | ||
Investment in subsidiaries | 0 | 0 | ||
Other noncurrent assets, net | 4,135 | 3,996 | ||
Total assets | 155,844 | 175,668 | ||
Accounts payable and accrued liabilities | 15,337 | 23,791 | ||
Other current liabilities | 9,664 | 25,974 | ||
Long-term debt, net | 0 | 0 | ||
Other noncurrent liabilities | 2,463 | 133,469 | ||
Total stockholders' equity | 128,380 | (7,566) | ||
Total liabilities and stockholders' equity | 155,844 | 175,668 | ||
Intercompany eliminations | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 0 | 0 | ||
Other current assets | 0 | 0 | ||
Oil and natural gas properties, net | (22,551) | (16,715) | ||
Midstream service assets, net | 0 | 0 | ||
Other fixed assets, net | 0 | 0 | ||
Investment in subsidiaries | (128,380) | 7,566 | ||
Other noncurrent assets, net | 0 | 0 | ||
Total assets | (150,931) | (9,149) | ||
Accounts payable and accrued liabilities | 0 | 0 | ||
Other current liabilities | 0 | 0 | ||
Long-term debt, net | 0 | 0 | ||
Other noncurrent liabilities | 0 | 0 | ||
Total stockholders' equity | (150,931) | (9,149) | ||
Total liabilities and stockholders' equity | $ (150,931) | $ (9,149) |
Subsidiary guarantors - Stateme
Subsidiary guarantors - Statement of operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Subsidiary guarantees | |||||||||||
Total revenues | $ 215,287 | $ 279,746 | $ 351,046 | $ 259,696 | $ 240,337 | $ 205,818 | $ 187,001 | $ 189,006 | $ 1,105,775 | $ 822,162 | $ 597,378 |
Total costs and expenses | 757,283 | 572,490 | 685,340 | ||||||||
Operating income (loss) | 56,123 | 104,410 | 94,767 | 93,192 | 85,833 | 60,452 | 52,061 | 51,326 | 348,492 | 249,672 | (87,962) |
Interest expense | (57,904) | (89,377) | (93,298) | ||||||||
Gain on sale of investment in equity method investee (see Note 4.c) | 0 | 405,906 | 0 | ||||||||
Other non-operating income (expense), net | 38,256 | (15,427) | (79,479) | ||||||||
Income (loss) before income taxes | 328,844 | 550,774 | (260,739) | ||||||||
Total income tax expense | (4,249) | (1,800) | 0 | ||||||||
Net income (loss) | $ 149,573 | $ 55,050 | $ 33,452 | $ 86,520 | $ 408,561 | $ 11,027 | $ 61,110 | $ 68,276 | 324,595 | 548,974 | (260,739) |
Reportable Legal Entities | Laredo | |||||||||||
Subsidiary guarantees | |||||||||||
Total revenues | 809,396 | 623,028 | 427,028 | ||||||||
Total costs and expenses | 466,895 | 376,938 | 514,483 | ||||||||
Operating income (loss) | 342,501 | 246,090 | (87,455) | ||||||||
Interest expense | (57,904) | (89,377) | (93,298) | ||||||||
Gain on sale of investment in equity method investee (see Note 4.c) | 0 | ||||||||||
Other non-operating income (expense), net | 50,083 | 402,536 | (73,669) | ||||||||
Income (loss) before income taxes | 334,680 | 559,249 | (254,422) | ||||||||
Total income tax expense | (4,249) | (1,800) | 0 | ||||||||
Net income (loss) | 330,431 | 557,449 | (254,422) | ||||||||
Reportable Legal Entities | Subsidiary Guarantors | |||||||||||
Subsidiary guarantees | |||||||||||
Total revenues | 365,633 | 266,455 | 213,866 | ||||||||
Total costs and expenses | 353,806 | 254,398 | 208,056 | ||||||||
Operating income (loss) | 11,827 | 12,057 | 5,810 | ||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Gain on sale of investment in equity method investee (see Note 4.c) | 405,906 | ||||||||||
Other non-operating income (expense), net | (1,049) | 8,083 | 9,381 | ||||||||
Income (loss) before income taxes | 10,778 | 426,046 | 15,191 | ||||||||
Total income tax expense | 0 | 0 | 0 | ||||||||
Net income (loss) | 10,778 | 426,046 | 15,191 | ||||||||
Intercompany eliminations | |||||||||||
Subsidiary guarantees | |||||||||||
Total revenues | (69,254) | (67,321) | (43,516) | ||||||||
Total costs and expenses | (63,418) | (58,846) | (37,199) | ||||||||
Operating income (loss) | (5,836) | (8,475) | (6,317) | ||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Gain on sale of investment in equity method investee (see Note 4.c) | 0 | ||||||||||
Other non-operating income (expense), net | (10,778) | (426,046) | (15,191) | ||||||||
Income (loss) before income taxes | (16,614) | (434,521) | (21,508) | ||||||||
Total income tax expense | 0 | 0 | 0 | ||||||||
Net income (loss) | $ (16,614) | $ (434,521) | $ (21,508) |
Subsidiary guarantors - Cash fl
Subsidiary guarantors - Cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Subsidiary guarantees | |||
Net cash provided by operating activities | $ 537,804 | $ 384,914 | $ 356,295 |
Change in investments between affiliates | 0 | 0 | 0 |
Capital expenditures and other | (692,611) | (534,565) | (564,402) |
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) | 1,655 | 829,615 | 0 |
Net cash provided by financing activities | 86,144 | (600,477) | 209,625 |
Net (decrease) increase in cash and cash equivalents | (67,008) | 79,487 | 1,518 |
Cash and cash equivalents, beginning of period | 112,159 | 32,672 | 31,154 |
Cash and cash equivalents, end of period | 45,151 | 112,159 | 32,672 |
Reportable Legal Entities | Laredo | |||
Subsidiary guarantees | |||
Net cash provided by operating activities | 528,281 | 778,851 | 355,458 |
Change in investments between affiliates | 5,175 | 383,613 | (73,988) |
Capital expenditures and other | (686,608) | (482,500) | (489,577) |
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) | 0 | 0 | |
Net cash provided by financing activities | 86,144 | (600,477) | 209,625 |
Net (decrease) increase in cash and cash equivalents | (67,008) | 79,487 | 1,518 |
Cash and cash equivalents, beginning of period | 112,158 | 32,671 | 31,153 |
Cash and cash equivalents, end of period | 45,150 | 112,158 | 32,671 |
Reportable Legal Entities | Subsidiary Guarantors | |||
Subsidiary guarantees | |||
Net cash provided by operating activities | 20,301 | 32,109 | 16,028 |
Change in investments between affiliates | (15,953) | (809,659) | 58,797 |
Capital expenditures and other | (6,003) | (52,065) | (74,825) |
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) | 1,655 | 829,615 | |
Net cash provided by financing activities | 0 | 0 | 0 |
Net (decrease) increase in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents, beginning of period | 1 | 1 | 1 |
Cash and cash equivalents, end of period | 1 | 1 | 1 |
Intercompany eliminations | |||
Subsidiary guarantees | |||
Net cash provided by operating activities | (10,778) | (426,046) | (15,191) |
Change in investments between affiliates | 10,778 | 426,046 | 15,191 |
Capital expenditures and other | 0 | 0 | 0 |
Proceeds from disposition of equity method investee, net of selling costs (see Note 4.c) | 0 | 0 | |
Net cash provided by financing activities | 0 | 0 | 0 |
Net (decrease) increase in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents, beginning of period | 0 | 0 | 0 |
Cash and cash equivalents, end of period | $ 0 | $ 0 | $ 0 |
Subsequent events - Additional
Subsequent events - Additional Information (Details) - USD ($) $ in Thousands | Feb. 12, 2019 | Jan. 14, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Feb. 13, 2019 |
Subsequent Event [Line Items] | ||||||
Borrowings on Senior Secured Credit Facility | $ 210,000 | $ 190,000 | $ 239,682 | |||
Secured Debt | Line of Credit | ||||||
Subsequent Event [Line Items] | ||||||
Line of credit | $ 190,000 | |||||
Secured Debt | Line of Credit | Subsequent events | ||||||
Subsequent Event [Line Items] | ||||||
Borrowings on Senior Secured Credit Facility | $ 20,000 | $ 30,000 | ||||
Line of credit | $ 240,000 |
Subsequent events - Derivatives
Subsequent events - Derivatives (Details) - Scenario, Forecast - Derivatives not designated as hedges | 12 Months Ended | ||
Dec. 31, 2021BoeMMBTU$ / MMBTU$ / bbl | Dec. 31, 2020BoeMMBTU$ / MMBTU$ / bbl | Dec. 31, 2019BoeMMBTU$ / MMBTU$ / bbl | |
Put Instrument 1 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 366,000 | 8,030,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 45 | 47.45 |
Put Instrument 2 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 4,745,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 3.21 |
Swap | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 695,400 | 657,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 52.18 | 53.45 |
Swap | Natural gas (MMcf) | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | MMBTU | 0 | 0 | 21,900,000 |
Weighted-average price (dollars per bbl) | $ / MMBTU | 0 | 0 | 3.23 |
Collar | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 1,134,600 | 0 |
Collar | Floor | Crude Oil | |||
Subsequent Event [Line Items] | |||
Weighted-average price (dollars per bbl) | $ / bbl | 45 | 45 | 0 |
Collar | Ceiling | Crude Oil | |||
Subsequent Event [Line Items] | |||
Weighted-average price (dollars per bbl) | $ / bbl | 71 | 76.13 | 0 |
Commodity | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 365,000 | 366,000 | 912,500 |
Commodity | Floor | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 2,196,000 | 8,687,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 45 | 47.27 | 47.91 |
Commodity | Ceiling | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 1,830,000 | 657,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 71 | 67.03 | 53.45 |
Basis Swap | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 1,840,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | (2.89) |
Basis Swap 2 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 552,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | (4.37) |
Basis Swap 3 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 1,810,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 7.30 |
Basis Swap 4 | Natural gas (MMcf) | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | MMBTU | 16,425,000 | 32,574,000 | 39,055,000 |
Weighted-average price (dollars per bbl) | $ / MMBTU | (0.47) | (0.76) | (1.51) |
Swaps - Purity Ethane | Swap | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 365,000 | 366,000 | 730,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 13.02 | 13.60 | 14.07 |
Natural Gasoline | Swap | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 182,500 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 46.62 |
Subsequent events | Put Instrument 1 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 366,000 | 8,030,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 45 | 47.45 |
Subsequent events | Put Instrument 2 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 4,745,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 3.21 |
Subsequent events | Swap | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 695,400 | 657,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 52.18 | 53.45 |
Subsequent events | Swap | Natural gas (MMcf) | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | MMBTU | 0 | 0 | 21,900,000 |
Weighted-average price (dollars per bbl) | $ / MMBTU | 0 | 0 | 3.23 |
Subsequent events | Collar | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 1,134,600 | 0 |
Subsequent events | Collar | Floor | Crude Oil | |||
Subsequent Event [Line Items] | |||
Weighted-average price (dollars per bbl) | $ / bbl | 45 | 45 | 0 |
Subsequent events | Collar | Ceiling | Crude Oil | |||
Subsequent Event [Line Items] | |||
Weighted-average price (dollars per bbl) | $ / bbl | 71 | 76.13 | 0 |
Subsequent events | Commodity | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 2,202,775 | 2,562,000 | 5,388,100 |
Subsequent events | Commodity | Floor | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 2,196,000 | 8,687,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 45 | 47.27 | 47.91 |
Subsequent events | Commodity | Ceiling | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 1,830,000 | 657,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 71 | 67.03 | 53.45 |
Subsequent events | Basis Swap | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 1,840,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | (2.89) |
Subsequent events | Basis Swap 2 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 552,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | (4.37) |
Subsequent events | Basis Swap 3 | Crude Oil | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 0 | 0 | 1,810,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 0 | 0 | 7.30 |
Subsequent events | Basis Swap 4 | Natural gas (MMcf) | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | MMBTU | 23,360,000 | 32,574,000 | 39,055,000 |
Weighted-average price (dollars per bbl) | $ / MMBTU | (0.47) | (0.76) | (1.51) |
Subsequent events | Swaps - Purity Ethane | Swap | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 912,500 | 366,000 | 2,233,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 12.01 | 13.60 | 14.21 |
Subsequent events | Natural Gasoline | Swap 5 | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 237,250 | 402,600 | 583,300 |
Weighted-average price (dollars per bbl) | $ / bbl | 44.31 | 45.15 | 45.83 |
Subsequent events | Propane | Swap 2 | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 730,000 | 1,244,400 | 1,736,800 |
Weighted-average price (dollars per bbl) | $ / bbl | 25.52 | 26.58 | 27.97 |
Subsequent events | Butane | Swap 3 | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 255,500 | 439,200 | 668,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 27.72 | 28.69 | 30.73 |
Subsequent events | Isobutane | Swap 4 | Natural Gas Liquids | |||
Subsequent Event [Line Items] | |||
Aggregate volumes (Boe) | Boe | 67,525 | 109,800 | 167,000 |
Weighted-average price (dollars per bbl) | $ / bbl | 28.79 | 29.99 | 31.08 |
Supplemental oil, NGL and nat_3
Supplemental oil, NGL and natural gas disclosures (unaudited) - Costs incurred in oil and natural gas property acquisition, exploration and development activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property acquisition costs: | |||
Evaluated | $ 15,072 | $ 0 | $ 5,905 |
Unevaluated | 2,790 | 0 | 119,923 |
Exploration costs | 23,884 | 36,257 | 41,333 |
Development costs | 607,790 | 560,919 | 298,942 |
Total costs incurred | $ 649,536 | $ 597,176 | $ 466,103 |
Supplemental oil, NGL and nat_4
Supplemental oil, NGL and natural gas disclosures (unaudited) - Aggregate capitalized oil, NGL and natural gas costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Gross capitalized costs: | ||||
Evaluated properties | $ 6,752,631 | $ 6,070,940 | ||
Unevaluated properties not being depleted, total | 130,957 | 175,865 | ||
Total gross capitalized costs | 6,883,588 | 6,246,805 | ||
Less accumulated depletion and impairment | (4,854,017) | (4,657,466) | ||
Net capitalized costs | 2,029,571 | 1,589,339 | ||
Oil and natural gas property costs not being amortized | ||||
Unevaluated properties not being depleted | 38,815 | 15,076 | $ 56,826 | $ 20,240 |
Unevaluated properties not being depleted, total | $ 130,957 | $ 175,865 |
Supplemental oil, NGL and nat_5
Supplemental oil, NGL and natural gas disclosures (unaudited) - Results of operations of oil, NGL and natural gas producing activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues: | |||
Oil, NGL and natural gas sales | $ 808,530 | $ 621,507 | $ 426,485 |
Production costs: | |||
Lease operating expenses | 91,289 | 75,049 | 75,327 |
Production and ad valorem taxes | 49,457 | 37,802 | 28,586 |
Transportation and marketing expenses | 11,704 | 0 | 0 |
Total production costs | 152,450 | 112,851 | 103,913 |
Other costs: | |||
Depletion | 196,458 | 143,592 | 134,105 |
Accretion of asset retirement obligations | 4,233 | 3,567 | 3,274 |
Impairment expense | 0 | 0 | 161,064 |
Income tax expense | 4,554 | 0 | 0 |
Total other costs | 205,245 | 147,159 | 298,443 |
Results of operations | $ 450,835 | $ 361,497 | $ 24,129 |
Effective tax rate (as a percent) | 1.00% | 0.00% | 0.00% |
Supplemental oil, NGL and nat_6
Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) - Narrative (Details) Boe in Thousands | 12 Months Ended | ||
Dec. 31, 2018Boereserves_streamlocation | Dec. 31, 2017Boereserves_streamlocation | Dec. 31, 2016Boereserves_streamlocation | |
Net proved oil and natural gas reserves | |||
Percentage of proved reserves estimated by independent reserve engineers (percent) | 100.00% | 100.00% | 100.00% |
Number of reportable reserves streams | reserves_stream | 3 | 3 | 3 |
Revisions of previous estimates (MBOE) | 2,173 | 35,351 | 34,082 |
Development wells drilled, net productive | location | 8 | 10 | 4 |
Development wells, scheduled to be drilled in the next twelve months | location | 2 | 8 | 7 |
Extensions, discoveries and other additions (MBOE) | 44,069 | 34,921 | 24,940 |
Performance, Pricing and Other Increases | |||
Net proved oil and natural gas reserves | |||
Revisions of previous estimates (MBOE) | 11,364 | ||
Performance, Pricing and Other Changes | |||
Net proved oil and natural gas reserves | |||
Revisions of previous estimates (MBOE) | 7,045 | 16,916 | 26,049 |
Reinterpretation of Undeveloped Locations | |||
Net proved oil and natural gas reserves | |||
Revisions of previous estimates (MBOE) | 6,492 | 18,435 | 10,325 |
Removed due to derecognition of certain proved undeveloped locations | |||
Net proved oil and natural gas reserves | |||
Revisions of previous estimates (MBOE) | 2,292 | ||
Drilling of New Wells | |||
Net proved oil and natural gas reserves | |||
Extensions, discoveries and other additions (MBOE) | 25,617 | 18,985 | 13,302 |
Horizontal Proved Undeveloped Properties | |||
Net proved oil and natural gas reserves | |||
Extensions, discoveries and other additions (MBOE) | 18,452 | 15,936 | 11,638 |
Supplemental oil, NGL and nat_7
Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) bbl in Thousands, MMcf in Thousands, Boe in Thousands | 12 Months Ended | ||
Dec. 31, 2018Boereserves_streambblMMcf | Dec. 31, 2017Boereserves_streambblMMcf | Dec. 31, 2016Boereserves_streambblMMcf | |
Net proved oil and natural gas reserves | |||
Number of reportable reserves streams | reserves_stream | 3 | 3 | 3 |
Proved developed and undeveloped reserves: | |||
Beginning of year (MBOE) | Boe | 215,883 | 167,100 | 125,698 |
Revisions of previous estimates (MBOE) | Boe | 2,173 | 35,351 | 34,082 |
Extensions, discoveries and other additions (MBOE) | Boe | 44,069 | 34,921 | 24,940 |
Purchases of reserves in place (MBOE) | Boe | 1,521 | 529 | |
Sales of reserves in place (MBOE) | Boe | (598) | (218) | |
Production (MBOE) | Boe | (24,881) | (21,270) | (18,149) |
End of year (MBOE) | Boe | 238,167 | 215,883 | 167,100 |
Proved developed reserves: | |||
Beginning of year (energy) | Boe | 191,309 | 141,155 | 100,395 |
End of year (energy) | Boe | 217,105 | 191,309 | 141,155 |
Proved undeveloped reserves: | |||
Beginning of year (energy) | Boe | 24,574 | 25,945 | 25,303 |
End of year (energy) | Boe | 21,062 | 24,574 | 25,945 |
Oil (MBbl) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 79,413 | 63,940 | 52,639 |
Revisions of previous estimates | (20,921) | 9,818 | 8,726 |
Extensions, discoveries and other additions | 13,330 | 15,250 | 10,741 |
Purchases of reserves in place | 596 | 276 | |
Divestitures of reserves in place | (349) | (120) | |
Production | (10,175) | (9,475) | (8,442) |
End of year | 61,894 | 79,413 | 63,940 |
Proved developed reserves: | |||
Beginning of year (volume) | 68,877 | 53,156 | 40,944 |
End of year (volume) | 55,893 | 68,877 | 53,156 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | 10,536 | 10,784 | 11,695 |
End of year (volume) | 6,001 | 10,536 | 10,784 |
NGL (MBbl) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 67,371 | 50,350 | 36,067 |
Revisions of previous estimates | 11,089 | 13,158 | 12,021 |
Extensions, discoveries and other additions | 15,112 | 9,711 | 6,930 |
Purchases of reserves in place | 457 | 116 | |
Divestitures of reserves in place | (123) | (48) | |
Production | (7,259) | (5,800) | (4,784) |
End of year | 86,647 | 67,371 | 50,350 |
Proved developed reserves: | |||
Beginning of year (volume) | 60,441 | 42,950 | 29,349 |
End of year (volume) | 79,241 | 60,441 | 42,950 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | 6,930 | 7,400 | 6,718 |
End of year (volume) | 7,406 | 6,930 | 7,400 |
Natural gas (MMcf) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | MMcf | 414,592 | 316,857 | 221,952 |
Revisions of previous estimates | MMcf | 72,028 | 74,247 | 80,004 |
Extensions, discoveries and other additions | MMcf | 93,762 | 59,759 | 43,614 |
Purchases of reserves in place | MMcf | 2,810 | 822 | |
Divestitures of reserves in place | MMcf | (756) | (299) | |
Production | MMcf | (44,680) | (35,972) | (29,535) |
End of year | MMcf | 537,756 | 414,592 | 316,857 |
Proved developed reserves: | |||
Beginning of year (volume) | MMcf | 371,946 | 270,291 | 180,613 |
End of year (volume) | MMcf | 491,828 | 371,946 | 270,291 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | MMcf | 42,646 | 46,566 | 41,339 |
End of year (volume) | MMcf | 45,928 | 42,646 | 46,566 |
Supplemental oil, NGL and nat_8
Supplemental oil, NGL and natural gas disclosures (unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Future cash inflows | $ 6,266,862 | $ 5,777,533 | $ 3,548,567 | |
Future production costs | (1,977,401) | (1,675,837) | (1,238,369) | |
Future development costs | (257,310) | (307,689) | (290,505) | |
Future income tax expenses | (226,183) | (237,153) | 0 | |
Future net cash flows | 3,805,968 | 3,556,854 | 2,019,693 | |
10% discount for estimated timing of cash flows | (1,691,731) | (1,786,533) | (1,041,199) | |
Standardized measure of discounted future net cash flows | $ 2,114,237 | $ 1,770,321 | $ 978,494 | $ 830,747 |
Supplemental oil, NGL and nat_9
Supplemental oil, NGL and natural gas disclosures (unaudited) - Changes in the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Standardized measure of discounted future net cash flows, beginning of year | $ 1,770,321 | $ 978,494 | $ 830,747 |
Changes in the year resulting from: | |||
Sales, less production costs | (656,080) | (508,656) | (322,573) |
Revisions of previous quantity estimates | (179,912) | 289,150 | 179,297 |
Extensions, discoveries and other additions | 521,605 | 296,129 | 133,472 |
Net change in prices and production costs | 365,902 | 474,831 | (80,102) |
Changes in estimated future development costs | 7,246 | 10,989 | 22,153 |
Previously estimated development costs incurred during the period | 207,865 | 192,332 | 189,085 |
Acquisitions of reserves in place | 11,411 | 0 | 3,422 |
Divestitures of reserves in place | (6,015) | (793) | 0 |
Accretion of discount | 181,693 | 97,849 | 83,075 |
Net change in income taxes | (10,340) | (46,610) | 0 |
Timing differences and other | (99,459) | (13,394) | (60,082) |
Standardized measure of discounted future net cash flows, end of year | $ 2,114,237 | $ 1,770,321 | $ 978,494 |
Supplemental quarterly financ_3
Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $ 215,287 | $ 279,746 | $ 351,046 | $ 259,696 | $ 240,337 | $ 205,818 | $ 187,001 | $ 189,006 | $ 1,105,775 | $ 822,162 | $ 597,378 |
Operating income | 56,123 | 104,410 | 94,767 | 93,192 | 85,833 | 60,452 | 52,061 | 51,326 | 348,492 | 249,672 | (87,962) |
Net income | $ 149,573 | $ 55,050 | $ 33,452 | $ 86,520 | $ 408,561 | $ 11,027 | $ 61,110 | $ 68,276 | $ 324,595 | $ 548,974 | $ (260,739) |
Net income per common share: | |||||||||||
Basic (in dollars per share) | $ 0.65 | $ 0.24 | $ 0.14 | $ 0.36 | $ 1.71 | $ 0.05 | $ 0.26 | $ 0.29 | $ 1.40 | $ 2.30 | $ (1.16) |
Diluted (in dollars per share) | $ 0.65 | $ 0.24 | $ 0.14 | $ 0.36 | $ 1.70 | $ 0.05 | $ 0.25 | $ 0.28 | $ 1.39 | $ 2.29 | $ (1.16) |