Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 12, 2016 | Jun. 30, 2015 | |
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, 2015 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 213,747,873 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Entity voluntary filer | No | ||
Entity well known seasoned issuer | Yes | ||
Entity public float | $ 1.2 |
Consolidated balance sheets
Consolidated balance sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Current assets: | |||
Cash and cash equivalents | $ 31,154 | $ 29,321 | |
Accounts receivable, net | 87,699 | 126,929 | |
Derivatives | 198,805 | 194,601 | |
Other current assets | 14,574 | 14,402 | |
Total current assets | 332,232 | 365,253 | |
Oil and natural gas properties, full cost method: | |||
Evaluated properties | 5,103,635 | 4,446,781 | |
Unevaluated properties not being depleted | 140,299 | 342,731 | |
Less accumulated depletion, depreciation, amortization and impairment | (4,218,942) | (1,586,237) | |
Oil and natural gas properties, net | 1,024,992 | 3,203,275 | |
Midstream service assets, net | 131,725 | 108,462 | |
Other fixed assets, net | 43,538 | 42,345 | |
Property and equipment, net | 1,200,255 | 3,354,082 | |
Derivatives | 77,443 | 117,788 | |
Investment in equity method investee | 192,524 | 58,288 | |
Other assets, net | 10,833 | 15,290 | |
Total assets | 1,813,287 | 3,910,701 | |
Current liabilities: | |||
Accounts payable | 14,181 | 39,008 | |
Undistributed revenue and royalties | 34,540 | 65,438 | |
Accrued capital expenditures | 61,872 | 148,241 | |
Derivatives | 0 | 115 | |
Other current liabilities | 106,222 | 101,032 | |
Total current liabilities | 216,815 | 353,834 | |
Long-term debt, net | 1,416,226 | 1,779,447 | |
Deferred income taxes, net | 0 | 176,945 | [1] |
Asset retirement obligations | 44,759 | 31,042 | |
Other noncurrent liabilities | 4,040 | 6,232 | |
Total liabilities | $ 1,681,840 | $ 2,347,500 | |
Commitments and contingencies | |||
Stockholders' equity: | |||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at December 31, 2015 and 2014 | $ 0 | $ 0 | |
Common stock, $0.01 par value, 450,000,000 shares authorized, and 213,808,003 and 143,686,491 issued, at December 31, 2015 and 2014, respectively | 2,138 | 1,437 | |
Additional paid-in capital | 2,086,652 | 1,309,171 | |
(Accumulated deficit) retained earnings | (1,957,343) | 252,593 | |
Total stockholders' equity | 131,447 | 1,563,201 | |
Total liabilities and stockholders' equity | $ 1,813,287 | $ 3,910,701 | |
[1] | See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014. |
Consolidated balance sheets (Pa
Consolidated balance sheets (Parenthetical) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 450,000,000 | 450,000,000 |
Common stock issued | 213,808,003 | 143,686,491 |
Consolidated statements of oper
Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Revenues: | |||||
Oil, NGL and natural gas sales | $ 431,734 | $ 737,203 | $ 664,844 | ||
Midstream service revenues | 6,548 | 2,245 | 413 | ||
Sales of purchased oil | 168,358 | 54,437 | 0 | ||
Total revenues | 606,640 | 793,885 | 665,257 | ||
Costs and expenses: | |||||
Lease operating expenses | 108,341 | 96,503 | 79,136 | ||
Production and ad valorem taxes | 32,892 | 50,312 | 42,396 | ||
Midstream service expenses | 5,846 | 5,429 | 3,368 | ||
Minimum volume commitments | 5,235 | 2,552 | 891 | ||
Costs of purchased oil | 174,338 | 53,967 | 0 | ||
Drilling rig fees | 0 | 527 | 0 | ||
General and administrative | [1] | 90,425 | 106,044 | 89,696 | |
Restructuring expenses | 6,042 | 0 | 0 | ||
Accretion of asset retirement obligations | 2,423 | 1,787 | 1,475 | ||
Depletion, depreciation and amortization | [2] | 277,724 | 246,474 | 233,944 | |
Impairment expense | 2,374,888 | 3,904 | 0 | ||
Total costs and expenses | 3,078,154 | 567,499 | 450,906 | ||
Operating income (loss) | (2,471,514) | 226,386 | 214,351 | ||
Gain (loss) on derivatives: | |||||
Commodity derivatives, net | 214,291 | 327,920 | 79,902 | ||
Interest rate derivatives, net | 0 | 0 | (24) | ||
Income (loss) from equity method investee | 6,799 | (192) | 29 | ||
Interest expense | [3] | (103,219) | (121,173) | (100,327) | |
Interest and other income | 426 | 294 | 163 | ||
Loss on early redemption of debt | (31,537) | [4] | 0 | 0 | |
Write-off of debt issuance costs | 0 | (124) | (1,502) | ||
Loss on disposal of assets, net | (2,127) | (3,252) | (1,508) | ||
Non-operating income (expense), net | 84,633 | 203,473 | (23,267) | ||
Income (loss) from continuing operations before income taxes | (2,386,881) | 429,859 | 191,084 | ||
Income tax benefit (expense): | |||||
Deferred | 176,945 | (164,286) | (74,507) | ||
Total income tax benefit (expense) | [5] | 176,945 | (164,286) | (74,507) | |
Income (loss) from continuing operations | (2,209,936) | 265,573 | 116,577 | ||
Income from discontinued operations, net of tax | 0 | 0 | 1,423 | ||
Net income (loss) | $ (2,209,936) | $ 265,573 | $ 118,000 | ||
Basic: | |||||
Income (loss) from continuing operations (in dollars per share) | $ (11.10) | $ 1.88 | $ 0.88 | ||
Income from discontinued operations, net of tax (in dollars per share) | 0 | 0 | 0.01 | ||
Net income (loss) per share (in dollars per share) | (11.10) | 1.88 | 0.89 | ||
Diluted: | |||||
Income (loss) from continuing operations (in dollars per share) | (11.10) | 1.85 | 0.87 | ||
Income from discontinued operations, net of tax (in dollars per share) | 0 | 0 | 0.01 | ||
Net income (loss) per share (in dollars per share) | $ (11.10) | $ 1.85 | $ 0.88 | ||
Weighted average common shares outstanding: | |||||
Basic (in shares) | [6] | 199,158 | 141,312 | 132,490 | |
Diluted (in shares) | 199,158 | 143,554 | 134,378 | ||
[1] | General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013. | ||||
[2] | Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. | ||||
[3] | Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013. | ||||
[4] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015. | ||||
[5] | Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% | ||||
[6] | For the year ended December 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders was computed taking into account the March 2015 Equity Offering. For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders was computed taking into account the August 2013 Equity Offering. |
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) retained earnings |
Balance at beginning of year (in shares) at Dec. 31, 2012 | 128,298 | 8 | |||
Balance at beginning of year at Dec. 31, 2012 | $ 831,723 | $ 1,283 | $ 961,424 | $ (4) | $ (130,980) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (in shares) | 1,469 | ||||
Restricted stock awards | $ 15 | (15) | |||
Restricted stock forfeitures (in shares) | (229) | ||||
Restricted stock forfeitures | $ (2) | 2 | |||
Vested restricted stock exchanged for tax withholding (in shares) | 95 | ||||
Vested restricted stock exchanged for tax withholding | (2,083) | $ (2,083) | |||
Retirement of treasury stock (in shares) | (95) | (103) | |||
Retirement of treasury stock | $ (1) | (2,086) | $ 2,087 | ||
Exercise of employee stock options (in shares) | 104 | ||||
Exercise of employee stock options | 2,050 | $ 1 | 2,049 | ||
Equity issuance, net of offering costs (in shares) | 13,000 | ||||
Equity issuance, net of offering costs | 298,104 | $ 130 | 297,974 | ||
Equity issued for acquisition, net of offering costs (in shares) | 124 | ||||
Equity issued for acquisition, net of offering costs | 3,029 | $ 1 | 3,028 | ||
Stock-based compensation | 21,433 | 21,433 | |||
Net income (loss) | 118,000 | 118,000 | |||
Balance at end of year (in shares) at Dec. 31, 2013 | 142,671 | 0 | |||
Balance at end of year at Dec. 31, 2013 | 1,272,256 | $ 1,427 | 1,283,809 | $ 0 | (12,980) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (in shares) | 1,234 | ||||
Restricted stock awards | $ 12 | (12) | |||
Restricted stock forfeitures (in shares) | (148) | ||||
Restricted stock forfeitures | $ (1) | 1 | |||
Vested restricted stock exchanged for tax withholding (in shares) | 166 | ||||
Vested restricted stock exchanged for tax withholding | (4,242) | $ (4,242) | |||
Retirement of treasury stock (in shares) | (166) | (166) | |||
Retirement of treasury stock | $ (2) | (4,240) | $ 4,242 | ||
Exercise of employee stock options (in shares) | 95 | ||||
Exercise of employee stock options | 1,885 | $ 1 | 1,884 | ||
Stock-based compensation | 27,729 | 27,729 | |||
Net income (loss) | 265,573 | 265,573 | |||
Balance at end of year (in shares) at Dec. 31, 2014 | 143,686 | 0 | |||
Balance at end of year at Dec. 31, 2014 | 1,563,201 | $ 1,437 | 1,309,171 | $ 0 | 252,593 |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (in shares) | 1,902 | ||||
Restricted stock awards | $ 19 | (19) | |||
Restricted stock forfeitures (in shares) | (553) | ||||
Restricted stock forfeitures | $ (6) | 6 | |||
Vested restricted stock exchanged for tax withholding (in shares) | 227 | ||||
Vested restricted stock exchanged for tax withholding | (2,811) | $ (2,811) | |||
Retirement of treasury stock (in shares) | (227) | (227) | |||
Retirement of treasury stock | $ (2) | (2,809) | $ 2,811 | ||
Equity issued for acquisition, net of offering costs (in shares) | 69,000 | ||||
Equity issued for acquisition, net of offering costs | 754,163 | $ 690 | 753,473 | ||
Stock-based compensation | 26,830 | 26,830 | |||
Net income (loss) | (2,209,936) | (2,209,936) | |||
Balance at end of year (in shares) at Dec. 31, 2015 | 213,808 | 0 | |||
Balance at end of year at Dec. 31, 2015 | $ 131,447 | $ 2,138 | $ 2,086,652 | $ 0 | $ (1,957,343) |
Consolidated statements of cash
Consolidated statements of cash flows - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Cash flows from operating activities: | ||||
Net income (loss) | $ (2,209,936) | $ 265,573 | $ 118,000 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
Deferred income tax (benefit) expense | (176,945) | 164,286 | 75,288 | |
Depletion, depreciation and amortization | 277,724 | 246,474 | 234,571 | |
Impairment expense | 2,374,888 | 3,904 | 0 | |
Loss on early redemption of debt | 31,537 | [1] | 0 | 0 |
Bad debt expense | 255 | 342 | 653 | |
Non-cash stock-based compensation, net of amounts capitalized | 24,509 | 23,079 | 21,433 | |
Accretion of asset retirement obligations | 2,423 | 1,787 | 1,475 | |
Mark-to-market on derivatives: | ||||
Gain on derivatives, net | (214,291) | (327,920) | (79,878) | |
Cash settlements received for matured derivatives, net | 255,281 | 28,241 | 3,745 | |
Cash settlements received for early terminations and modification of derivatives, net | 0 | 76,660 | 6,008 | |
Change in net present value of deferred premiums paid for derivatives | 203 | 220 | 462 | |
Cash premiums paid for derivatives | (5,167) | (7,419) | (10,277) | |
Amortization of debt issuance costs | 4,727 | 5,137 | 5,023 | |
Write-off of debt issuance costs | 0 | 124 | 1,502 | |
Loss on disposal of assets, net | 2,127 | 3,252 | 1,508 | |
(Income) loss on equity method investee | (6,799) | 192 | (29) | |
Cash settlement of performance unit awards | (2,738) | 0 | (2,080) | |
Other, net | 4 | 403 | (230) | |
Decrease (increase) in accounts receivable | 38,975 | (49,953) | 6,825 | |
Increase in other assets | (2,309) | (16,688) | (7,438) | |
(Decrease) increase in accounts payable | (24,827) | 23,006 | (32,581) | |
(Decrease) increase in undistributed revenues and royalties | (30,898) | 30,314 | (941) | |
(Decrease) increase in other accrued liabilities | (26,996) | 23,837 | 16,458 | |
Increase in other noncurrent liabilities | 119 | 2,825 | 499 | |
Increase in fair value of performance unit awards | 4,081 | 601 | 4,733 | |
Net cash provided by operating activities | 315,947 | 498,277 | 364,729 | |
Capital expenditures: | ||||
Acquisitions of oil and natural gas properties | 0 | (6,493) | (33,710) | |
Acquisition of mineral interests | 0 | (7,305) | 0 | |
Oil and natural gas properties | (588,017) | (1,251,757) | (702,349) | |
Midstream service assets | (35,459) | (60,548) | (24,409) | |
Other fixed assets | (9,125) | (27,444) | (16,257) | |
Investment in equity method investee | (99,855) | (55,164) | (3,287) | |
Proceeds from dispositions of capital assets, net of costs | 64,949 | 1,750 | 450,128 | |
Net cash used in investing activities | (667,507) | (1,406,961) | (329,884) | |
Cash flows from financing activities: | ||||
Borrowings on Senior Secured Credit Facility | 310,000 | 300,000 | 230,000 | |
Payments on Senior Secured Credit Facility | (475,000) | 0 | (395,000) | |
Redemption of January 2019 Notes | (576,200) | 0 | 0 | |
Proceeds from issuance of common stock, net of offering costs | 754,163 | 0 | 298,104 | |
Purchase of treasury stock | (2,811) | (4,242) | (2,083) | |
Proceeds from exercise of employee stock options | 0 | 1,885 | 2,050 | |
Payments for debt issuance costs | (6,759) | (7,791) | (2,987) | |
Net cash provided by financing activities | 353,393 | 739,852 | 130,084 | |
Net increase (decrease) in cash and cash equivalents | 1,833 | (168,832) | 164,929 | |
Cash and cash equivalents, beginning of period | 29,321 | 198,153 | 33,224 | |
Cash and cash equivalents, end of period | 31,154 | 29,321 | 198,153 | |
March 2023 Notes | ||||
Cash flows from financing activities: | ||||
Issuance of long-term debt | 350,000 | 0 | 0 | |
January 2022 Notes | ||||
Cash flows from financing activities: | ||||
Issuance of long-term debt | $ 0 | $ 450,000 | $ 0 | |
[1] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015. |
Organization
Organization | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Organization The Company (defined below) is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. On August 1, 2013, the Company sold its properties in the Mid-Continent region of the United States (as further described below). Laredo Petroleum, Inc. ("Laredo"), formerly known as Laredo Petroleum Holdings, Inc., was formed pursuant to the laws of the State of Delaware on August 12, 2011 for purposes of a Corporate Reorganization (defined below) and initial public offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, was merged with and into Laredo, with Laredo surviving the merger (the "Corporate Reorganization"). As a holding company, Laredo's management operations were conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo Inc."), a Delaware corporation, and Laredo Inc's subsidiaries, Laredo Petroleum Texas, LLC ("Laredo Texas"), a Texas limited liability company, Laredo Gas Services, LLC ("Laredo Gas"), a Delaware limited liability company, and Laredo Petroleum—Dallas, Inc. ("Laredo Dallas"), a Delaware corporation. Effective December 31, 2013, an internal corporate reorganization was completed, which simplified the corporate structure. Two of Laredo Inc.'s subsidiaries, Laredo Texas and Laredo Dallas, were merged with and into Laredo Inc. The sole remaining wholly-owned subsidiary of Laredo Inc. at the time of the internal corporate reorganization, Laredo Gas, changed its name to Laredo Midstream Services, LLC ("LMS"). Laredo Inc. merged with and into Laredo with Laredo surviving and changing its name to "Laredo Petroleum, Inc." (the events described in this paragraph collectively, the "Internal Consolidation"). On October 24, 2014, Laredo formed Garden City Minerals, LLC ("GCM"), a Delaware limited liability company, for the purpose of holding its mineral interests. GCM is wholly owned by Laredo. GCM and LMS (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company," (i) when used in the present tense, prospectively or from October 24, 2014, refers to Laredo, LMS and GCM collectively; (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refers to Laredo and LMS collectively; and (iii) when used for historical periods from December 19, 2011 to December 30, 2013, refers to Laredo and its subsidiaries, 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 operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and certain third parties with (i) products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in and around Laredo's primary production corridors, (ii) water takeaway in and around Laredo's primary production corridors and (iii) oil and natural gas takeaway optionality in the field coupled with firm service commitments to maximize Laredo's oil, natural gas liquids ("NGL") and natural gas revenues. |
Basis of presentation and signi
Basis of presentation and significant accounting policies | 12 Months Ended |
Dec. 31, 2015 | |
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. Unless otherwise indicated, the information in these notes relates to the Company's continuing operations. 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 (loss) is included in the consolidated statements of operations. See Note 15 for additional discussion of the Company's 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) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of commodity derivatives, commodity deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. 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 2015 presentation. These reclassifications had no impact to previously reported net income, stockholders' equity or cash flows. See Notes 7 and 14 for discussion regarding reclassifications related to the Company's early adoption of new guidance related to the classification of income taxes. See Notes 2.k, 5.h and 14 for discussion regarding the Company's early adoption of new guidance related to the presentation of deferred loan costs. 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 11 for discussion regarding the Company's exposure to credit risk. e. Accounts receivable The Company sells produced and purchased oil, NGL and natural gas to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize the receivables through netting of anticipated future production revenues. 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 over 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 December 31: (in thousands) 2015 2014 Matured derivatives $ 27,469 $ 16,098 Oil, NGL and natural gas sales 25,582 57,070 Joint operations, net (1) 21,375 33,808 Purchased oil and other product sales 11,775 18,917 Other 1,498 1,036 Total $ 87,699 $ 126,929 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of December 31, 2015 and 2014, respectively. f. Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant 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 due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and basis swaps. In addition, in prior periods the Company entered into interest rate derivatives. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives 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. See Note 9 for discussion regarding the fair value of the Company's derivatives. The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's commodity derivatives. g. Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite units 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 amortized 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. The Company computes the provision for depletion of oil and natural gas properties using the units 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. Approximately $140.3 million and $342.7 million of such costs were excluded from the depletion base as of December 31, 2015 and 2014, respectively. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Total accumulated depletion and impairment for oil and natural gas properties was $4.2 billion and $1.6 billion for the years ended December 31, 2015 and 2014, respectively. Depletion expense for oil and natural gas properties was $263.7 million , $237.1 million and $228.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $16.13 , $ 20.21 and $20.34 for the years ended December 31, 2015, 2014 and 2013, respectively. The Company excludes the costs directly associated with 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 on 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 property are assessed on a quarterly basis for possible impairment or reduction in value. 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% . Per the Securities and Exchange Commission ("SEC") guidelines, companies are required 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. In the event the unamortized cost of evaluated oil and natural gas properties being amortized 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, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented: For the quarters ended For the years ended (1) December 31, 2015 September 30, 2015 June 30, 2015 March 31, 2015 December 31, 2014 December 31, 2013 Benchmark Prices Oil ($/Bbl) $ 46.79 $ 55.73 $ 68.17 $ 79.21 $ 91.48 $ 93.52 NGL ($/Bbl) 18.75 21.87 26.73 31.25 — — Natural gas ($/MMBtu) 2.47 2.89 3.22 3.73 4.25 3.57 Realized Prices Oil ($/Bbl) 45.58 54.28 66.68 77.72 89.57 92.26 NGL ($/Bbl) 12.50 15.25 19.56 23.75 — — Natural gas ($/Mcf) 1.89 2.30 2.62 3.09 6.39 5.52 Non-cash full cost ceiling impairment (in thousands) $ 975,011 $ 906,420 $ 488,046 $ — $ — $ — _____________________________________________________________________________ (1) For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods. Full cost ceiling impairment expense for the year ended December 31, 2015 in the consolidated statements of operations was $2.4 billion . The amount is included in the "Impairment expense" line item in the consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 17. h. Midstream service assets Midstream service assets 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. The oil and natural gas pipeline gathering assets, related equipment, oil delivery stations and water storage and treatment facilities are recorded at cost, net of impairment. See Note 2.m 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 from continuing operations for midstream service assets was $7.5 million , $4.3 million and $1.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. Midstream service assets consist of the following as of December 31: (in thousands) 2015 2014 Midstream service assets $ 147,811 $ 117,052 Less accumulated depreciation (16,086 ) (8,590 ) Total, net $ 131,725 $ 108,462 i. 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 from continuing operations for other fixed assets was $6.5 million , $5.1 million and $4.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. Other fixed assets consist of the following as of December 31: (in thousands) 2015 2014 Computer hardware and software $ 12,148 $ 13,495 Vehicles 9,266 7,802 Leasehold improvements 7,710 6,867 Real estate and buildings 7,618 4,908 Aircraft 4,952 4,952 Other 5,105 4,909 Depreciable total 46,799 42,933 Less accumulated depreciation and amortization (18,169 ) (13,820 ) Depreciable total, net 28,630 29,113 Land 14,908 13,232 Total, net $ 43,538 $ 42,345 j. Long-lived assets, materials and supplies and line-fill Impairment losses are recorded on property and equipment used in operations and other 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. Materials and supplies used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") and are included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. The market price for materials and supplies is determined utilizing the Company's recent prices paid to acquire materials. During the years ended December 31, 2015 and 2014, the Company reduced materials and supplies by $2.8 million and $1.8 million , respectively, in order to reflect the balance at LCM. These adjustments are included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's exploration and production segment presented in Note 17. The Company determined an LCM adjustment was not necessary for materials and supplies during the year ended December 31, 2013. The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill, and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Beginning in the fourth quarter of 2014, the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the years ended December 31, 2015 and 2014, the Company recorded LCM adjustments of $1.3 million and $2.1 million , respectively, related to its line-fill, which is included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's midstream and marketing segment presented in Note 17. For the year ended December 31, 2015, the Company recorded an impairment, based on an internally developed cash flow model, of $1.3 million related to its compressed natural gas station. This amount is included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's midstream and marketing segment presented in Note 17. There were no comparable impairments recorded for the years ended December 31, 2014 or 2013. k. 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. The Company capitalized $6.8 million of debt issuance costs during the year ended December 31, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). The Company capitalized $7.8 million of debt issuance costs during the year ended December 31, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below). The Company capitalized $3.0 million of debt issuance costs during the year ended December 31, 2013. The Company had total debt issuance costs of $23.9 million and $28.5 million , net of accumulated amortization of $17.0 million and $19.4 million , as of December 31, 2015 and 2014 , respectively. The Company wrote-off approximately $6.6 million of debt issuance costs during the year ended December 31, 2015 as a result of the early redemption of the January 2019 Notes (as defined below), which is included in the consolidated statements of operations in the "Loss on early redemption of debt" line item. During the year ended December 31, 2014, $0.1 million of debt issuance costs were written-off as a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the issuance of the January 2022 Notes. During the year ended December 31, 2013, $1.5 million of debt issuance costs were written off as a result of changes in the borrowing base of the Senior Secured Credit Facility due to the Anadarko Basin Sale (as defined below). Debt issuance costs written-off during the years ended December 31, 2014 and 2013 are included in the consolidated statements of operations in the "Write-off of debt issuance costs" line item. See Notes 4.d, 5.b, 5.c, 5.e and 5.f for definition of and information regarding the Anadarko Basin Sale, March 2023 Notes, January 2022 Notes, January 2019 Notes and Senior Secured Credit Facility, respectively. During the year ended December 31, 2015, the Company early-adopted new guidance that seeks to simplify the presentation of debt issuance costs and has applied its provisions retrospectively. The adoption of this standard resulted in $18.8 million and $21.8 million of unamortized debt issuance costs related to the Company's senior unsecured notes being presented in "Long-term debt, net" rather than the past presentation in "Other assets, net" within its consolidated balance sheets as of December 31, 2015 and December 31, 2014, respectively. Other than this reclassification of the December 31, 2014 amount, the adoption of this standard did not have an impact on the Company's consolidated financial statements. Debt issuance costs related to the Senior Secured Credit Facility remain presented in "Other assets, net" on the Company's consolidated balance sheets. See Notes 5.h and 14 for additional discussion of debt issuance costs. Future amortization expense of debt issuance costs as of the period presented is as follows: (in thousands) December 31, 2015 2016 $ 4,503 2017 4,575 2018 4,349 2019 2,915 2020 3,005 Thereafter 4,585 Total $ 23,932 l. Other current liabilities Other current liabilities consist of the following components as of December 31: (in thousands) 2015 2014 Capital contribution payable to equity method investee (1) $ 27,583 $ — Accrued interest payable 24,208 37,689 Accrued compensation and benefits 14,342 13,034 Lease operating expense payable 13,205 11,963 Costs of purchased oil 12,189 20,114 Other accrued liabilities 14,695 18,232 Total other current liabilities $ 106,222 $ 101,032 _____________________________________________________________________________ (1) See Notes 15, 16 and 19.b for additional discussion regarding our equity method investee. m. 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 asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding 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, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) 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, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas 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 gas gathering assets in the periods in which settlement dates are reasonably determinable. The following reconciles the Company's asset retirement obligation liability as of December 31: (in thousands) 2015 2014 Liability at beginning of year $ 32,198 $ 21,743 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 2,236 6,370 Accretion expense 2,423 1,787 Liabilities settled upon plugging and abandonment (146 ) (450 ) Liabilities removed due to sale of property (2,005 ) — Revision of estimates (1) 11,600 2,748 Liability at end of year $ 46,306 $ 32,198 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to declining commodity prices. n. Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.g for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 9 for details regarding the fair value of the Company's derivatives. o. Treasury stock Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition. p. Revenue recognition Oil, NGL and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil, NGL and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. 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, 2015 or 2014. During the year ended December 31, 2013, the majority of the Company's natural gas producer imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined below). Prior to their disposition, the value of net overproduced positions arising during the year ended December 31, 2013, which increased oil and natural gas sales, was $0.03 million . Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes title to the products and has risks and rewards of ownership. q. 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 amounts have been recorded for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Fees received for the operation of jointly-owned oil and natural gas properties $ 3,125 $ 3,265 $ 3,398 r. Compensation awards Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" 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 value 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 of the performance share awards and performance unit awards. On January 1, 2014, the Company began capitalizing 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 as an addition to "Oil and natural gas properties" in the consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards. s. 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. A valuation allowance is established to reduce deferred tax assets if it is determined 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. See Note 7 for detail of amounts recorded in the consolidated financial statements and discussion regarding the valuation allowance taken in 2015. 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 be |
Equity offering
Equity offering | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Equity offering | Equity offerings a. March 2015 Equity Offering On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share (the "March 2015 Equity Offering"). The Company received net proceeds of $754.2 million, after underwriting discounts and commissions and offering expenses, from the March 2015 Equity Offering. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock. There were no comparative offerings of the Company's stock during the year ended December 31, 2014 . b. August 2013 Equity Offering On August 19, 2013, Laredo, together with certain affiliates of Warburg Pincus and members of the Company's management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of Laredo's common stock by Laredo and (ii) 3,000,000 shares of Laredo's common stock by the Selling Stockholders, at a price to the public of $ 23.75 per share ($ 22.9781 per share, net of underwriting discounts) (the "August 2013 Equity Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of Laredo's common stock pursuant to the option to purchase additional shares of Laredo's common stock granted to the associated underwriters. The Company received net proceeds of $ 298.1 million, after underwriting discounts and commissions and offering expenses, from the August 2013 Equity Offering. The Company did not receive any proceeds from either of the sales of shares of Laredo's common stock by the Selling Stockholders. |
Acquisitions and divestitures
Acquisitions and divestitures | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions and divestitures | Acquisitions and divestitures a. 2015 Divestiture of non-strategic assets On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $ 65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $ 64.8 million, net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results. The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Oil, NGL and natural gas sales $ 5,138 $ 19,337 $ 24,187 Expenses (1) 5,791 11,082 11,826 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. b. Summary of 2014 and 2013 acquisitions 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 and integration 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 values of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted-average cost of capital rate. The market-based weighted-average cost of capital rate is subjected 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 probable and possible reserves are reduced by additional risk-weighting factors. The following table presents the Company's 2014 and 2013 acquisitions. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions, see Note C in the Company's 2013 Annual Report on Form 10-K and Note 3 in the Company's 2014 Annual Report on Form 10-K. (in thousands) Accounting treatment Cash consideration Common stock issued (2) August 28, 2014 acquisition of leasehold interests Acquisition of assets $ 192,484 $ — June 23, 2014 acquisition of evaluated and unevaluated oil and natural gas properties Acquisition method 1,800 — June 11, 2014 acquisition of evaluated and unevaluated oil and natural gas properties Acquisition method 4,693 — February 25, 2014 acquisition of mineral interests Acquisition of assets 7,305 — September 6, 2013 acquisition of evaluated and unevaluated oil and natural gas properties (1) Acquisition method 33,710 3,029 _____________________________________________________________________________ (1) The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities. (2) In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). In accordance with federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 9. c. 2013 divestiture of Dalhart Basin acreage On December 20, 2013, the Company completed the sale of 37,000 net acres and one producing property in the Dalhart Basin for $20.4 million , subject to customary closing adjustments. d. 2013 divestiture of Anadarko assets On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million , net of working capital adjustments. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The results of operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties. The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the period presented: (in thousands) For the year ended December 31, 2013 Revenues $ 59,631 Expenses (1) 46,357 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. The results of operations of the associated pipeline assets and various other associated property and equipment ("Pipeline Assets") are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the consolidated statements of operations in the line item "Loss on disposal of assets, net" during the year ended December 31, 2013. The following represents operating results from discontinued operations for the period presented: (in thousands) For the year ended December 31, 2013 Revenues: Midstream service revenue $ 4,020 Total revenues from discontinued operations 4,020 Cost and expenses: Midstream service expense, net 1,189 Depreciation and amortization 627 Total costs and expenses from discontinued operations 1,816 Non-operating expense, net — Income (loss) from discontinued operations before income tax 2,204 Income tax (expense) benefit (781 ) Income (loss) from discontinued operations $ 1,423 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Debt | Debt a. Interest expense The following amounts have been incurred and charged to interest expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Cash payments for interest $ 112,693 $ 105,086 $ 95,877 Amortization of debt issuance costs and other adjustments 4,243 4,433 4,926 Change in accrued interest (13,481 ) 11,804 (221 ) Interest costs incurred 103,455 121,323 100,582 Less capitalized interest (236 ) (150 ) (255 ) Total interest expense $ 103,219 $ 121,173 $ 100,327 b. 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 with interest accruing at a rate of 6 1/4% per annum and 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 (as defined below), 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 proceeds of the offering to fund a portion of the Company's redemption of the January 2019 Notes (as defined below). See Note 5.e for additional discussion of this early redemption. 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 the applicable redemption price plus accrued and unpaid interest to, but not including, the date of redemption. Further, before March 15, 2018, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the March 2023 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 106.25% of the principal amount of the March 2023 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the March 2023 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control occurs prior to March 15, 2016, the Company may redeem all, but not less than all, of the March 2023 Notes at a redemption price equal to 110% of the principal amount of the March 2023 Notes plus any accrued and unpaid interest to, but not including, the date of redemption. c. 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 with interest accruing at a rate of 5 5/8% per annum and 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. Laredo will have the option to redeem all or part of the January 2022 Notes at any time on and after January 15, 2017, at the applicable redemption price plus accrued and unpaid interest to the date of redemption. In addition, the Company may redeem, at its option, all or part of the January 2022 Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the January 2022 Notes redeemed plus the applicable premium and accrued and unpaid interest and additional interest, if any, to the date of redemption. Further, before January 15, 2017, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the January 2022 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 105.625% of the principal amount of the January 2022 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the January 2022 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. d. 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 will mature on May 1, 2022 and bear 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 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 May 2022 Notes were issued under, and are governed by, an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as further supplemented, the "2012 Indenture"), among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and the guarantors named therein. The 2012 Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under the May 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 Indenture. Laredo will have the option to redeem the May 2022 Notes, in whole or in part, at any time on or after May 1, 2017, at the redemption prices (expressed as percentages of principal amount) of 103.688% for the 12-month period beginning on May 1, 2017, 102.458% for the 12-month period beginning on May 1, 2018, 101.229% for the 12-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest, if any, to the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the May 2022 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Laredo may also be required to make an offer to purchase the May 2022 Notes upon a change of control triggering event. e. January 2019 Notes On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The January 2019 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. The January 2019 Notes were issued under and were governed by an indenture dated January 20, 2011 (as supplemented, the "2011 Indenture") among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and guarantors named therein. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of or similar restricted payments, the undertaking of transactions with Laredo's unrestricted affiliates and limitations on asset sales. On April 6, 2015 (the "Redemption Date"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes. f. Senior Secured Credit Facility As of December 31, 2015 , the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.15 billion and an aggregate elected commitment of $1.0 billion with $135.0 million outstanding and was subject to an interest rate of 1.90% . The borrowing base is subject to a semi-annual redetermination occurring each May 1 and November 1 based on the financial institutions' evaluation of the Company's oil 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 0.5% to 1.5% 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 1.5% to 2.5% , based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Laredo is also required to pay an annual 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 total commitment under the Senior Secured Credit Facility. The Senior Secured Credit Facility is secured by a first-priority lien on Laredo and the Guarantor's assets and stock, including oil, NGL and natural gas properties, constituting at least 80% of the present value of the Company's evaluated reserves. Further, the Company is subject to various financial and non-financial ratios 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, at the end of each calendar quarter, the Company must maintain a ratio of (I) its consolidated net income (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 all non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of 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 Senior Secured Credit Facility contains both financial and non-financial covenants and 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 $20.0 million . No letters of credit were outstanding as of December 31, 2015 or 2014. g. Fair value of debt The Company has not elected to account for its debt at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the periods presented: December 31, 2015 December 31, 2014 (in thousands) Long-term debt Fair value Long-term debt Fair value January 2019 Notes (1) $ — $ — $ 551,295 $ 550,000 January 2022 Notes 450,000 388,301 450,000 396,014 May 2022 Notes 500,000 460,000 500,000 467,529 March 2023 Notes 350,000 301,000 — — Senior Secured Credit Facility 135,000 134,993 300,000 300,279 Total value of debt $ 1,435,000 $ 1,284,294 $ 1,801,295 $ 1,713,822 _____________________________________________________________________________ (1) The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014 . The fair values of the debt outstanding on the January 2019 Notes, the January 2022 Notes, the May 2022 Notes and the March 2023 Notes were determined using the December 31, 2015 and 2014 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2015 and 2014 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels. h. Debt issuance costs The following tables summarize the net presentation of the Company's long-term debt and debt issuance cost on the consolidated balance sheets as of the periods presented: December 31, 2015 December 31, 2014 (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 2019 Notes (1) $ — $ — $ — $ 551,295 $ (7,031 ) $ 544,264 January 2022 Notes 450,000 (5,939 ) 444,061 450,000 (6,916 ) 443,084 May 2022 Notes 500,000 (7,066 ) 492,934 500,000 (7,901 ) 492,099 March 2023 Notes 350,000 (5,769 ) 344,231 — — — Senior Secured Credit Facility (2) 135,000 — 135,000 300,000 — 300,000 Total $ 1,435,000 $ (18,774 ) $ 1,416,226 $ 1,801,295 $ (21,848 ) $ 1,779,447 _____________________________________________________________________________ (1) The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014 . (2) Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the consolidated balance sheets. |
Employee compensation
Employee compensation | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Employee compensation | Employee compensation The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of 10.0 million shares. 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 its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. a. Restricted stock awards All 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 and 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 including (i) 20% at the grant date and then 20% annually thereafter, (ii) 33% , 33% and 34% per year beginning on the first anniversary date of the grant, (iii) 50% in year two and 50% in year three, (iv) fully on the first anniversary of the grant date and (v) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date. The following table reflects the outstanding restricted stock awards for the years ended December 31, 2015 , 2014 and 2013 : (in thousands, except for weighted-average grant date fair values) Restricted stock awards Weighted-average grant date fair value (per award) Outstanding as of December 31, 2012 1,195 $ 15.06 Granted 1,469 $ 18.17 Forfeited (229 ) $ 18.47 Vested (1) (636 ) $ 18.69 Outstanding as of December 31, 2013 1,799 $ 19.17 Granted 1,234 $ 25.68 Forfeited (148 ) $ 22.56 Vested (1) (680 ) $ 19.13 Outstanding as of December 31, 2014 2,205 $ 22.63 Granted 1,902 $ 11.98 Forfeited (553 ) $ 20.48 Vested (1) (1,015 ) $ 22.32 Outstanding as of December 31, 2015 2,539 $ 15.26 _____________________________________________________________________________ (1) The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards. 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, 2015 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $21.6 million . Such cost is expected to be recognized over a weighted-average period of 1.74 years. b. Restricted stock option awards Restricted stock option awards granted under the LTIP vest and are 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, 2015 , 2014 and 2013 : (in thousands, except for weighted-average price and contractual term) Restricted stock option awards Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2012 459 $ 24.11 10 Granted 1,019 $ 17.34 Exercised (1) (104 ) $ 20.79 Expired or canceled (12 ) $ 24.11 Forfeited (133 ) $ 19.88 Outstanding as of December 31, 2013 1,229 $ 19.32 8.82 Granted 336 $ 25.60 Exercised (1) (95 ) $ 19.93 Expired or canceled (30 ) $ 21.15 Forfeited (73 ) $ 19.68 Outstanding as of December 31, 2014 1,367 $ 20.76 8.17 Granted 632 $ 11.93 Exercised — $ — Expired or canceled (82 ) $ 19.92 Forfeited (139 ) $ 18.17 Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Vested and exercisable at end of period (2) 545 $ 20.77 6.94 Expected to vest at end of period (3) 1,219 $ 16.51 8.34 _____________________________________________________________________________ (1) The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards. (2) The vested and exercisable options as of December 31, 2015 had no aggregate intrinsic value. (3) The restricted stock options expected to vest as of December 31, 2015 had no aggregate intrinsic value. The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and is recognizing 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, 2015 , unrecognized stock-based compensation related to restricted stock option awards expected to vest was $7.0 million . Such cost is expected to be recognized over a weighted-average period of 2.35 years. The assumptions used to estimate the fair value of restricted stock options granted are as follows: February 27, 2015 February 27, 2014 February 15, 2013 February 3, 2012 Risk-free interest rate (1) 1.70 % 1.88 % 1.19 % 1.14 % Expected option life (2) 6.25 years 6.25 years 6.25 years 6.25 years Expected volatility (3) 52.59 % 53.21 % 58.89 % 59.98 % Fair value per stock option $ 6.15 $ 13.41 $ 9.67 $ 13.52 _____________________________________________________________________________ (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 option. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option 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 for the February 27, 2015 grant. The prior grants utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility. In accordance with the LTIP and stock option agreement, the options 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 option 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. c. Performance share awards The performance share awards granted to management on February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three -year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria. The 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017 and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. During the year ended December 31, 2015 , the Company granted 602,501 2015 Performance Share Awards and all remain outstanding as of December 31, 2015 . The 271,667 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016 and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met. No 2014 Performance Share Awards were forfeited during the years ended December 31, 2015 or 2014. As of December 31, 2015 , unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was $9.9 million . Such cost is expected to be recognized over a weighted-average period of 1.86 years. The assumptions used to estimate the fair value of the Performance Share Awards granted are as follows: February 27, 2015 February 27, 2014 Risk-free rate (1) 0.95 % 0.63 % Dividend yield — % — % Expected volatility (2) 53.78 % 38.21 % Laredo stock closing price as of the grant date $ 11.93 $ 25.60 Fair value per performance share $ 16.23 $ 28.56 _____________________________________________________________________________ (1) The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date. (2) The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility. d. Stock-based compensation award expense The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Restricted stock award compensation $ 17,534 $ 21,982 $ 17,084 Restricted stock option award compensation 4,074 3,639 4,349 Restricted performance share award compensation 5,222 2,108 — Total stock-based compensation, gross 26,830 27,729 21,433 Less amounts capitalized in oil and natural gas properties (2,321 ) (4,650 ) — Total stock-based compensation, net of amounts capitalized $ 24,509 $ 23,079 $ 21,433 During the year ended December 31, 2013, two officers' and 20 employees' restricted stock awards and restricted option awards were modified to vest upon the officers' or the employees' retirement or in connection with the employees' termination of employment as a result of the Anadarko Basin Sale. The incremental compensation cost resulting from these modifications recognized during the year ended December 31, 2013 was $4.7 million . e. Performance unit awards The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") 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 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. The 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100 per unit during the first quarter of 2015. The following table reflects the outstanding performance unit awards for the periods presented: (in thousands) 2013 Performance Unit Awards (2) 2012 Performance Unit Awards (3) Outstanding at December 31, 2012 — 47 Granted 58 — Forfeited (4 ) (9 ) Vested (1) (10 ) (11 ) Outstanding at December 31, 2013 44 27 Vested — (27 ) Outstanding at December 31, 2014 44 — Vested (44 ) — Outstanding at December 31, 2015 — — _____________________________________________________________________________ (1) During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit. (2) The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016. (3) The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015. The liability related to the 2013 Performance Unit Awards as of December 31, 2015 was $6.4 million and represents the cash payment made in the first quarter of 2016. The fair value of the 2013 Performance Unit Awards as of December 31, 2014 was $3.5 million . The liability related to the 2012 Performance Unit Awards as of December 31, 2014 was $2.7 million and represents the cash payment made in the first quarter of 2015. The fair values of the 2013 Performance Unit Awards and 2012 Performance Unit Awards as of December 31, 2013 were $5.7 million and $3.8 million , respectively. The following has been recorded to performance unit award compensation expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 2013 Performance Unit Award compensation expense $ 4,081 $ 409 $ 2,863 2012 Performance Unit Award compensation expense — 192 1,870 Total performance unit award compensation expense $ 4,081 $ 601 $ 4,733 Compensation expense for the 2012 Performance Unit Awards and the 2013 Performance Unit Awards is recognized in "General and administrative" in the Company's consolidated statements of operations, and the corresponding liabilities are included in "Other current liabilities" and "Other noncurrent liabilities" on the consolidated balance sheets. f. 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) 2015 2014 2013 Contributions $ 1,847 $ 2,202 $ 1,886 |
Income taxes
Income taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
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. The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit (expense) attributable to income (loss) from continuing operations for the periods presented consisted of the following: For the years ended December 31, (in thousands) 2015 2014 2013 Current taxes: Federal $ — $ — $ — State — — — Deferred taxes: Federal 152,590 (147,445 ) (64,034 ) State 24,355 (16,841 ) (10,473 ) Income tax benefit (expense) $ 176,945 $ (164,286 ) $ (74,507 ) The following presents the comprehensive benefit (expense) for income taxes for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Comprehensive benefit (expense) for income taxes allocable to: Continuing operations $ 176,945 $ (164,286 ) $ (74,507 ) Discontinued operations — — (781 ) Comprehensive benefit (expense) for income taxes $ 176,945 $ (164,286 ) $ (75,288 ) Income tax benefit (expense) attributable to income (loss) from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2015 and 2014 and 34% for the year ended December 31, 2013 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2015 2014 2013 Income tax benefit (expense) computed by applying the statutory rate $ 835,408 $ (150,450 ) $ (64,969 ) State income tax, net of federal tax benefit and increase in valuation allowance 13,975 (11,099 ) (7,532 ) Non-deductible stock-based compensation (256 ) (509 ) (1,070 ) Stock-based compensation tax deficiency (3,274 ) (266 ) (559 ) Increase in deferred tax valuation allowance (668,702 ) (1,139 ) (63 ) Other items (206 ) (823 ) (314 ) Income tax benefit (expense) $ 176,945 $ (164,286 ) $ (74,507 ) The effective tax rate for the Company's continuing operations was 7% , 38% and 39% for the years ended December 31, 2015, 2014 and 2013, respectively. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. 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 2015, in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realized 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 and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, therefore a valuation allowance of $676.0 million was recorded. The impact of significant discrete items is separately recognized in the year in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the years ended December 31, 2015, 2014 and 2013, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the years ended December 31, 2014 and 2013, certain restricted stock options were exercised. There were no comparable exercise of stock options during the year ended December 31, 2015. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax benefit (expense) attributable to continuing operations. The following table presents the tax impact of these shortfalls for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Vesting of restricted stock $ 3,334 $ 112 $ 425 Exercise of restricted stock options — 158 150 Tax expense due to shortfalls $ 3,334 $ 270 $ 575 Significant components of the Company's net deferred tax liability as of December 31 are as follows: (in thousands) 2015 2014 Oil and natural gas properties, midstream service assets and other fixed assets $ 306,997 $ (424,712 ) Net operating loss carry-forward 479,022 353,724 Derivatives (98,675 ) (121,365 ) Stock-based compensation 11,597 10,718 Equity method investee (31,711 ) (2,331 ) Accrued bonus 4,763 3,256 Capitalized interest 2,525 3,049 Materials and supplies impairment 1,647 642 Other 1,173 1,373 Net deferred tax asset (liability) before valuation allowance 677,338 (175,646 ) Valuation allowance (677,338 ) (1,299 ) Net deferred tax asset (liability) $ — $ (176,945 ) Deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 are as follows: (in thousands) 2015 2014 (1) Offset (1) 2014 new presentation (1) Deferred tax asset $ — $ — $ — $ — Deferred tax liability: Current — (71,191 ) 71,191 — Noncurrent — (105,754 ) (71,191 ) (176,945 ) Deferred tax liability $ — $ (176,945 ) $ — $ (176,945 ) Net deferred tax liability $ — $ (176,945 ) $ — $ (176,945 ) _____________________________________________________________________________ (1) See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014. The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2015 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 915,642 Total $ 1,368,590 The Company had federal net operating loss carry-forwards totaling $1.4 billion and state of Oklahoma net operating loss carry-forwards totaling $40.9 million as of December 31, 2015. These carry-forwards begin expiring in 2026. As of December 31, 2015, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2015, 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's federal and state operating loss carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of December 31, 2015, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital. 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, 2015, a valuation allowance of $677.3 million has been recorded against the deferred tax asset. Prior to the Internal Consolidation, the Company and its subsidiaries filed a federal corporate income tax return on a consolidated basis. Following the Internal Consolidation, the surviving entities file a single return. The Company's income tax returns for the years 2012 through 2015 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 carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives a. Commodity derivatives The Company engages in derivative transactions such as puts, swaps, collars and basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its production. As of December 31, 2015 , the Company had 18 open derivative contracts with financial institutions that extend from January 2016 to December 2017. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the consolidated statements of operations in the "Gain (loss) on derivatives" line items. Each put transaction has an established floor price. The Company pays the counterparty a premium, which can be 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 fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires. 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. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty 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. Each basis swap transaction has an established fixed basis differential corresponding to two index prices. Depending on the difference of the two 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. During the first quarter of 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial derivative contract that hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with the normal purchase and normal sale scope exemption. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business. During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale: Aggregate volumes Swap price Contract period Natural gas (volumes in MMBtu): Swap 2,386,800 $ 4.31 August 2013 - December 2013 Swap 3,978,500 $ 4.36 January 2014 - December 2014 The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013: Aggregate volumes Floor price Ceiling price Contract period Natural gas (volumes in MMBtu): Price collar 2,200,000 $ 4.00 $ 7.05 September 2013 - December 2013 Put 2,200,000 $ 4.00 $ — September 2013 - December 2013 Price collar 3,480,000 $ 4.00 $ 7.00 January 2014 - December 2014 Price collar 1,800,000 $ 4.00 $ 7.05 January 2014 - December 2014 Price collar 1,680,000 $ 4.00 $ 7.05 January 2014 - December 2014 Price collar 1,560,000 $ 3.00 $ 5.50 January 2014 - December 2014 Price collar 2,520,000 $ 3.00 $ 6.00 January 2015 - December 2015 Price collar 2,400,000 $ 3.00 $ 6.00 January 2015 - December 2015 Price collar 2,400,000 $ 3.00 $ 6.00 January 2015 - December 2015 The following represents cash settlements received (paid) for matured derivatives and for early terminations and modifications of derivatives for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Cash settlements received for matured commodity derivatives $ 255,281 $ 28,241 $ 4,046 Cash settlements paid for matured interest rate swaps — — (301 ) Early terminations and modification of commodity derivatives received (1) — 76,660 6,008 Cash settlements received for derivatives, net $ 255,281 $ 104,901 $ 9,753 _____________________________________________________________________________ (1) During the year ended December 31, 2013, the Company received $6.0 million , net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts. The following table summarizes open positions as of December 31, 2015 , and represents, as of such date, derivatives in place through December 2017 on annual production volumes: Year Year Oil positions: (1) Puts: Hedged volume (Bbl) 1,296,000 — Weighted-average price ($/Bbl) $ 45.00 $ — Swaps: Hedged volume (Bbl) 1,573,800 — Weighted-average price ($/Bbl) $ 84.82 $ — Collars: Hedged volume (Bbl) 3,654,000 2,628,000 Weighted-average floor price ($/Bbl) $ 73.99 $ 77.22 Weighted-average ceiling price ($/Bbl) $ 89.63 $ 97.22 Totals: Total volume hedged with floor price (Bbl) 6,523,800 2,628,000 Weighted-average floor price ($/Bbl) $ 70.84 $ 77.22 Total volume hedged with ceiling price (Bbl) 5,227,800 2,628,000 Weighted-average ceiling price ($/Bbl) $ 88.18 $ 97.22 Natural gas positions: (2) Collars: Hedged volume (MMBtu) 18,666,000 5,475,000 Weighted-average floor price ($/MMBtu) $ 3.00 $ 3.00 Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 4.00 _____________________________________________________________________________ (1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX"). (2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period. b. Interest rate derivatives The Company is exposed to market risk for changes in interest rates related to any drawn amount on its Senior Secured Credit Facility. In prior periods, interest rate derivative agreements were used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If the London Interbank Offered Rate ("LIBOR") was lower than the fixed rate in the contract, the Company was required to pay the counterparties the difference, and conversely, the counterparties were required to pay the Company if LIBOR was higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments were recorded in current earnings. In prior years, the Company had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00% , respectively, until their expiration in September 2013. No interest rate derivatives were in place as of December 31, 2015 or 2014 . c. Balance sheet presentation In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas commodity derivatives are presented on a net basis as "Derivatives" on the consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis. By using derivatives to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil 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 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 the Company's 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. |
Fair value measurements
Fair value measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair value measurements | Fair value measurements The Company accounts for its oil and natural gas commodity derivatives and, in prior periods, its interest rate derivatives, at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties. 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. When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the years ended December 31, 2015 , 2014 or 2013 . a. Fair value measurement on a recurring basis The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented: (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, 2015: Assets Current: Oil derivatives $ — $ 194,940 $ — $ 194,940 $ — $ 194,940 Natural gas derivatives — 13,166 — 13,166 — 13,166 Oil deferred premiums — — — — (9,301 ) (9,301 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 80,302 $ — $ 80,302 $ — $ 80,302 Natural gas derivatives — 2,459 — 2,459 — 2,459 Oil deferred premiums — — — — (4,877 ) (4,877 ) Natural gas deferred premiums — — — — (441 ) (441 ) Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (9,301 ) (9,301 ) 9,301 — Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (4,877 ) (4,877 ) 4,877 — Natural gas deferred premiums — — (441 ) (441 ) 441 — Net derivative position $ — $ 290,867 $ (14,619 ) $ 276,248 $ — $ 276,248 (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, 2014: Assets Current: Oil derivatives $ — $ 190,303 $ — $ 190,303 $ — $ 190,303 Natural gas derivatives — 9,647 — 9,647 — 9,647 Oil deferred premiums — — — — (4,653 ) (4,653 ) Natural gas deferred premiums — — — — (696 ) (696 ) Noncurrent: Oil derivatives $ — $ 117,963 $ — $ 117,963 $ — $ 117,963 Natural gas derivatives — 3,646 — 3,646 — 3,646 Oil deferred premiums — — — — (3,821 ) (3,821 ) Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (4,768 ) (4,768 ) 4,653 (115 ) Natural gas deferred premiums — — (696 ) (696 ) 696 — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (3,821 ) (3,821 ) 3,821 — Natural gas deferred premiums — — — — — — Net derivative position $ — $ 321,559 $ (9,285 ) $ 312,274 $ — $ 312,274 These items are included as "Derivatives" on the consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of commodity derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data. The Company's deferred premiums associated with its commodity 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 commodity 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 (historical input rates range from 1.69% to 3.56% ), 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; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness. The following table presents actual cash payments required for deferred premiums for the calendar years presented: (in thousands) December 31, 2015 2016 $ 8,629 2017 5,796 2018 426 Total $ 14,851 A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2015 2014 2013 Balance of Level 3 at beginning of period $ (9,285 ) $ (12,684 ) $ (24,709 ) Change in net present value of deferred premiums for derivatives (203 ) (220 ) (462 ) Total purchases and settlements: Purchases (10,298 ) (3,800 ) — Settlements (1) 5,167 7,419 12,487 Balance of Level 3 at end of period $ (14,619 ) $ (9,285 ) $ (12,684 ) _____________________________________________________________________________ (1) The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive. b. Fair value measurement on a nonrecurring basis The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. 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. See Note 2.j for discussion of the Company's impairment of line-fill, materials and supplies and other fixed assets for the periods presented. The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. 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 evaluated reserves and other relevant data. See Note 2.g for discussion regarding the prices used in the calculation of discounted cash flows and the Company's second, third and fourth-quarter 2015 full cost ceiling impairments. |
Net income (loss) per share
Net income (loss) per share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Net income (loss) per share | Net income (loss) per share Basic net income (loss) per 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 share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the year ended December 31, 2015, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net income (loss) per share. The effects of the Company's then outstanding restricted stock options that were granted in February 2014 to purchase 336,140 shares of common stock at $25.60 per share and in February 2012 to purchase 280,626 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income per share for each of the years ended December 31, 2014 and 2013, because the exercise prices of these options were greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive. The effect of the Company's outstanding restricted stock options that were granted in February 2013 to purchase 750,338 shares of common stock at $17.34 per share was excluded from the calculation of diluted net income per share for the years ended December 31, 2014 and 2013, because, utilizing the treasury method, the sum of the assumed proceeds exceeded the average stock price during the period and, therefore, the inclusion of these outstanding options would have been anti-dilutive. For the year ended December 31, 2014, the 2014 Performance Share Awards' total shareholder return was below their agreement's payout threshold, and therefore the 2014 Performance Share Awards were excluded from the calculation of diluted net income per share. There were no outstanding performance share awards in 2013. The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2015 2014 2013 Net income (loss) (numerator): Income (loss) from continuing operations—basic and diluted $ (2,209,936 ) $ 265,573 $ 116,577 Income from discontinued operations, net of tax—basic and diluted — — 1,423 Net income (loss)—basic and diluted $ (2,209,936 ) $ 265,573 $ 118,000 Weighted-average common shares outstanding (denominator): Weighted-average common shares outstanding—basic (1) 199,158 141,312 132,490 Non-vested restricted stock awards — 2,242 1,888 Weighted-average common shares outstanding—diluted 199,158 143,554 134,378 Net income (loss) per share: Basic: Income (loss) from continuing operations $ (11.10 ) $ 1.88 $ 0.88 Income from discontinued operations, net of tax — — 0.01 Net income (loss) per share $ (11.10 ) $ 1.88 $ 0.89 Diluted: Income (loss) from continuing operations $ (11.10 ) $ 1.85 $ 0.87 Income from discontinued operations, net of tax — — 0.01 Net income (loss) per share $ (11.10 ) $ 1.85 $ 0.88 _____________________________________________________________________________ (1) For the year ended December 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders was computed taking into account the March 2015 Equity Offering. For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders was computed taking into account the August 2013 Equity Offering. |
Credit risk
Credit risk | 12 Months Ended |
Dec. 31, 2015 | |
Risks and Uncertainties [Abstract] | |
Credit Risk | Credit risk The Company's oil, NGL and natural gas 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 made to one customer. 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. The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and, in prior periods, its exposure to interest rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.f, 8 and 9 for additional information regarding the Company's derivatives. For the year ended December 31, 2015 , the Company had two customers that accounted for 37.5% and 20.3% of total oil, NGL and natural gas sales, with each customer accounting for 35.3% and 23.7% , respectively, of oil, NGL and natural gas sales accounts receivable, and two other customers accounting for 18.5% and 10.7% of oil, NGL and natural gas sales accounts receivable as of December 31, 2015 . For the year ended December 31, 2014 , the Company had two customers that accounted for 36.0% and 13.7% of total oil, NGL and natural gas sales, with each customer accounting for 16.4% and 22.5% , respectively, of oil, NGL and natural gas sales accounts receivable, and three other customers accounting for 13.5% , 12.5% and 11.6% of oil, NGL and natural gas sales accounts receivable as of December 31, 2014 . For the year ended December 31, 2013 , the Company had three customers that accounted for 28.3% , 11.7% and 11.7% of total oil, NGL and natural gas sales, with two of the three customers accounting for 36.0% and 15.7% of oil and natural gas sales accounts receivable as of December 31, 2013 . These customers and percentages reported are related to the Company's exploration and production segment, see Note 17. As of December 31, 2015 , the Company had two partners whose joint operations accounts receivable accounted for 18.9% and 17.1% of the Company's total joint operations accounts receivable. As of December 31, 2014 , the Company had two partners whose joint operations accounts receivable accounted for 20.5% and 13.2% of the Company's total joint operations accounts receivable. These customers and percentages reported are related to the Company's exploration and production segment, see Note 17. For the year ended December 31, 2015 , the Company had one customer that accounted for 100.0% of total sales of purchased oil, with the same customer accounting for 99.6% of purchased oil and other product sales receivable as of December 31, 2015 . For the year ended December 31, 2014 , the Company had one customer that accounted for 100.0% of total sales of purchased oil, with the same customer accounting for 97.3% of purchased oil and other product sales receivable as of December 31, 2014 . There were no comparable sales of purchased oil for the year ended December 31, 2013 and correspondingly, there was no purchased oil and other product sales receivable as of December 31, 2013 . The customer and percentages reported relate to the Company's midstream and marketing segment, see Note 17. The Company's cash balances are insured by the FDIC up to $250,000 per bank. The Company had cash balances on deposit with certain banks as of December 31, 2015 , which exceeded the balance insured by the FDIC in the amount of $51.3 million . Management believes that the risk of loss is mitigated by the banks' reputation and financial position. |
Commitments and contingencies
Commitments and contingencies | 12 Months Ended |
Dec. 31, 2015 | |
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 . Minimum annual lease commitments for the calendar years presented are: (in thousands) December 31, 2015 2016 $ 3,087 2017 3,244 2018 3,160 2019 2,408 2020 1,294 Thereafter 8,217 Total $ 21,410 The following has been recorded to rent expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Rent expense $ 2,880 $ 3,042 $ 1,923 The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the difference between the straight-line amount and the actual amounts of the lease payments. Rent expense is included in the consolidated statements of operations in the "General and administrative" line item. b. Litigation From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity. c. Drilling contracts The Company has committed to drilling contracts with various third parties to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. In the fourth quarter of 2014, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5 million which were recorded for the year ended December 31, 2014 on the consolidated statements of operations as "Drilling rig fees." No comparable amounts were recorded in the years ended December 31, 2015 or 2013. Future commitments of $10.3 million as of December 31, 2015 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2016 that would result in a substantial penalty. d. Firm sale and transportation commitments The Company has committed to deliver for sale or transportation fixed volumes under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $425.7 million as of December 31, 2015 are not recorded in the accompanying consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the three most recent years, and management expects such production will continue to exceed the Company's future commitments. However, 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. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments. e. Federal and state regulations Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations. f. Other commitments See Notes 2.u, 16.a and 19.b for the amount of and discussion regarding outstanding commitments to the Company's non-consolidated variable interest entity ("VIE"). |
Restructuring
Restructuring | 12 Months Ended |
Dec. 31, 2015 | |
Restructuring and Related Activities [Abstract] | |
Restructuring | Restructuring Following the fourth-quarter 2014 drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees from the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the year ended December 31, 2015 related to the RIF. There were no comparative amounts recorded in the years ended December 31, 2014 or 2013. |
Recently issued accounting stan
Recently issued accounting standards | 12 Months Ended |
Dec. 31, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recently issued accounting standards | Recently issued accounting standards In November 2015, the Financial Accounting Standards Board ("FASB") issued new guidance in Topic 740, Income Taxes, which seeks to simplify the presentation of deferred income taxes. The amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. For public business entities, the amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company has early-adopted this standard as of December 31, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of deferred income taxes from the current liabilities "Deferred income taxes" to the noncurrent liabilities "Deferred income taxes" within the consolidated balance sheets. The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below: (in thousands) September 30, 2015 June 30, 2015 March 31, 2015 December 31, 2014 Noncurrent assets: Decrease in deferred income taxes $ (68,069 ) $ (45,089 ) $ — $ — Decrease in total assets (68,069 ) (45,089 ) — — Current liabilities: Decrease in deferred income taxes $ (68,069 ) $ (45,089 ) $ (73,753 ) $ (71,191 ) Decrease in total current liabilities (68,069 ) (45,089 ) (73,753 ) (71,191 ) Noncurrent liabilities: Increase in deferred income taxes $ — $ — $ 73,753 $ 71,191 Decrease in total liabilities (68,069 ) (45,089 ) — — See Note 7 for additional discussion of the December 31, 2014 consolidated balance sheet presentation reclassification. In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. In April 2015, the FASB issued new guidance in Subtopic 835-30, Interest-Imputation of Interest, which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this guidance. Entities should apply the amendments on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The Company has early-adopted this standard as of September 30, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of (i) the unamortized debt issuance costs related to the Company's senior unsecured notes from noncurrent assets "Debt issuance costs, net" to noncurrent liabilities "Long-term debt, net" and (ii) the unamortized debt issuance costs related to the Company's Senior Secured Credit Facility from noncurrent assets "Debt issuance costs, net" to noncurrent assets "Other assets, net" within the consolidated balance sheets. See Notes 2.k and 5.h for additional discussion of debt issuance costs. The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below: (in thousands) June 30, 2015 March 31, 2015 December 31, 2014 Noncurrent assets: Decrease in debt issuance costs, net $ (26,158 ) $ (33,513 ) $ (28,463 ) Increase in other assets, net 6,068 6,873 6,615 Decrease in total assets (20,090 ) (26,640 ) (21,848 ) Noncurrent liabilities: Decrease in long-term debt, net $ (20,090 ) $ (26,640 ) $ (21,848 ) Decrease in total liabilities (20,090 ) (26,640 ) (21,848 ) In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. |
Variable interest entity
Variable interest entity | 12 Months Ended |
Dec. 31, 2015 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Variable Interest Entity | Variable interest entity An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change. LMS contributed $99.9 million and $55.2 million during the years ended December 31, 2015 and 2014 , respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together, "Medallion"). See Note 19.b for discussion regarding a contribution made to Medallion subsequent to December 31, 2015. LMS holds 49% of Medallion ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil, NGL and natural gas to market. LMS and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operating and business decisions. The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the consolidated balance sheets as "Investment in equity method investee." During the year ended December 31, 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production and began recognizing revenue due to its main pipeline becoming operational. During the year ended December 31, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled. See Note 16.a for discussion of items included in the consolidated financial statements related to Medallion. The following table summarizes items included in Medallion's consolidated statements of operations, which are not recorded in the Company's consolidated financial statements, for the periods presented: For the years ended December 31, (in thousands) 2015 (3) 2014 2013 Total revenues $ 34,288 $ 4,623 $ 892 Gross profit (1) 29,826 4,623 892 Income (loss) from continuing operations 13,821 (333 ) 54 Net income (loss) (2) 13,821 (333 ) 54 _____________________________________________________________________________ (1) Medallion's pipeline did not become operational until 2015, accordingly no costs of good sold were recorded for the years ended December 31, 2014 and 2013. (2) As Medallion's financial statements are unaudited at the time of filing the Company's Annual Report on Form 10-K, the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations for the years ended December 31, 2015 and 2014 include immaterial prior period Medallion audit adjustments. (3) Medallion's consolidated statement of operations for the year ended December 31, 2015 was unaudited as of February 17, 2016. The following table summarizes items included in Medallion's consolidated balance sheets, which are not recorded in the Company's consolidated financial statements, as of the periods presented: December 31, (in thousands) 2015 (1) 2014 Assets: Current assets $ 78,411 $ 25,777 Noncurrent assets 329,956 112,753 Total assets $ 408,367 $ 138,530 Liabilities: Current liabilities $ 15,461 $ 19,522 Noncurrent liabilities — — Total liabilities $ 15,461 $ 19,522 _____________________________________________________________________________ (1) Medallion's consolidated balance sheet as of December 31, 2015 was unaudited as of February 17, 2016. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Parties | Related Parties a. Medallion The following table summarizes items included in the consolidated statements of operations related to Medallion for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Midstream service revenues $ 487 $ — $ — Minimum volume commitments 5,235 2,552 891 Interest and other income 158 — — The following table summarizes items included in the consolidated balance sheets related to Medallion as of the periods presented: December 31, (in thousands) 2015 2014 Accounts receivable, net $ 1,163 $ — Other assets, net (1) 1,025 1,110 Other current liabilities (2) 27,583 3,443 _____________________________________________________________________________ (1) Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline. (2) Amounts included in "Other current liabilities" above for the year ended December 31, 2015 represents LMS's capital contribution payable to Medallion, of which a portion was paid subsequent to December 31, 2015. "Other current liabilities" above for the year ended December 31, 2014 represents LMS's minimum volume commitment payable to Medallion. See Note 15 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion. b. Targa Resources Corp. The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors was on the board of directors of Targa until May 18, 2015. The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa and included in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Oil, NGL and natural gas sales $ 99,992 $ 96,100 $ 74,245 Midstream service revenues 590 — — The following table summarizes the amounts included in accounts receivable, net from Targa in the consolidated balance sheets as of the periods presented: December 31, (in thousands) 2015 2014 Accounts receivable, net $ 6,097 $ 12,869 c. Archrock Partners, L.P. The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P., ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock. The following table summarizes the lease operating expenses related to Archrock included in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Lease operating expenses $ 1,477 $ 975 $ 51 The following table summarizes the capital expenditures related to Archrock included in the consolidated statements of cash flows for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Capital expenditures: Oil and natural gas properties $ — $ 57 $ — Midstream service assets 64 833 — The following table summarizes the amounts included in accounts payable from Archrock in the consolidated balance sheets as of the periods presented: December 31, (in thousands) 2015 2014 Accounts payable $ 13 $ — d. Helmerich & Payne, Inc. The Company has had drilling contracts 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 summarizes the capitalized oil and natural gas properties related to H&P and included in the consolidated statements of cash flows for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Capital expenditures: Oil and natural gas properties $ 2,434 $ 9,518 $ 9,943 |
Segments
Segments | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segments | Segments Since the beginning of 2015, the Company has presented financial results by segment to highlight the growing value of its midstream and marketing segment and the midstream and marketing segment's interest in Medallion, as Medallion's third-party revenues have increased. The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and certain third parties with (i) products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in and around Laredo's primary production corridors, (ii) water takeaway in and around Laredo's primary production corridors and (iii) oil and natural gas takeaway optionality in the field coupled with firm service commitments to maximize Laredo's oil, NGL and natural gas revenues. The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis: (in thousands) Exploration and production Midstream and marketing Consolidated Year ended December 31, 2015: Oil, NGL and natural gas sales $ 432,711 $ 1,692 $ (2,669 ) $ 431,734 Midstream service revenues — 27,965 (21,417 ) 6,548 Sales of purchased oil — 168,358 — 168,358 Total revenues 432,711 198,015 (24,086 ) 606,640 Lease operating expenses, including production tax 151,918 — (10,685 ) 141,233 Midstream service expenses, including minimum volume commitments 4,399 18,393 (11,711 ) 11,081 Costs of purchased oil — 174,338 — 174,338 General and administrative (1) 82,251 8,174 — 90,425 Depletion, depreciation and amortization (2) 269,631 8,093 — 277,724 Impairment expense 2,372,296 2,592 — 2,374,888 Other operating costs and expenses (3) 8,123 342 — 8,465 Operating loss $ (2,455,907 ) $ (13,917 ) $ (1,690 ) $ (2,471,514 ) Other financial information: Income from equity method investee $ — $ 6,799 $ — $ 6,799 Interest expense (4) $ (98,040 ) $ (5,179 ) $ — $ (103,219 ) Loss on early redemption of debt (5) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Income tax benefit (6) $ 171,952 $ 4,993 $ — $ 176,945 Capital expenditures $ (597,086 ) $ (35,515 ) $ — $ (632,601 ) Gross property and equipment (8) $ 5,302,716 $ 345,183 $ (1,923 ) $ 5,645,976 Year ended December 31, 2014: Oil, NGL and natural gas sales $ 738,455 $ 1,660 $ (2,912 ) $ 737,203 Midstream service revenues — 7,838 (5,593 ) 2,245 Sales of purchased oil — 54,437 — 54,437 Total revenues 738,455 63,935 (8,505 ) 793,885 Lease operating expenses, including production tax 153,427 — (6,612 ) 146,815 Midstream service expenses, including minimum volume commitments — 9,641 (1,660 ) 7,981 Costs of purchased oil — 53,967 — 53,967 General and administrative (1) 99,075 6,969 — 106,044 Depletion, depreciation and amortization (2) 241,834 4,640 — 246,474 Impairment expense 1,802 2,102 — 3,904 Other operating costs and expenses (3) 2,248 66 — 2,314 Operating income (loss) $ 240,069 $ (13,450 ) $ (233 ) $ 226,386 Other financial information: Loss from equity method investee $ — $ (192 ) $ — $ (192 ) Interest expense (4) $ (117,560 ) $ (3,613 ) $ — $ (121,173 ) Income tax (expense) benefit (6) $ (170,551 ) $ 6,265 $ — $ (164,286 ) Capital expenditures (7) $ (1,279,142 ) $ (60,607 ) $ — $ (1,339,749 ) Gross property and equipment (8) $ 4,841,895 $ 179,355 $ (233 ) $ 5,021,017 Year ended December 31, 2013: Oil, NGL and natural gas sales $ 664,844 $ — $ — $ 664,844 Midstream service revenues 328 8,824 (8,739 ) 413 Total revenues 665,172 8,824 (8,739 ) 665,257 Lease operating expenses, including production tax 130,152 — (8,620 ) 121,532 Midstream service expenses, including minimum volume commitments 2,807 1,571 (119 ) 4,259 General and administrative (1) 86,951 2,745 — 89,696 Depletion, depreciation and amortization (2) 231,703 2,241 — 233,944 Other operating costs and expenses (3) 1,475 — — 1,475 Operating income $ 212,084 $ 2,267 $ — $ 214,351 Other financial information: Income from equity method investee $ — $ 29 $ — $ 29 Interest expense (4) $ (98,680 ) $ (1,647 ) $ — $ (100,327 ) Income tax expense (6) $ (73,476 ) $ (1,031 ) $ — $ (74,507 ) Capital expenditures (7) $ (718,606 ) $ (24,409 ) $ — $ (743,015 ) Gross property and equipment (8) $ 3,516,406 $ 58,706 $ — $ 3,575,112 _____________________________________________________________________________ (1) General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015 , 2014 and 2013 . Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013. (2) Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015 , 2014 and 2013 . (3) Other operating costs and expenses include restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015 , accretion of asset retirement obligations and drilling rig fees for the year ended December 31, 2014 and accretion of asset retirement obligations for the year ended December 31, 2013. These expenses are based on actual costs and are not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013. (5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015. (6) Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% for the years ended December 31, 2015, 2014 and 2013. (7) Capital expenditures exclude acquisition of oil and natural gas properties and acquisition of mineral interests for the year ended December 31, 2014 and excludes acquisitions of oil and natural gas properties for the year ended December 31, 2013. (8) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $192.5 million, $58.3 million and $5.9 million as of December 31, 2015 , 2014 and 2013 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2015 , 2014 and 2013 . |
Subsidiary guarantors
Subsidiary guarantors | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Subsidiary guarantors | Subsidiary guarantors The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2015 and 2014 , and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2015 , 2014 and 2013 , 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. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, 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, 2014, certain midstream service assets were transferred from Laredo to LMS at historical cost. Condensed consolidating balance sheet December 31, 2015 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Accounts receivable, net $ 74,613 $ 13,086 $ — $ 87,699 Other current assets 244,477 56 — 244,533 Total oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Total midstream service assets, net — 131,725 — 131,725 Total other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 Total other long-term assets 84,360 3,916 — 88,276 Total assets $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287 Accounts payable $ 12,203 $ 1,978 $ — $ 14,181 Other current liabilities 158,283 44,351 — 202,634 Long-term debt, net 1,416,226 — — 1,416,226 Other long-term liabilities 46,034 2,765 — 48,799 Stockholders' equity 133,370 301,891 (303,814 ) 131,447 Total liabilities and stockholders' equity $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287 Condensed consolidating balance sheet December 31, 2014 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Accounts receivable, net $ 107,860 $ 19,069 $ — $ 126,929 Other current assets 238,300 24 — 238,324 Total oil and natural gas properties, net 3,196,231 7,277 (233 ) 3,203,275 Total midstream service assets, net — 108,462 — 108,462 Total other fixed assets, net 42,046 299 — 42,345 Investment in subsidiaries and equity method investee 163,349 58,288 (163,349 ) 58,288 Total other long-term assets 128,582 4,496 — 133,078 Total assets $ 3,876,368 $ 197,915 $ (163,582 ) $ 3,910,701 Accounts payable $ 38,453 $ 555 $ — $ 39,008 Other current liabilities 283,026 31,800 — 314,826 Long-term debt, net 1,779,447 — — 1,779,447 Other long-term liabilities 212,008 2,211 — 214,219 Stockholders' equity 1,563,434 163,349 (163,582 ) 1,563,201 Total liabilities and stockholders' equity $ 3,876,368 $ 197,915 $ (163,582 ) $ 3,910,701 Condensed consolidating statement of operations For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Total operating revenues $ 432,478 $ 198,248 $ (24,086 ) $ 606,640 Total operating costs and expenses 2,897,272 203,278 (22,396 ) 3,078,154 Loss from operations (2,464,794 ) (5,030 ) (1,690 ) (2,471,514 ) Interest expense and other, net (102,793 ) — — (102,793 ) Other non-operating income 182,396 6,708 (1,678 ) 187,426 Income (loss) from continuing operations before income tax (2,385,191 ) 1,678 (3,368 ) (2,386,881 ) Income tax benefit 176,945 — — 176,945 Income (loss) from continuing operations (2,208,246 ) 1,678 (3,368 ) (2,209,936 ) Net income (loss) $ (2,208,246 ) $ 1,678 $ (3,368 ) $ (2,209,936 ) Condensed consolidating statement of operations For the year ended December 31, 2014 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Total operating revenues $ 738,446 $ 63,944 $ (8,505 ) $ 793,885 Total operating costs and expenses 505,455 70,316 (8,272 ) 567,499 Income (loss) from operations 232,991 (6,372 ) (233 ) 226,386 Interest expense and other, net (120,879 ) — — (120,879 ) Other non-operating income (expense) 317,980 (339 ) 6,711 324,352 Income (loss) from continuing operations before income tax 430,092 (6,711 ) 6,478 429,859 Income tax expense (164,286 ) — — (164,286 ) Income (loss) from continuing operations 265,806 (6,711 ) 6,478 265,573 Net income (loss) $ 265,806 $ (6,711 ) $ 6,478 $ 265,573 Condensed consolidating statement of operations For the year ended December 31, 2013 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Total operating revenues $ 665,172 $ 8,824 $ (8,739 ) $ 665,257 Total operating costs and expenses 455,972 3,673 (8,739 ) 450,906 Income from operations 209,200 5,151 — 214,351 Interest expense and other, net (100,164 ) — — (100,164 ) Other non-operating income 84,861 2,268 (10,232 ) 76,897 Income from continuing operations before income tax 193,897 7,419 (10,232 ) 191,084 Income tax expense (74,507 ) — — (74,507 ) Income from continuing operations 119,390 7,419 (10,232 ) 116,577 Income (loss) from discontinued operations, net of tax (1,390 ) 2,813 — 1,423 Net income $ 118,000 $ 10,232 $ (10,232 ) $ 118,000 Condensed consolidating statement of cash flows For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Net cash flows provided by operating activities $ 316,838 $ 787 $ (1,678 ) $ 315,947 Change in investments between affiliates (136,252 ) 134,574 1,678 — Capital expenditures and other (532,146 ) (135,361 ) — (667,507 ) Net cash flows provided by financing activities 353,393 — — 353,393 Net increase in cash and cash equivalents 1,833 — — 1,833 Cash and cash equivalents at beginning of period 29,320 1 — 29,321 Cash and cash equivalents at end of period $ 31,153 $ 1 $ — $ 31,154 Condensed consolidating statement of cash flows For the year ended December 31, 2014 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Net cash flows provided (used) by operating activities $ 496,955 $ (5,389 ) $ 6,711 $ 498,277 Change in investments between affiliates (113,449 ) 120,160 (6,711 ) — Capital expenditures and other (1,292,191 ) (114,770 ) — (1,406,961 ) Net cash flows provided by financing activities 739,852 — — 739,852 Net (decrease) increase in cash and cash equivalents (168,833 ) 1 — (168,832 ) Cash and cash equivalents at beginning of period 198,153 — — 198,153 Cash and cash equivalents at end of period $ 29,320 $ 1 $ — $ 29,321 Condensed consolidating statement of cash flows For the year ended December 31, 2013 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Net cash flows provided by operating activities $ 359,198 $ 15,763 $ (10,232 ) $ 364,729 Change in investments between affiliates 23,986 (34,218 ) 10,232 — Capital expenditures and other (348,339 ) 18,455 — (329,884 ) Net cash flows provided by financing activities 130,084 — — 130,084 Net increase in cash and cash equivalents 164,929 — — 164,929 Cash and cash equivalents at beginning of period 33,224 — — 33,224 Cash and cash equivalents at end of period $ 198,153 $ — $ — $ 198,153 |
Subsequent events
Subsequent events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent events | Subsequent events a. Senior Secured Credit Facility On January 14, 2016, the Company borrowed $35.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $170.0 million at February 16, 2016. b. Medallion capital call On January 15 and February 16, 2016, the Company made additional capital contributions to Medallion of $12.7 million and $8.3 million , respectively, which represent LMS's remaining commitment for the extension from Medallion's Garden City Station to Midland and Upton counties, Texas and a portion of the commitment for the southern extension from Medallion's Reagan Station further into Reagan County, Texas. c. New commodity derivative contracts Subsequent to December 31, 2015, the Company entered into the following new commodity derivative contracts: Aggregate volumes Floor price Contract period Natural gas (volumes in MMBtu): (1) Put 8,040,000 $ 2.50 January 2017 - December 2017 Put 8,220,000 $ 2.50 January 2018 - December 2018 _____________________________________________________________________________ (1) The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts. |
Supplemental oil, NGL and natur
Supplemental oil, NGL and natural gas disclosures | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental oil, NGL and natural gas disclosures | Supplemental oil, NGL and natural gas disclosures a. Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below: For the years ended December 31, (in thousands) 2015 2014 2013 Property acquisition costs: Evaluated $ — $ 3,873 $ 9,652 Unevaluated — 9,925 27,087 Exploration (1) 20,697 242,284 48,763 Development costs (2) 500,577 1,049,317 654,452 Total costs incurred $ 521,274 $ 1,305,399 $ 739,954 _____________________________________________________________________________ (1) The Company acquired significant leasehold interests during the year ended December 31, 2014. (2) The costs incurred for oil, NGL and natural gas development activities include $ 13.4 million , $ 6.9 million and $ 6.8 million in asset retirement obligations for the years ended December 31, 2015 , 2014 and 2013 , respectively. b. Capitalized oil, NGL and natural gas costs Aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment are presented below: For the years ended December 31, (in thousands) 2015 2014 2013 Capitalized costs: Evaluated properties $ 5,103,635 $ 4,446,781 $ 3,276,578 Unevaluated properties not being depleted 140,299 342,731 208,085 5,243,934 4,789,512 3,484,663 Less accumulated depletion and impairment (4,218,942 ) (1,586,237 ) (1,349,315 ) Net capitalized costs $ 1,024,992 $ 3,203,275 $ 2,135,348 The following table shows a summary of the oil, NGL and natural gas property costs not being depleted as of December 31, 2015 , by year in which such costs were incurred: (in thousands) 2015 2014 2013 2012 and prior Total Unevaluated properties not being depleted $ 12,640 $ 110,955 $ 9,293 $ 7,411 $ 140,299 Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil, NGL and natural gas leaseholds 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 oil, NGL and natural gas producing activities The results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) are presented below: For the years ended December 31, (in thousands) 2015 2014 2013 Revenues: Oil, NGL and natural gas sales $ 431,734 $ 737,203 $ 664,844 Production costs: Lease operating expenses 108,341 96,503 79,136 Production and ad valorem taxes 32,892 50,312 42,396 141,233 146,815 121,532 Other costs: Depletion 263,666 237,067 227,992 Accretion of asset retirement obligations 2,236 1,721 1,475 Impairment expense 2,369,477 — — Income tax (benefit) expense (1) (164,141 ) 126,576 112,984 Results of operations $ (2,180,737 ) $ 225,024 $ 200,861 _____________________________________________________________________________ (1) During the year ended December 31, 2015, the Company recorded a valuation allowance against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the year ended December 31, 2015, income tax benefit is computed utilizing the Company's effective rate of 7% , 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 benefit for the period. For the years ended December 31, 2014 and 2013, income tax expense is computed utilizing the statutory rate. d. Net proved oil, NGL and natural gas reserves - (unaudited) 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, 2015 , 2014 and 2013 . In accordance with SEC regulations, reserves as of December 31, 2015 , 2014 and 2013 were estimated using the Realized Prices (which are the Benchmark Prices adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead), see Note 2.g. The Company's reserves as of December 31, 2015 are reported in three streams: oil, NGL and natural gas. The Company's reserves as of December 31, 2014 and 2013 are reported in two streams: oil and liquids-rich natural gas with the economic value of the NGLs in the Company's natural gas included in the wellhead natural gas price. This change impacts the comparability of 2015 with prior periods. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil, NGL 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 reserve quantities of oil, NGL and natural gas for the year ended December 31, 2015 and of oil and liquids-rich natural gas for the years ended December 31, 2014 and 2013 , all of which are located within the United States. Year ended December 31, 2015 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 140,190 — 642,794 247,322 Revisions of previous estimates (1) (88,900 ) 35,477 (424,546 ) (124,180 ) Extensions, discoveries and other additions 10,511 5,865 36,074 22,388 Sales of reserves in place (1,552 ) (1,008 ) (5,554 ) (3,486 ) Production (7,610 ) (4,267 ) (26,816 ) (16,346 ) End of year 52,639 36,067 221,952 125,698 Proved developed reserves: Beginning of year 56,975 — 291,493 105,557 End of year 40,944 29,349 180,613 100,395 Proved undeveloped reserves: Beginning of year 83,215 — 351,301 141,765 End of year 11,695 6,718 41,339 25,303 _____________________________________________________________________________ (1) The positive NGL revisions of previous estimates and the negative natural gas revisions of previous estimates include the impact of the Company's conversion to three-stream production. For periods prior to January 1, 2015, the Company presented its reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability to prior periods. Year ended December 31, 2014 Oil Gas MBOE Proved developed and undeveloped reserves: Beginning of year 111,498 552,702 203,615 Revisions of previous estimates (10,134 ) (67,350 ) (21,359 ) Extensions, discoveries and other additions 45,554 185,909 76,539 Purchases of reserves in place 173 498 256 Production (6,901 ) (28,965 ) (11,729 ) End of year 140,190 642,794 247,322 Proved developed reserves: Beginning of year 37,878 203,082 71,725 End of year 56,975 291,493 105,557 Proved undeveloped reserves: Beginning of year 73,620 349,620 131,890 End of year 83,215 351,301 141,765 Year ended December 31, 2013 Oil Gas MBOE Proved developed and undeveloped reserves: Beginning of year 98,141 542,946 188,632 Revisions of previous estimates (17,956 ) 15,710 (15,338 ) Extensions, discoveries and other additions 37,850 192,229 69,888 Purchases of reserves in place 170 1,454 412 Sale of reserves in place (1,220 ) (165,289 ) (28,768 ) Production (5,487 ) (34,348 ) (11,211 ) End of year 111,498 552,702 203,615 Proved developed reserves: Beginning of year 33,316 289,045 81,490 End of year 37,878 203,082 71,725 Proved undeveloped reserves: Beginning of year 64,825 253,901 107,142 End of year 73,620 349,620 131,890 For the year ended December 31, 2015 , the Company's negative revision of 124,180 MBOE of previously estimated quantities is primarily attributable to the removal of 106,883 MBOE due to the combined effect of the removal of 378 proved undeveloped locations and the net effect of reinterpreting 34 undeveloped locations. The 378 locations that were removed were comprised of 182 vertical Wolfberry wells due to lower commodity prices and 196 horizontal wells to better align the timing of their development with the Company's future drilling plans. The remaining 17,297 MBOE of negative revisions is due to a combination of pricing, performance and other changes to the proved developed producing and proved developed non-producing wells. Extensions, discoveries and other additions of 22,388 MBOE during the year ended December 31, 2015 , consisted of 19,719 MBOE primarily from the drilling of new wells during the year and 2,669 MBOE from four new horizontal Middle Wolfcamp proved undeveloped locations added during the year. For the year ended December 31, 2014 , the Company's negative revision of 21,359 MBOE of previously estimated quantities is primarily attributable to the removal of 26,017 MBOE due to the combined effect of the removal of 226 proved undeveloped locations and the net effect of reinterpreting 345 undeveloped locations. The 226 locations that were removed were comprised of vertical Wolfberry and horizontal laterals to better align with the proved developed producing wells. The increase of 4,658 MBOE, which offsets the overall negative revision, is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 76,539 MBOE during the year ended December 31, 2014 , consisted of 34,782 MBOE primarily from the drilling of new wells during the year and 41,757 MBOE from 113 new horizontal proved undeveloped locations added during the year. Purchases of minerals in place added 256 MBOE from acquisition of proved reserves in the Permian Basin. For the year ended December 31, 2013 , the Company's negative revision of 15,338 MBOE of previously estimated quantities is primarily attributable to the removal of 11,944 MBOE due to the combined effect of the removal of 174 proved undeveloped locations and the net effect of reinterpreting 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and short horizontal laterals which were replaced with longer horizontal laterals to better align with future drilling plans. The remaining 3,394 MBOE of the negative revision is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 69,888 MBOE during the year ended December 31, 2013 , consisted of 22,245 MBOE primarily from the drilling of new wells during the year and 47,643 MBOE from new proved undeveloped locations added during the year. The latter consists of 45,510 MBOE attributable to 85 horizontal locations in the Permian Basin. Purchases of minerals in place added 412 MBOE from acquisition of proved reserves in the Permian Basin. e. Standardized measure of discounted future net cash flows - (unaudited) 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, 2015 , 2014 and 2013 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for gravity, quality, local conditions, fuel and shrinkage and/or distance from market. 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, NGL and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10% . The Company's net book value of evaluated oil, NGL and natural gas properties exceeded the full cost ceiling amount as of June 30, 2015, September 30, 2015 and December 31, 2015 . See Note 2.g for discussion of the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded. The standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves is as follows: For the years ended December 31, (in thousands) 2015 2014 2013 Future cash inflows $ 3,269,184 $ 16,663,685 $ 13,337,798 Future production costs (1,321,471 ) (3,616,775 ) (3,059,368 ) Future development costs (376,701 ) (2,471,985 ) (2,250,950 ) Future income tax expenses — (2,827,763 ) (2,150,983 ) Future net cash flows 1,571,012 7,747,162 5,876,497 10% discount for estimated timing of cash flows (740,265 ) (4,500,434 ) (3,554,293 ) Standardized measure of discounted future net cash flows $ 830,747 $ 3,246,728 $ 2,322,204 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. Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves are as follows: For the years ended December 31, (in thousands) 2015 2014 2013 Standardized measure of discounted future net cash flows, beginning of year $ 3,246,728 $ 2,322,204 $ 1,877,456 Changes in the year resulting from: Sales, less production costs (290,501 ) (590,388 ) (543,312 ) Revisions of previous quantity estimates (2,444,322 ) (320,275 ) (190,961 ) Extensions, discoveries and other additions 192,979 1,340,022 1,166,481 Net change in prices and production costs (1,495,144 ) 145,740 313,947 Changes in estimated future development costs (2,974 ) (22,961 ) 921 Previously estimated development costs incurred during the period 162,237 92,135 89,396 Purchases of reserves in place — 6,100 7,604 Divestitures of reserves in place (29,149 ) — (239,148 ) Accretion of discount 424,453 305,325 234,852 Net change in income taxes 997,805 (266,757 ) (259,991 ) Timing differences and other 68,635 235,583 (135,041 ) Standardized measure of discounted future net cash flows, end of year $ 830,747 $ 3,246,728 $ 2,322,204 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 and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated. |
Supplemental quarterly financia
Supplemental quarterly financial data (unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Supplemental quarterly financial data (unaudited) | Supplemental quarterly financial data - (unaudited) The Company's results from continuing operations by quarter for the periods presented are as follows: Year ended December 31, 2015 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 150,694 $ 182,331 $ 150,340 $ 123,275 Operating loss (26,498 ) (501,480 ) (927,859 ) (1,015,677 ) Net loss (472 ) (397,034 ) (847,783 ) (964,647 ) Net loss per common share: Basic $ — $ (1.88 ) $ (4.01 ) $ (4.57 ) Diluted $ — $ (1.88 ) $ (4.01 ) $ (4.57 ) Year ended December 31, 2014 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 173,310 $ 183,044 $ 200,241 $ 237,290 Operating income 60,038 64,561 69,164 32,623 Net income (loss) (213 ) (18,899 ) 83,407 201,278 Net income (loss) per common share: Basic $ — $ (0.13 ) $ 0.59 $ 1.42 Diluted $ — $ (0.13 ) $ 0.58 $ 1.40 |
Basis of presentation and sig28
Basis of presentation and significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of presentation | 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. Unless otherwise indicated, the information in these notes relates to the Company's continuing operations. 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 (loss) is included in the consolidated statements of operations. |
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) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of commodity derivatives, commodity deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. 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 2015 presentation. These reclassifications had no impact to previously reported net income, stockholders' equity or 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. |
Accounts receivable | Accounts receivable The Company sells produced and purchased oil, NGL and natural gas to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize the receivables through netting of anticipated future production revenues. 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 over 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. |
Derivative financial instruments | Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant 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 due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and basis swaps. In addition, in prior periods the Company entered into interest rate derivatives. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives 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. See Note 9 for discussion regarding the fair value of the Company's derivatives. The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's commodity derivatives. |
Oil and natural gas properties | The Company excludes the costs directly associated with 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 on 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 property are assessed on a quarterly basis for possible impairment or reduction in value. 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% . Per the Securities and Exchange Commission ("SEC") guidelines, companies are required 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. In the event the unamortized cost of evaluated oil and natural gas properties being amortized 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. 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 finding oil and natural gas are capitalized and amortized on a composite units 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 amortized 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. The Company computes the provision for depletion of oil and natural gas properties using the units of production method based upon production and estimates of proved reserve quantities. |
Midstream service assets | Midstream service assets Midstream service assets 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. The oil and natural gas pipeline gathering assets, related equipment, oil delivery stations and water storage and treatment facilities are recorded at cost, net of impairment. See Note 2.m 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. |
Other fixed assets | 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. |
Long-lived assets, materials and supplies and line-fill | Long-lived assets, materials and supplies and line-fill Impairment losses are recorded on property and equipment used in operations and other 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. Materials and supplies used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") and are included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. The market price for materials and supplies is determined utilizing the Company's recent prices paid to acquire materials. These adjustments are included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's exploration and production segment presented in Note 17. The Company determined an LCM adjustment was not necessary for materials and supplies during the year ended December 31, 2013. The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill, and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Beginning in the fourth quarter of 2014, the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). |
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 asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding 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, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) 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, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas 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 gas 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, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.g for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. Fair value measurements The Company accounts for its oil and natural gas commodity derivatives and, in prior periods, its interest rate derivatives, at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties. 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. When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. 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. See Note 2.j for discussion of the Company's impairment of line-fill, materials and supplies and other fixed assets for the periods presented. The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. 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 evaluated reserves and other relevant data. See Note 2.g for discussion regarding the prices used in the calculation of discounted cash flows and the Company's second, third and fourth-quarter 2015 full cost ceiling impairments. |
Treasury stock | Treasury stock Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition. |
Revenue recognition | Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes title to the products and has risks and rewards of ownership. Revenue recognition Oil, NGL and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil, NGL and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. 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, 2015 or 2014. During the year ended December 31, 2013, the majority of the Company's natural gas producer imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined below). |
General and administrative expense | 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. |
Equity and stock-based awards | Compensation awards Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" 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 value 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 of the performance share awards and performance unit awards. On January 1, 2014, the Company began capitalizing 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 as an addition to "Oil and natural gas properties" in the consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards. |
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. A valuation allowance is established to reduce deferred tax assets if it is determined 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. See Note 7 for detail of amounts recorded in the consolidated financial statements and discussion regarding the valuation allowance taken in 2015. 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 impact of significant discrete items is separately recognized in the year in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. 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. |
Environmental | Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of December 31, 2015 or 2014. |
Employee compensation | Employee compensation The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of 10.0 million shares. 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 its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. |
Credit risk | Credit risk The Company's oil, NGL and natural gas 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 made to one customer. 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. The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and, in prior periods, its exposure to interest rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. |
Recently issued accounting standards | In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. In April 2015, the FASB issued new guidance in Subtopic 835-30, Interest-Imputation of Interest, which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this guidance. Entities should apply the amendments on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The Company has early-adopted this standard as of September 30, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of (i) the unamortized debt issuance costs related to the Company's senior unsecured notes from noncurrent assets "Debt issuance costs, net" to noncurrent liabilities "Long-term debt, net" and (ii) the unamortized debt issuance costs related to the Company's Senior Secured Credit Facility from noncurrent assets "Debt issuance costs, net" to noncurrent assets "Other assets, net" within the consolidated balance sheets. Recently issued accounting standards In November 2015, the Financial Accounting Standards Board ("FASB") issued new guidance in Topic 740, Income Taxes, which seeks to simplify the presentation of deferred income taxes. The amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. For public business entities, the amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company has early-adopted this standard as of December 31, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of deferred income taxes from the current liabilities "Deferred income taxes" to the noncurrent liabilities "Deferred income taxes" within the consolidated balance sheets. In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. |
Variable Interest Entity | An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change. |
Acquisitions | 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 and integration 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 values of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted-average cost of capital rate. The market-based weighted-average cost of capital rate is subjected 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 probable and possible reserves are reduced by additional risk-weighting factors. |
Basis of presentation and sig29
Basis of presentation and significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Schedule of components of accounts receivable | Accounts receivable consisted of the following components as of December 31: (in thousands) 2015 2014 Matured derivatives $ 27,469 $ 16,098 Oil, NGL and natural gas sales 25,582 57,070 Joint operations, net (1) 21,375 33,808 Purchased oil and other product sales 11,775 18,917 Other 1,498 1,036 Total $ 87,699 $ 126,929 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of December 31, 2015 and 2014, respectively. |
SEC prices used to calculate full cost ceiling value | The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented: For the quarters ended For the years ended (1) December 31, 2015 September 30, 2015 June 30, 2015 March 31, 2015 December 31, 2014 December 31, 2013 Benchmark Prices Oil ($/Bbl) $ 46.79 $ 55.73 $ 68.17 $ 79.21 $ 91.48 $ 93.52 NGL ($/Bbl) 18.75 21.87 26.73 31.25 — — Natural gas ($/MMBtu) 2.47 2.89 3.22 3.73 4.25 3.57 Realized Prices Oil ($/Bbl) 45.58 54.28 66.68 77.72 89.57 92.26 NGL ($/Bbl) 12.50 15.25 19.56 23.75 — — Natural gas ($/Mcf) 1.89 2.30 2.62 3.09 6.39 5.52 Non-cash full cost ceiling impairment (in thousands) $ 975,011 $ 906,420 $ 488,046 $ — $ — $ — _____________________________________________________________________________ (1) For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods. |
Schedule of pipeline and gathering assets | Other fixed assets consist of the following as of December 31: (in thousands) 2015 2014 Computer hardware and software $ 12,148 $ 13,495 Vehicles 9,266 7,802 Leasehold improvements 7,710 6,867 Real estate and buildings 7,618 4,908 Aircraft 4,952 4,952 Other 5,105 4,909 Depreciable total 46,799 42,933 Less accumulated depreciation and amortization (18,169 ) (13,820 ) Depreciable total, net 28,630 29,113 Land 14,908 13,232 Total, net $ 43,538 $ 42,345 Midstream service assets consist of the following as of December 31: (in thousands) 2015 2014 Midstream service assets $ 147,811 $ 117,052 Less accumulated depreciation (16,086 ) (8,590 ) Total, net $ 131,725 $ 108,462 |
Schedule of future amortization expense of deferred loan costs | Future amortization expense of debt issuance costs as of the period presented is as follows: (in thousands) December 31, 2015 2016 $ 4,503 2017 4,575 2018 4,349 2019 2,915 2020 3,005 Thereafter 4,585 Total $ 23,932 |
Schedule of components of other current liabilities | Other current liabilities consist of the following components as of December 31: (in thousands) 2015 2014 Capital contribution payable to equity method investee (1) $ 27,583 $ — Accrued interest payable 24,208 37,689 Accrued compensation and benefits 14,342 13,034 Lease operating expense payable 13,205 11,963 Costs of purchased oil 12,189 20,114 Other accrued liabilities 14,695 18,232 Total other current liabilities $ 106,222 $ 101,032 _____________________________________________________________________________ (1) See Notes 15, 16 and 19.b for additional discussion regarding our equity method investee. |
Schedule of reconciliation of asset retirement obligations liability | The following reconciles the Company's asset retirement obligation liability as of December 31: (in thousands) 2015 2014 Liability at beginning of year $ 32,198 $ 21,743 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 2,236 6,370 Accretion expense 2,423 1,787 Liabilities settled upon plugging and abandonment (146 ) (450 ) Liabilities removed due to sale of property (2,005 ) — Revision of estimates (1) 11,600 2,748 Liability at end of year $ 46,306 $ 32,198 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to declining commodity prices. |
Schedule of fees received from operation of jointly owned oil and natural gas properties | The following amounts have been recorded for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Fees received for the operation of jointly-owned oil and natural gas properties $ 3,125 $ 3,265 $ 3,398 |
Schedule of Cash Flow, Supplemental Disclosures | The following table summarizes the supplemental disclosure of cash flow information for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Cash paid for interest, net of $236, $150 and $255 of capitalized interest, respectively $ 112,457 $ 104,936 $ 95,622 The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Change in accrued capital expenditures $ (86,369 ) $ 31,913 $ (5,284 ) Change in accrued capital contribution to equity method investee 27,583 (2,597 ) 2,597 Capitalized asset retirement cost 13,836 9,118 6,790 Capitalized stock-based compensation 2,321 4,650 — Equity issued in connection with acquisition — — 3,029 |
Acquisitions and divestitures (
Acquisitions and divestitures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Operating results from discontinued operations | The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the period presented: (in thousands) For the year ended December 31, 2013 Revenues $ 59,631 Expenses (1) 46,357 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. The following represents operating results from discontinued operations for the period presented: (in thousands) For the year ended December 31, 2013 Revenues: Midstream service revenue $ 4,020 Total revenues from discontinued operations 4,020 Cost and expenses: Midstream service expense, net 1,189 Depreciation and amortization 627 Total costs and expenses from discontinued operations 1,816 Non-operating expense, net — Income (loss) from discontinued operations before income tax 2,204 Income tax (expense) benefit (781 ) Income (loss) from discontinued operations $ 1,423 The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Oil, NGL and natural gas sales $ 5,138 $ 19,337 $ 24,187 Expenses (1) 5,791 11,082 11,826 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. |
Estimated fair value of assets acquired and associated liabilities of acquisition | The following table presents the Company's 2014 and 2013 acquisitions. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions, see Note C in the Company's 2013 Annual Report on Form 10-K and Note 3 in the Company's 2014 Annual Report on Form 10-K. (in thousands) Accounting treatment Cash consideration Common stock issued (2) August 28, 2014 acquisition of leasehold interests Acquisition of assets $ 192,484 $ — June 23, 2014 acquisition of evaluated and unevaluated oil and natural gas properties Acquisition method 1,800 — June 11, 2014 acquisition of evaluated and unevaluated oil and natural gas properties Acquisition method 4,693 — February 25, 2014 acquisition of mineral interests Acquisition of assets 7,305 — September 6, 2013 acquisition of evaluated and unevaluated oil and natural gas properties (1) Acquisition method 33,710 3,029 _____________________________________________________________________________ (1) The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities. (2) In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). In accordance with federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 9. |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of amounts incurred and charged to interest expenses | The following amounts have been incurred and charged to interest expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Cash payments for interest $ 112,693 $ 105,086 $ 95,877 Amortization of debt issuance costs and other adjustments 4,243 4,433 4,926 Change in accrued interest (13,481 ) 11,804 (221 ) Interest costs incurred 103,455 121,323 100,582 Less capitalized interest (236 ) (150 ) (255 ) Total interest expense $ 103,219 $ 121,173 $ 100,327 |
Schedule of carrying amount and fair value of debt instruments | The following table presents the carrying amounts and fair values of the Company's debt as of the periods presented: December 31, 2015 December 31, 2014 (in thousands) Long-term debt Fair value Long-term debt Fair value January 2019 Notes (1) $ — $ — $ 551,295 $ 550,000 January 2022 Notes 450,000 388,301 450,000 396,014 May 2022 Notes 500,000 460,000 500,000 467,529 March 2023 Notes 350,000 301,000 — — Senior Secured Credit Facility 135,000 134,993 300,000 300,279 Total value of debt $ 1,435,000 $ 1,284,294 $ 1,801,295 $ 1,713,822 _____________________________________________________________________________ (1) The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014 . |
Schedule of net presentation of the Company's long-term debt and debt issuance cost | The following tables summarize the net presentation of the Company's long-term debt and debt issuance cost on the consolidated balance sheets as of the periods presented: December 31, 2015 December 31, 2014 (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 2019 Notes (1) $ — $ — $ — $ 551,295 $ (7,031 ) $ 544,264 January 2022 Notes 450,000 (5,939 ) 444,061 450,000 (6,916 ) 443,084 May 2022 Notes 500,000 (7,066 ) 492,934 500,000 (7,901 ) 492,099 March 2023 Notes 350,000 (5,769 ) 344,231 — — — Senior Secured Credit Facility (2) 135,000 — 135,000 300,000 — 300,000 Total $ 1,435,000 $ (18,774 ) $ 1,416,226 $ 1,801,295 $ (21,848 ) $ 1,779,447 _____________________________________________________________________________ (1) The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014 . (2) Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the consolidated balance sheets. |
Employee compensation (Tables)
Employee compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity and stock-based compensation | |
Schedule of Nonvested Share Activity | The following table reflects the outstanding restricted stock awards for the years ended December 31, 2015 , 2014 and 2013 : (in thousands, except for weighted-average grant date fair values) Restricted stock awards Weighted-average grant date fair value (per award) Outstanding as of December 31, 2012 1,195 $ 15.06 Granted 1,469 $ 18.17 Forfeited (229 ) $ 18.47 Vested (1) (636 ) $ 18.69 Outstanding as of December 31, 2013 1,799 $ 19.17 Granted 1,234 $ 25.68 Forfeited (148 ) $ 22.56 Vested (1) (680 ) $ 19.13 Outstanding as of December 31, 2014 2,205 $ 22.63 Granted 1,902 $ 11.98 Forfeited (553 ) $ 20.48 Vested (1) (1,015 ) $ 22.32 Outstanding as of December 31, 2015 2,539 $ 15.26 _____________________________________________________________________________ (1) The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards. |
Schedule of Share-based Compensation, Stock Options, Activity | The following table reflects the stock option award activity for the years ended December 31, 2015 , 2014 and 2013 : (in thousands, except for weighted-average price and contractual term) Restricted stock option awards Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2012 459 $ 24.11 10 Granted 1,019 $ 17.34 Exercised (1) (104 ) $ 20.79 Expired or canceled (12 ) $ 24.11 Forfeited (133 ) $ 19.88 Outstanding as of December 31, 2013 1,229 $ 19.32 8.82 Granted 336 $ 25.60 Exercised (1) (95 ) $ 19.93 Expired or canceled (30 ) $ 21.15 Forfeited (73 ) $ 19.68 Outstanding as of December 31, 2014 1,367 $ 20.76 8.17 Granted 632 $ 11.93 Exercised — $ — Expired or canceled (82 ) $ 19.92 Forfeited (139 ) $ 18.17 Outstanding as of December 31, 2015 1,778 $ 17.86 7.91 Vested and exercisable at end of period (2) 545 $ 20.77 6.94 Expected to vest at end of period (3) 1,219 $ 16.51 8.34 _____________________________________________________________________________ (1) The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards. (2) The vested and exercisable options as of December 31, 2015 had no aggregate intrinsic value. (3) The restricted stock options expected to vest as of December 31, 2015 had no aggregate intrinsic value. |
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions | The assumptions used to estimate the fair value of restricted stock options granted are as follows: February 27, 2015 February 27, 2014 February 15, 2013 February 3, 2012 Risk-free interest rate (1) 1.70 % 1.88 % 1.19 % 1.14 % Expected option life (2) 6.25 years 6.25 years 6.25 years 6.25 years Expected volatility (3) 52.59 % 53.21 % 58.89 % 59.98 % Fair value per stock option $ 6.15 $ 13.41 $ 9.67 $ 13.52 _____________________________________________________________________________ (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 option. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option 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 for the February 27, 2015 grant. The prior grants utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility. |
Share Based Compensation Schedule Of Vesting Rights Options | In accordance with the LTIP and stock option agreement, the options 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 Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan | The following has been recorded to performance unit award compensation expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 2013 Performance Unit Award compensation expense $ 4,081 $ 409 $ 2,863 2012 Performance Unit Award compensation expense — 192 1,870 Total performance unit award compensation expense $ 4,081 $ 601 $ 4,733 The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Restricted stock award compensation $ 17,534 $ 21,982 $ 17,084 Restricted stock option award compensation 4,074 3,639 4,349 Restricted performance share award compensation 5,222 2,108 — Total stock-based compensation, gross 26,830 27,729 21,433 Less amounts capitalized in oil and natural gas properties (2,321 ) (4,650 ) — Total stock-based compensation, net of amounts capitalized $ 24,509 $ 23,079 $ 21,433 |
Schedule of Nonvested Performance-based Units Activity | The following table reflects the outstanding performance unit awards for the periods presented: (in thousands) 2013 Performance Unit Awards (2) 2012 Performance Unit Awards (3) Outstanding at December 31, 2012 — 47 Granted 58 — Forfeited (4 ) (9 ) Vested (1) (10 ) (11 ) Outstanding at December 31, 2013 44 27 Vested — (27 ) Outstanding at December 31, 2014 44 — Vested (44 ) — Outstanding at December 31, 2015 — — _____________________________________________________________________________ (1) During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit. (2) The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016. (3) The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015. |
Schedule of Defined Contribution Plans Disclosures | 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) 2015 2014 2013 Contributions $ 1,847 $ 2,202 $ 1,886 |
Performance unit awards | |
Equity and stock-based compensation | |
Schedule of Share-base Payment Award, Equity Instruments Other Than Options, Valuation Assumptions | The assumptions used to estimate the fair value of the Performance Share Awards granted are as follows: February 27, 2015 February 27, 2014 Risk-free rate (1) 0.95 % 0.63 % Dividend yield — % — % Expected volatility (2) 53.78 % 38.21 % Laredo stock closing price as of the grant date $ 11.93 $ 25.60 Fair value per performance share $ 16.23 $ 28.56 _____________________________________________________________________________ (1) The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date. (2) The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility. |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of income tax (expense) benefit | The following presents the comprehensive benefit (expense) for income taxes for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Comprehensive benefit (expense) for income taxes allocable to: Continuing operations $ 176,945 $ (164,286 ) $ (74,507 ) Discontinued operations — — (781 ) Comprehensive benefit (expense) for income taxes $ 176,945 $ (164,286 ) $ (75,288 ) Income tax benefit (expense) attributable to income (loss) from continuing operations for the periods presented consisted of the following: For the years ended December 31, (in thousands) 2015 2014 2013 Current taxes: Federal $ — $ — $ — State — — — Deferred taxes: Federal 152,590 (147,445 ) (64,034 ) State 24,355 (16,841 ) (10,473 ) Income tax benefit (expense) $ 176,945 $ (164,286 ) $ (74,507 ) |
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 benefit (expense) attributable to income (loss) from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2015 and 2014 and 34% for the year ended December 31, 2013 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2015 2014 2013 Income tax benefit (expense) computed by applying the statutory rate $ 835,408 $ (150,450 ) $ (64,969 ) State income tax, net of federal tax benefit and increase in valuation allowance 13,975 (11,099 ) (7,532 ) Non-deductible stock-based compensation (256 ) (509 ) (1,070 ) Stock-based compensation tax deficiency (3,274 ) (266 ) (559 ) Increase in deferred tax valuation allowance (668,702 ) (1,139 ) (63 ) Other items (206 ) (823 ) (314 ) Income tax benefit (expense) $ 176,945 $ (164,286 ) $ (74,507 ) |
Schedule of Income Tax Deficiency from Share-based Compensation | The following table presents the tax impact of these shortfalls for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Vesting of restricted stock $ 3,334 $ 112 $ 425 Exercise of restricted stock options — 158 150 Tax expense due to shortfalls $ 3,334 $ 270 $ 575 |
Schedule of Deferred Tax Assets and Liabilities | Significant components of the Company's net deferred tax liability as of December 31 are as follows: (in thousands) 2015 2014 Oil and natural gas properties, midstream service assets and other fixed assets $ 306,997 $ (424,712 ) Net operating loss carry-forward 479,022 353,724 Derivatives (98,675 ) (121,365 ) Stock-based compensation 11,597 10,718 Equity method investee (31,711 ) (2,331 ) Accrued bonus 4,763 3,256 Capitalized interest 2,525 3,049 Materials and supplies impairment 1,647 642 Other 1,173 1,373 Net deferred tax asset (liability) before valuation allowance 677,338 (175,646 ) Valuation allowance (677,338 ) (1,299 ) Net deferred tax asset (liability) $ — $ (176,945 ) Deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 are as follows: (in thousands) 2015 2014 (1) Offset (1) 2014 new presentation (1) Deferred tax asset $ — $ — $ — $ — Deferred tax liability: Current — (71,191 ) 71,191 — Noncurrent — (105,754 ) (71,191 ) (176,945 ) Deferred tax liability $ — $ (176,945 ) $ — $ (176,945 ) Net deferred tax liability $ — $ (176,945 ) $ — $ (176,945 ) _____________________________________________________________________________ (1) See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014. |
Summary of Operating Loss Carryforwards | The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of the period presented: (in thousands) December 31, 2015 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 915,642 Total $ 1,368,590 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative contracts transferred to buyers on sale of assets | During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale: Aggregate volumes Swap price Contract period Natural gas (volumes in MMBtu): Swap 2,386,800 $ 4.31 August 2013 - December 2013 Swap 3,978,500 $ 4.36 January 2014 - December 2014 |
Summary of derivative contracts unwound in connection with sale of assets | The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013: Aggregate volumes Floor price Ceiling price Contract period Natural gas (volumes in MMBtu): Price collar 2,200,000 $ 4.00 $ 7.05 September 2013 - December 2013 Put 2,200,000 $ 4.00 $ — September 2013 - December 2013 Price collar 3,480,000 $ 4.00 $ 7.00 January 2014 - December 2014 Price collar 1,800,000 $ 4.00 $ 7.05 January 2014 - December 2014 Price collar 1,680,000 $ 4.00 $ 7.05 January 2014 - December 2014 Price collar 1,560,000 $ 3.00 $ 5.50 January 2014 - December 2014 Price collar 2,520,000 $ 3.00 $ 6.00 January 2015 - December 2015 Price collar 2,400,000 $ 3.00 $ 6.00 January 2015 - December 2015 Price collar 2,400,000 $ 3.00 $ 6.00 January 2015 - December 2015 Subsequent to December 31, 2015, the Company entered into the following new commodity derivative contracts: Aggregate volumes Floor price Contract period Natural gas (volumes in MMBtu): (1) Put 8,040,000 $ 2.50 January 2017 - December 2017 Put 8,220,000 $ 2.50 January 2018 - December 2018 _____________________________________________________________________________ (1) The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts. |
Schedule of gains and losses on derivative instruments | The following represents cash settlements received (paid) for matured derivatives and for early terminations and modifications of derivatives for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Cash settlements received for matured commodity derivatives $ 255,281 $ 28,241 $ 4,046 Cash settlements paid for matured interest rate swaps — — (301 ) Early terminations and modification of commodity derivatives received (1) — 76,660 6,008 Cash settlements received for derivatives, net $ 255,281 $ 104,901 $ 9,753 _____________________________________________________________________________ (1) During the year ended December 31, 2013, the Company received $6.0 million , net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts. |
Schedule of notional amounts of outstanding derivative positions | The following table summarizes open positions as of December 31, 2015 , and represents, as of such date, derivatives in place through December 2017 on annual production volumes: Year Year Oil positions: (1) Puts: Hedged volume (Bbl) 1,296,000 — Weighted-average price ($/Bbl) $ 45.00 $ — Swaps: Hedged volume (Bbl) 1,573,800 — Weighted-average price ($/Bbl) $ 84.82 $ — Collars: Hedged volume (Bbl) 3,654,000 2,628,000 Weighted-average floor price ($/Bbl) $ 73.99 $ 77.22 Weighted-average ceiling price ($/Bbl) $ 89.63 $ 97.22 Totals: Total volume hedged with floor price (Bbl) 6,523,800 2,628,000 Weighted-average floor price ($/Bbl) $ 70.84 $ 77.22 Total volume hedged with ceiling price (Bbl) 5,227,800 2,628,000 Weighted-average ceiling price ($/Bbl) $ 88.18 $ 97.22 Natural gas positions: (2) Collars: Hedged volume (MMBtu) 18,666,000 5,475,000 Weighted-average floor price ($/MMBtu) $ 3.00 $ 3.00 Weighted-average ceiling price ($/MMBtu) $ 5.60 $ 4.00 _____________________________________________________________________________ (1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX"). (2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period. |
Fair value measurements (Tables
Fair value measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented: (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, 2015: Assets Current: Oil derivatives $ — $ 194,940 $ — $ 194,940 $ — $ 194,940 Natural gas derivatives — 13,166 — 13,166 — 13,166 Oil deferred premiums — — — — (9,301 ) (9,301 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 80,302 $ — $ 80,302 $ — $ 80,302 Natural gas derivatives — 2,459 — 2,459 — 2,459 Oil deferred premiums — — — — (4,877 ) (4,877 ) Natural gas deferred premiums — — — — (441 ) (441 ) Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (9,301 ) (9,301 ) 9,301 — Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (4,877 ) (4,877 ) 4,877 — Natural gas deferred premiums — — (441 ) (441 ) 441 — Net derivative position $ — $ 290,867 $ (14,619 ) $ 276,248 $ — $ 276,248 (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, 2014: Assets Current: Oil derivatives $ — $ 190,303 $ — $ 190,303 $ — $ 190,303 Natural gas derivatives — 9,647 — 9,647 — 9,647 Oil deferred premiums — — — — (4,653 ) (4,653 ) Natural gas deferred premiums — — — — (696 ) (696 ) Noncurrent: Oil derivatives $ — $ 117,963 $ — $ 117,963 $ — $ 117,963 Natural gas derivatives — 3,646 — 3,646 — 3,646 Oil deferred premiums — — — — (3,821 ) (3,821 ) Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (4,768 ) (4,768 ) 4,653 (115 ) Natural gas deferred premiums — — (696 ) (696 ) 696 — Noncurrent: Oil derivatives $ — $ — $ — $ — $ — $ — Natural gas derivatives — — — — — — Oil deferred premiums — — (3,821 ) (3,821 ) 3,821 — Natural gas deferred premiums — — — — — — Net derivative position $ — $ 321,559 $ (9,285 ) $ 312,274 $ — $ 312,274 |
Actual cash payments required for deferred premium contracts | The following table presents actual cash payments required for deferred premiums for the calendar years presented: (in thousands) December 31, 2015 2016 $ 8,629 2017 5,796 2018 426 Total $ 14,851 |
Summary of changes in assets classified as Level 3 measurements | A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows: For the years ended December 31, (in thousands) 2015 2014 2013 Balance of Level 3 at beginning of period $ (9,285 ) $ (12,684 ) $ (24,709 ) Change in net present value of deferred premiums for derivatives (203 ) (220 ) (462 ) Total purchases and settlements: Purchases (10,298 ) (3,800 ) — Settlements (1) 5,167 7,419 12,487 Balance of Level 3 at end of period $ (14,619 ) $ (9,285 ) $ (12,684 ) _____________________________________________________________________________ (1) The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive. |
Net income (loss) per share (Ta
Net income (loss) per share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share | The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2015 2014 2013 Net income (loss) (numerator): Income (loss) from continuing operations—basic and diluted $ (2,209,936 ) $ 265,573 $ 116,577 Income from discontinued operations, net of tax—basic and diluted — — 1,423 Net income (loss)—basic and diluted $ (2,209,936 ) $ 265,573 $ 118,000 Weighted-average common shares outstanding (denominator): Weighted-average common shares outstanding—basic (1) 199,158 141,312 132,490 Non-vested restricted stock awards — 2,242 1,888 Weighted-average common shares outstanding—diluted 199,158 143,554 134,378 Net income (loss) per share: Basic: Income (loss) from continuing operations $ (11.10 ) $ 1.88 $ 0.88 Income from discontinued operations, net of tax — — 0.01 Net income (loss) per share $ (11.10 ) $ 1.88 $ 0.89 Diluted: Income (loss) from continuing operations $ (11.10 ) $ 1.85 $ 0.87 Income from discontinued operations, net of tax — — 0.01 Net income (loss) per share $ (11.10 ) $ 1.85 $ 0.88 _____________________________________________________________________________ (1) For the year ended December 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders was computed taking into account the March 2015 Equity Offering. For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders was computed taking into account the August 2013 Equity Offering. |
Commitments and contingencies (
Commitments and contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 . Minimum annual lease commitments for the calendar years presented are: (in thousands) December 31, 2015 2016 $ 3,087 2017 3,244 2018 3,160 2019 2,408 2020 1,294 Thereafter 8,217 Total $ 21,410 |
Schedule of rent expense | The following has been recorded to rent expense for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Rent expense $ 2,880 $ 3,042 $ 1,923 |
Recently issued accounting st38
Recently issued accounting standards (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncement, Early Adoption | See Notes 2.k and 5.h for additional discussion of debt issuance costs. The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below: (in thousands) June 30, 2015 March 31, 2015 December 31, 2014 Noncurrent assets: Decrease in debt issuance costs, net $ (26,158 ) $ (33,513 ) $ (28,463 ) Increase in other assets, net 6,068 6,873 6,615 Decrease in total assets (20,090 ) (26,640 ) (21,848 ) Noncurrent liabilities: Decrease in long-term debt, net $ (20,090 ) $ (26,640 ) $ (21,848 ) Decrease in total liabilities (20,090 ) (26,640 ) (21,848 ) The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below: (in thousands) September 30, 2015 June 30, 2015 March 31, 2015 December 31, 2014 Noncurrent assets: Decrease in deferred income taxes $ (68,069 ) $ (45,089 ) $ — $ — Decrease in total assets (68,069 ) (45,089 ) — — Current liabilities: Decrease in deferred income taxes $ (68,069 ) $ (45,089 ) $ (73,753 ) $ (71,191 ) Decrease in total current liabilities (68,069 ) (45,089 ) (73,753 ) (71,191 ) Noncurrent liabilities: Increase in deferred income taxes $ — $ — $ 73,753 $ 71,191 Decrease in total liabilities (68,069 ) (45,089 ) — — |
Variable interest entity (Table
Variable interest entity (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | The following table summarizes items included in Medallion's consolidated statements of operations, which are not recorded in the Company's consolidated financial statements, for the periods presented: For the years ended December 31, (in thousands) 2015 (3) 2014 2013 Total revenues $ 34,288 $ 4,623 $ 892 Gross profit (1) 29,826 4,623 892 Income (loss) from continuing operations 13,821 (333 ) 54 Net income (loss) (2) 13,821 (333 ) 54 _____________________________________________________________________________ (1) Medallion's pipeline did not become operational until 2015, accordingly no costs of good sold were recorded for the years ended December 31, 2014 and 2013. (2) As Medallion's financial statements are unaudited at the time of filing the Company's Annual Report on Form 10-K, the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations for the years ended December 31, 2015 and 2014 include immaterial prior period Medallion audit adjustments. (3) Medallion's consolidated statement of operations for the year ended December 31, 2015 was unaudited as of February 17, 2016. The following table summarizes items included in Medallion's consolidated balance sheets, which are not recorded in the Company's consolidated financial statements, as of the periods presented: December 31, (in thousands) 2015 (1) 2014 Assets: Current assets $ 78,411 $ 25,777 Noncurrent assets 329,956 112,753 Total assets $ 408,367 $ 138,530 Liabilities: Current liabilities $ 15,461 $ 19,522 Noncurrent liabilities — — Total liabilities $ 15,461 $ 19,522 _____________________________________________________________________________ (1) Medallion's consolidated balance sheet as of December 31, 2015 was unaudited as of February 17, 2016. |
Related Parties (Tables)
Related Parties (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Oil and gas related party transactions | The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa and included in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Oil, NGL and natural gas sales $ 99,992 $ 96,100 $ 74,245 Midstream service revenues 590 — — The following table summarizes the amounts included in accounts receivable, net from Targa in the consolidated balance sheets as of the periods presented: December 31, (in thousands) 2015 2014 Accounts receivable, net $ 6,097 $ 12,869 The following table summarizes the capitalized oil and natural gas properties related to H&P and included in the consolidated statements of cash flows for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Capital expenditures: Oil and natural gas properties $ 2,434 $ 9,518 $ 9,943 The following table summarizes the lease operating expenses related to Archrock included in the consolidated statements of operations for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Lease operating expenses $ 1,477 $ 975 $ 51 The following table summarizes the capital expenditures related to Archrock included in the consolidated statements of cash flows for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Capital expenditures: Oil and natural gas properties $ — $ 57 $ — Midstream service assets 64 833 — The following table summarizes the amounts included in accounts payable from Archrock in the consolidated balance sheets as of the periods presented: December 31, (in thousands) 2015 2014 Accounts payable $ 13 $ — The following table summarizes items included in the consolidated statements of operations related to Medallion for the periods presented: For the years ended December 31, (in thousands) 2015 2014 2013 Midstream service revenues $ 487 $ — $ — Minimum volume commitments 5,235 2,552 891 Interest and other income 158 — — The following table summarizes items included in the consolidated balance sheets related to Medallion as of the periods presented: December 31, (in thousands) 2015 2014 Accounts receivable, net $ 1,163 $ — Other assets, net (1) 1,025 1,110 Other current liabilities (2) 27,583 3,443 _____________________________________________________________________________ (1) Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline. (2) Amounts included in "Other current liabilities" above for the year ended December 31, 2015 represents LMS's capital contribution payable to Medallion, of which a portion was paid subsequent to December 31, 2015. "Other current liabilities" above for the year ended December 31, 2014 represents LMS's minimum volume commitment payable to Medallion. See Note 15 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion. |
Segments (Tables)
Segments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment reporting information by segment | The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis: (in thousands) Exploration and production Midstream and marketing Consolidated Year ended December 31, 2015: Oil, NGL and natural gas sales $ 432,711 $ 1,692 $ (2,669 ) $ 431,734 Midstream service revenues — 27,965 (21,417 ) 6,548 Sales of purchased oil — 168,358 — 168,358 Total revenues 432,711 198,015 (24,086 ) 606,640 Lease operating expenses, including production tax 151,918 — (10,685 ) 141,233 Midstream service expenses, including minimum volume commitments 4,399 18,393 (11,711 ) 11,081 Costs of purchased oil — 174,338 — 174,338 General and administrative (1) 82,251 8,174 — 90,425 Depletion, depreciation and amortization (2) 269,631 8,093 — 277,724 Impairment expense 2,372,296 2,592 — 2,374,888 Other operating costs and expenses (3) 8,123 342 — 8,465 Operating loss $ (2,455,907 ) $ (13,917 ) $ (1,690 ) $ (2,471,514 ) Other financial information: Income from equity method investee $ — $ 6,799 $ — $ 6,799 Interest expense (4) $ (98,040 ) $ (5,179 ) $ — $ (103,219 ) Loss on early redemption of debt (5) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Income tax benefit (6) $ 171,952 $ 4,993 $ — $ 176,945 Capital expenditures $ (597,086 ) $ (35,515 ) $ — $ (632,601 ) Gross property and equipment (8) $ 5,302,716 $ 345,183 $ (1,923 ) $ 5,645,976 Year ended December 31, 2014: Oil, NGL and natural gas sales $ 738,455 $ 1,660 $ (2,912 ) $ 737,203 Midstream service revenues — 7,838 (5,593 ) 2,245 Sales of purchased oil — 54,437 — 54,437 Total revenues 738,455 63,935 (8,505 ) 793,885 Lease operating expenses, including production tax 153,427 — (6,612 ) 146,815 Midstream service expenses, including minimum volume commitments — 9,641 (1,660 ) 7,981 Costs of purchased oil — 53,967 — 53,967 General and administrative (1) 99,075 6,969 — 106,044 Depletion, depreciation and amortization (2) 241,834 4,640 — 246,474 Impairment expense 1,802 2,102 — 3,904 Other operating costs and expenses (3) 2,248 66 — 2,314 Operating income (loss) $ 240,069 $ (13,450 ) $ (233 ) $ 226,386 Other financial information: Loss from equity method investee $ — $ (192 ) $ — $ (192 ) Interest expense (4) $ (117,560 ) $ (3,613 ) $ — $ (121,173 ) Income tax (expense) benefit (6) $ (170,551 ) $ 6,265 $ — $ (164,286 ) Capital expenditures (7) $ (1,279,142 ) $ (60,607 ) $ — $ (1,339,749 ) Gross property and equipment (8) $ 4,841,895 $ 179,355 $ (233 ) $ 5,021,017 Year ended December 31, 2013: Oil, NGL and natural gas sales $ 664,844 $ — $ — $ 664,844 Midstream service revenues 328 8,824 (8,739 ) 413 Total revenues 665,172 8,824 (8,739 ) 665,257 Lease operating expenses, including production tax 130,152 — (8,620 ) 121,532 Midstream service expenses, including minimum volume commitments 2,807 1,571 (119 ) 4,259 General and administrative (1) 86,951 2,745 — 89,696 Depletion, depreciation and amortization (2) 231,703 2,241 — 233,944 Other operating costs and expenses (3) 1,475 — — 1,475 Operating income $ 212,084 $ 2,267 $ — $ 214,351 Other financial information: Income from equity method investee $ — $ 29 $ — $ 29 Interest expense (4) $ (98,680 ) $ (1,647 ) $ — $ (100,327 ) Income tax expense (6) $ (73,476 ) $ (1,031 ) $ — $ (74,507 ) Capital expenditures (7) $ (718,606 ) $ (24,409 ) $ — $ (743,015 ) Gross property and equipment (8) $ 3,516,406 $ 58,706 $ — $ 3,575,112 _____________________________________________________________________________ (1) General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015 , 2014 and 2013 . Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013. (2) Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015 , 2014 and 2013 . (3) Other operating costs and expenses include restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015 , accretion of asset retirement obligations and drilling rig fees for the year ended December 31, 2014 and accretion of asset retirement obligations for the year ended December 31, 2013. These expenses are based on actual costs and are not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013. (5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015. (6) Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% for the years ended December 31, 2015, 2014 and 2013. (7) Capital expenditures exclude acquisition of oil and natural gas properties and acquisition of mineral interests for the year ended December 31, 2014 and excludes acquisitions of oil and natural gas properties for the year ended December 31, 2013. (8) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $192.5 million, $58.3 million and $5.9 million as of December 31, 2015 , 2014 and 2013 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2015 , 2014 and 2013 . |
Subsidiary guarantors (Tables)
Subsidiary guarantors (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Schedule of condensed consolidating balance sheet | Condensed consolidating balance sheet December 31, 2015 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Accounts receivable, net $ 74,613 $ 13,086 $ — $ 87,699 Other current assets 244,477 56 — 244,533 Total oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Total midstream service assets, net — 131,725 — 131,725 Total other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 Total other long-term assets 84,360 3,916 — 88,276 Total assets $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287 Accounts payable $ 12,203 $ 1,978 $ — $ 14,181 Other current liabilities 158,283 44,351 — 202,634 Long-term debt, net 1,416,226 — — 1,416,226 Other long-term liabilities 46,034 2,765 — 48,799 Stockholders' equity 133,370 301,891 (303,814 ) 131,447 Total liabilities and stockholders' equity $ 1,766,116 $ 350,985 $ (303,814 ) $ 1,813,287 Condensed consolidating balance sheet December 31, 2014 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Accounts receivable, net $ 107,860 $ 19,069 $ — $ 126,929 Other current assets 238,300 24 — 238,324 Total oil and natural gas properties, net 3,196,231 7,277 (233 ) 3,203,275 Total midstream service assets, net — 108,462 — 108,462 Total other fixed assets, net 42,046 299 — 42,345 Investment in subsidiaries and equity method investee 163,349 58,288 (163,349 ) 58,288 Total other long-term assets 128,582 4,496 — 133,078 Total assets $ 3,876,368 $ 197,915 $ (163,582 ) $ 3,910,701 Accounts payable $ 38,453 $ 555 $ — $ 39,008 Other current liabilities 283,026 31,800 — 314,826 Long-term debt, net 1,779,447 — — 1,779,447 Other long-term liabilities 212,008 2,211 — 214,219 Stockholders' equity 1,563,434 163,349 (163,582 ) 1,563,201 Total liabilities and stockholders' equity $ 3,876,368 $ 197,915 $ (163,582 ) $ 3,910,701 |
Schedule of condensed consolidating statement of operations | Condensed consolidating statement of operations For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Total operating revenues $ 432,478 $ 198,248 $ (24,086 ) $ 606,640 Total operating costs and expenses 2,897,272 203,278 (22,396 ) 3,078,154 Loss from operations (2,464,794 ) (5,030 ) (1,690 ) (2,471,514 ) Interest expense and other, net (102,793 ) — — (102,793 ) Other non-operating income 182,396 6,708 (1,678 ) 187,426 Income (loss) from continuing operations before income tax (2,385,191 ) 1,678 (3,368 ) (2,386,881 ) Income tax benefit 176,945 — — 176,945 Income (loss) from continuing operations (2,208,246 ) 1,678 (3,368 ) (2,209,936 ) Net income (loss) $ (2,208,246 ) $ 1,678 $ (3,368 ) $ (2,209,936 ) Condensed consolidating statement of operations For the year ended December 31, 2014 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Total operating revenues $ 738,446 $ 63,944 $ (8,505 ) $ 793,885 Total operating costs and expenses 505,455 70,316 (8,272 ) 567,499 Income (loss) from operations 232,991 (6,372 ) (233 ) 226,386 Interest expense and other, net (120,879 ) — — (120,879 ) Other non-operating income (expense) 317,980 (339 ) 6,711 324,352 Income (loss) from continuing operations before income tax 430,092 (6,711 ) 6,478 429,859 Income tax expense (164,286 ) — — (164,286 ) Income (loss) from continuing operations 265,806 (6,711 ) 6,478 265,573 Net income (loss) $ 265,806 $ (6,711 ) $ 6,478 $ 265,573 Condensed consolidating statement of operations For the year ended December 31, 2013 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Total operating revenues $ 665,172 $ 8,824 $ (8,739 ) $ 665,257 Total operating costs and expenses 455,972 3,673 (8,739 ) 450,906 Income from operations 209,200 5,151 — 214,351 Interest expense and other, net (100,164 ) — — (100,164 ) Other non-operating income 84,861 2,268 (10,232 ) 76,897 Income from continuing operations before income tax 193,897 7,419 (10,232 ) 191,084 Income tax expense (74,507 ) — — (74,507 ) Income from continuing operations 119,390 7,419 (10,232 ) 116,577 Income (loss) from discontinued operations, net of tax (1,390 ) 2,813 — 1,423 Net income $ 118,000 $ 10,232 $ (10,232 ) $ 118,000 |
Schedule of condensed consolidating statement of cash flows | Condensed consolidating statement of cash flows For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Net cash flows provided by operating activities $ 316,838 $ 787 $ (1,678 ) $ 315,947 Change in investments between affiliates (136,252 ) 134,574 1,678 — Capital expenditures and other (532,146 ) (135,361 ) — (667,507 ) Net cash flows provided by financing activities 353,393 — — 353,393 Net increase in cash and cash equivalents 1,833 — — 1,833 Cash and cash equivalents at beginning of period 29,320 1 — 29,321 Cash and cash equivalents at end of period $ 31,153 $ 1 $ — $ 31,154 Condensed consolidating statement of cash flows For the year ended December 31, 2014 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Net cash flows provided (used) by operating activities $ 496,955 $ (5,389 ) $ 6,711 $ 498,277 Change in investments between affiliates (113,449 ) 120,160 (6,711 ) — Capital expenditures and other (1,292,191 ) (114,770 ) — (1,406,961 ) Net cash flows provided by financing activities 739,852 — — 739,852 Net (decrease) increase in cash and cash equivalents (168,833 ) 1 — (168,832 ) Cash and cash equivalents at beginning of period 198,153 — — 198,153 Cash and cash equivalents at end of period $ 29,320 $ 1 $ — $ 29,321 Condensed consolidating statement of cash flows For the year ended December 31, 2013 (in thousands) Laredo Subsidiary Guarantors Intercompany eliminations Consolidated company Net cash flows provided by operating activities $ 359,198 $ 15,763 $ (10,232 ) $ 364,729 Change in investments between affiliates 23,986 (34,218 ) 10,232 — Capital expenditures and other (348,339 ) 18,455 — (329,884 ) Net cash flows provided by financing activities 130,084 — — 130,084 Net increase in cash and cash equivalents 164,929 — — 164,929 Cash and cash equivalents at beginning of period 33,224 — — 33,224 Cash and cash equivalents at end of period $ 198,153 $ — $ — $ 198,153 |
Subsequent events (Tables)
Subsequent events (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Schedule of new commodity contracts | The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013: Aggregate volumes Floor price Ceiling price Contract period Natural gas (volumes in MMBtu): Price collar 2,200,000 $ 4.00 $ 7.05 September 2013 - December 2013 Put 2,200,000 $ 4.00 $ — September 2013 - December 2013 Price collar 3,480,000 $ 4.00 $ 7.00 January 2014 - December 2014 Price collar 1,800,000 $ 4.00 $ 7.05 January 2014 - December 2014 Price collar 1,680,000 $ 4.00 $ 7.05 January 2014 - December 2014 Price collar 1,560,000 $ 3.00 $ 5.50 January 2014 - December 2014 Price collar 2,520,000 $ 3.00 $ 6.00 January 2015 - December 2015 Price collar 2,400,000 $ 3.00 $ 6.00 January 2015 - December 2015 Price collar 2,400,000 $ 3.00 $ 6.00 January 2015 - December 2015 Subsequent to December 31, 2015, the Company entered into the following new commodity derivative contracts: Aggregate volumes Floor price Contract period Natural gas (volumes in MMBtu): (1) Put 8,040,000 $ 2.50 January 2017 - December 2017 Put 8,220,000 $ 2.50 January 2018 - December 2018 _____________________________________________________________________________ (1) The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts. |
Supplemental oil, NGL and nat44
Supplemental oil, NGL and natural gas disclosures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 | Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below: For the years ended December 31, (in thousands) 2015 2014 2013 Property acquisition costs: Evaluated $ — $ 3,873 $ 9,652 Unevaluated — 9,925 27,087 Exploration (1) 20,697 242,284 48,763 Development costs (2) 500,577 1,049,317 654,452 Total costs incurred $ 521,274 $ 1,305,399 $ 739,954 _____________________________________________________________________________ (1) The Company acquired significant leasehold interests during the year ended December 31, 2014. (2) The costs incurred for oil, NGL and natural gas development activities include $ 13.4 million , $ 6.9 million and $ 6.8 million in asset retirement obligations for the years ended December 31, 2015 , 2014 and 2013 , respectively. |
Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment | Aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment are presented below: For the years ended December 31, (in thousands) 2015 2014 2013 Capitalized costs: Evaluated properties $ 5,103,635 $ 4,446,781 $ 3,276,578 Unevaluated properties not being depleted 140,299 342,731 208,085 5,243,934 4,789,512 3,484,663 Less accumulated depletion and impairment (4,218,942 ) (1,586,237 ) (1,349,315 ) Net capitalized costs $ 1,024,992 $ 3,203,275 $ 2,135,348 |
Summary of oil and natural gas property costs not being amortized by year | The following table shows a summary of the oil, NGL and natural gas property costs not being depleted as of December 31, 2015 , by year in which such costs were incurred: (in thousands) 2015 2014 2013 2012 and prior Total Unevaluated properties not being depleted $ 12,640 $ 110,955 $ 9,293 $ 7,411 $ 140,299 |
Summary of results of oil and natural gas producing activities (excluding corporate overhead and interest costs) | The results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) are presented below: For the years ended December 31, (in thousands) 2015 2014 2013 Revenues: Oil, NGL and natural gas sales $ 431,734 $ 737,203 $ 664,844 Production costs: Lease operating expenses 108,341 96,503 79,136 Production and ad valorem taxes 32,892 50,312 42,396 141,233 146,815 121,532 Other costs: Depletion 263,666 237,067 227,992 Accretion of asset retirement obligations 2,236 1,721 1,475 Impairment expense 2,369,477 — — Income tax (benefit) expense (1) (164,141 ) 126,576 112,984 Results of operations $ (2,180,737 ) $ 225,024 $ 200,861 _____________________________________________________________________________ (1) During the year ended December 31, 2015, the Company recorded a valuation allowance against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the year ended December 31, 2015, income tax benefit is computed utilizing the Company's effective rate of 7% , 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 benefit for the period. For the years ended December 31, 2014 and 2013, income tax expense is computed utilizing the statutory rate. |
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 reserve quantities of oil, NGL and natural gas for the year ended December 31, 2015 and of oil and liquids-rich natural gas for the years ended December 31, 2014 and 2013 , all of which are located within the United States. Year ended December 31, 2015 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 140,190 — 642,794 247,322 Revisions of previous estimates (1) (88,900 ) 35,477 (424,546 ) (124,180 ) Extensions, discoveries and other additions 10,511 5,865 36,074 22,388 Sales of reserves in place (1,552 ) (1,008 ) (5,554 ) (3,486 ) Production (7,610 ) (4,267 ) (26,816 ) (16,346 ) End of year 52,639 36,067 221,952 125,698 Proved developed reserves: Beginning of year 56,975 — 291,493 105,557 End of year 40,944 29,349 180,613 100,395 Proved undeveloped reserves: Beginning of year 83,215 — 351,301 141,765 End of year 11,695 6,718 41,339 25,303 _____________________________________________________________________________ (1) The positive NGL revisions of previous estimates and the negative natural gas revisions of previous estimates include the impact of the Company's conversion to three-stream production. For periods prior to January 1, 2015, the Company presented its reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability to prior periods. Year ended December 31, 2014 Oil Gas MBOE Proved developed and undeveloped reserves: Beginning of year 111,498 552,702 203,615 Revisions of previous estimates (10,134 ) (67,350 ) (21,359 ) Extensions, discoveries and other additions 45,554 185,909 76,539 Purchases of reserves in place 173 498 256 Production (6,901 ) (28,965 ) (11,729 ) End of year 140,190 642,794 247,322 Proved developed reserves: Beginning of year 37,878 203,082 71,725 End of year 56,975 291,493 105,557 Proved undeveloped reserves: Beginning of year 73,620 349,620 131,890 End of year 83,215 351,301 141,765 Year ended December 31, 2013 Oil Gas MBOE Proved developed and undeveloped reserves: Beginning of year 98,141 542,946 188,632 Revisions of previous estimates (17,956 ) 15,710 (15,338 ) Extensions, discoveries and other additions 37,850 192,229 69,888 Purchases of reserves in place 170 1,454 412 Sale of reserves in place (1,220 ) (165,289 ) (28,768 ) Production (5,487 ) (34,348 ) (11,211 ) End of year 111,498 552,702 203,615 Proved developed reserves: Beginning of year 33,316 289,045 81,490 End of year 37,878 203,082 71,725 Proved undeveloped reserves: Beginning of year 64,825 253,901 107,142 End of year 73,620 349,620 131,890 |
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | The standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves is as follows: For the years ended December 31, (in thousands) 2015 2014 2013 Future cash inflows $ 3,269,184 $ 16,663,685 $ 13,337,798 Future production costs (1,321,471 ) (3,616,775 ) (3,059,368 ) Future development costs (376,701 ) (2,471,985 ) (2,250,950 ) Future income tax expenses — (2,827,763 ) (2,150,983 ) Future net cash flows 1,571,012 7,747,162 5,876,497 10% discount for estimated timing of cash flows (740,265 ) (4,500,434 ) (3,554,293 ) Standardized measure of discounted future net cash flows $ 830,747 $ 3,246,728 $ 2,322,204 |
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves are as follows: For the years ended December 31, (in thousands) 2015 2014 2013 Standardized measure of discounted future net cash flows, beginning of year $ 3,246,728 $ 2,322,204 $ 1,877,456 Changes in the year resulting from: Sales, less production costs (290,501 ) (590,388 ) (543,312 ) Revisions of previous quantity estimates (2,444,322 ) (320,275 ) (190,961 ) Extensions, discoveries and other additions 192,979 1,340,022 1,166,481 Net change in prices and production costs (1,495,144 ) 145,740 313,947 Changes in estimated future development costs (2,974 ) (22,961 ) 921 Previously estimated development costs incurred during the period 162,237 92,135 89,396 Purchases of reserves in place — 6,100 7,604 Divestitures of reserves in place (29,149 ) — (239,148 ) Accretion of discount 424,453 305,325 234,852 Net change in income taxes 997,805 (266,757 ) (259,991 ) Timing differences and other 68,635 235,583 (135,041 ) Standardized measure of discounted future net cash flows, end of year $ 830,747 $ 3,246,728 $ 2,322,204 |
Supplemental quarterly financ45
Supplemental quarterly financial data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of results of operations by quarter | The Company's results from continuing operations by quarter for the periods presented are as follows: Year ended December 31, 2015 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 150,694 $ 182,331 $ 150,340 $ 123,275 Operating loss (26,498 ) (501,480 ) (927,859 ) (1,015,677 ) Net loss (472 ) (397,034 ) (847,783 ) (964,647 ) Net loss per common share: Basic $ — $ (1.88 ) $ (4.01 ) $ (4.57 ) Diluted $ — $ (1.88 ) $ (4.01 ) $ (4.57 ) Year ended December 31, 2014 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 173,310 $ 183,044 $ 200,241 $ 237,290 Operating income 60,038 64,561 69,164 32,623 Net income (loss) (213 ) (18,899 ) 83,407 201,278 Net income (loss) per common share: Basic $ — $ (0.13 ) $ 0.59 $ 1.42 Diluted $ — $ (0.13 ) $ 0.58 $ 1.40 |
Organization (Details)
Organization (Details) | Dec. 31, 2013subsidiary | Dec. 31, 2015segment |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Number of subsidiaries | subsidiary | 2 | |
Number of segments | segment | 2 |
Basis of presentation and sig47
Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Accounts receivable | |||
Term of accounts receivable to be considered as past due (in days) | 30 days | ||
Term of past due balances to be reviewed individually for collectability (in days) | 90 days | ||
Matured derivatives | $ 27,469 | $ 16,098 | |
Oil, NGL and natural gas sales | 25,582 | 57,070 | |
Joint operations, net | [1] | 21,375 | 33,808 |
Purchased oil and other product sales | 11,775 | 18,917 | |
Other | 1,498 | 1,036 | |
Total | 87,699 | 126,929 | |
Allowance for doubtful accounts of accounts receivable for joint operations | $ 200 | $ 800 | |
[1] | Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of December 31, 2015 and 2014, respectively. |
Basis of presentation and sig48
Basis of presentation and significant accounting policies - Oil and natural gas properties (Details) $ in Thousands | Dec. 31, 2015USD ($)$ / bbl$ / MMBTU | Sep. 30, 2015$ / bbl$ / MMBTU | Jun. 30, 2015$ / bbl$ / MMBTU | Mar. 31, 2015$ / bbl$ / MMBTU | Sep. 30, 2015USD ($) | [1] | Jun. 30, 2015USD ($) | [1] | Mar. 31, 2015USD ($) | [1] | Dec. 31, 2015USD ($)$ / Boe | Dec. 31, 2014USD ($)$ / bbl$ / Boe$ / MMBTU | Dec. 31, 2013USD ($)$ / bbl$ / Boe$ / MMBTU | |||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Unevaluated properties not being depleted | $ | $ 140,299 | $ 140,299 | $ 342,731 | $ 208,085 | ||||||||||||
Accumulated depletion | $ | (4,200,000) | (4,200,000) | (1,600,000) | |||||||||||||
Depletion expense | $ | $ 263,700 | $ 237,100 | $ 228,000 | |||||||||||||
Depletion expense per physical unit of production (in USD per BOE) | $ / Boe | 16.13 | 20.21 | 20.34 | |||||||||||||
Discount rate used in calculating full cost ceiling (as a percent) | 10.00% | |||||||||||||||
Unamortized capitalized | $ | $ 975,011 | [1] | $ 906,420 | $ 488,046 | $ 0 | $ 2,400,000 | ||||||||||
Natural Gas | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Benchmark Prices | $ / MMBTU | 2.47 | 2.89 | 3.22 | 3.73 | 4.25 | [1] | 3.57 | [1] | ||||||||
Realized Prices | $ / MMBTU | 1.89 | 2.30 | 2.62 | 3.09 | 6.39 | [1] | 5.52 | [1] | ||||||||
Crude Oil | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Benchmark Prices | $ / bbl | 46.79 | 55.73 | 68.17 | 79.21 | 91.48 | [1] | 93.52 | [1] | ||||||||
Realized Prices | $ / bbl | 45.58 | 54.28 | 66.68 | 77.72 | 89.57 | [1] | 92.26 | [1] | ||||||||
Natural Gas Liquids | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Benchmark Prices | $ / bbl | 18.75 | 21.87 | 26.73 | 31.25 | ||||||||||||
Realized Prices | $ / bbl | 12.50 | 15.25 | 19.56 | 23.75 | ||||||||||||
[1] | For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods. |
Basis of presentation and sig49
Basis of presentation and significant accounting policies - Midstream service assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Property, Plant and Equipment [Line Items] | ||||
Depletion, depreciation and amortization | [1] | $ 277,724 | $ 246,474 | $ 233,944 |
Property and equipment, net | 1,200,255 | 3,354,082 | ||
Midstream service assets | ||||
Property, Plant and Equipment [Line Items] | ||||
Depletion, depreciation and amortization | 7,500 | 4,300 | $ 1,500 | |
Midstream Service Assets | 147,811 | 117,052 | ||
Less accumulated depreciation | (16,086) | (8,590) | ||
Property and equipment, net | $ 131,725 | $ 108,462 | ||
Midstream service assets | Minimum | ||||
Property, Plant and Equipment [Line Items] | ||||
Useful life (in years) | 10 years | |||
Midstream service assets | Maximum | ||||
Property, Plant and Equipment [Line Items] | ||||
Useful life (in years) | 20 years | |||
[1] | Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. |
Basis of presentation and sig50
Basis of presentation and significant accounting policies - Other fixed assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Pipeline and other gas gathering assets and other fixed assets | ||||
Depreciation, depletion and amortization | [1] | $ 277,724 | $ 246,474 | $ 233,944 |
Property and equipment, net | 1,200,255 | 3,354,082 | ||
Other fixed assets | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Depreciation, depletion and amortization | 6,500 | 5,100 | $ 4,400 | |
Property and equipment, net | 43,538 | 42,345 | ||
Computer hardware and software | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | 12,148 | 13,495 | ||
Vehicles | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | 9,266 | 7,802 | ||
Leasehold improvements | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | 7,710 | 6,867 | ||
Real estate and buildings | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | 7,618 | 4,908 | ||
Aircraft | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | 4,952 | 4,952 | ||
Other | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | 5,105 | 4,909 | ||
Depreciable total, net | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | 46,799 | 42,933 | ||
Less accumulated depreciation | (18,169) | (13,820) | ||
Property and equipment, net | 28,630 | 29,113 | ||
Land | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Other fixed assets, net | $ 14,908 | $ 13,232 | ||
Minimum | Other | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Useful life (in years) | 3 years | |||
Maximum | Other | ||||
Pipeline and other gas gathering assets and other fixed assets | ||||
Useful life (in years) | 10 years | |||
[1] | Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. |
Basis of presentation and sig51
Basis of presentation and significant accounting policies - Income tax, Long-lived assets and Cash flow disclosure (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Materials and supplies | |||
Impairment expense | $ 2,374,888,000 | $ 3,904,000 | $ 0 |
Unrecognized tax benefits | 0 | 0 | 0 |
Supplemental Cash Flow Information | |||
Cash paid for interest, net of $236, $150 and $255 of capitalized interest, respectively | 112,457,000 | 104,936,000 | 95,622,000 |
Capitalized interest | 236,000 | 150,000 | 255,000 |
Materials and Supplies | Nonrecurring | Level 2 | |||
Materials and supplies | |||
Impairment expense | 2,800,000 | 1,800,000 | |
Line-fill | Nonrecurring | Level 2 | |||
Materials and supplies | |||
Impairment expense | 1,300,000 | 2,100,000 | |
Compressed Natural Gas station | Nonrecurring | Level 2 | |||
Materials and supplies | |||
Impairment expense | $ 1,300,000 | $ 0 | $ 0 |
Basis of presentation and sig52
Basis of presentation and significant accounting policies - Debt issuance costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Deferred loan costs | |||
Payments of Debt Issuance Costs | $ 6,759 | $ 7,791 | $ 2,987 |
Debt issuance cost, net | 23,932 | 28,500 | |
Accumulated amortization | 17,000 | 19,400 | |
Write-off of debt issuance costs | 0 | 124 | $ 1,502 |
Deferred finance costs | 18,774 | 21,848 | |
Future amortization expense of deferred loan costs | |||
2,016 | 4,503 | ||
2,017 | 4,575 | ||
2,018 | 4,349 | ||
2,019 | 2,915 | ||
2,020 | 3,005 | ||
Thereafter | 4,585 | ||
Total | 23,932 | 28,500 | |
January 2011 | Senior Notes | |||
Deferred loan costs | |||
Write-off of debt issuance costs | 6,600 | ||
Accounting Standards Update 2015-03 | Adjustments for New Accounting Principle, Early Adoption | |||
Deferred loan costs | |||
Deferred finance costs | $ 18,800 | $ 21,800 |
Basis of presentation and sig53
Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Accounting Policies [Abstract] | |||
Capital contribution payable to equity method investee | [1] | $ 27,583 | $ 0 |
Accrued interest payable | 24,208 | 37,689 | |
Accrued compensation and benefits | 14,342 | 13,034 | |
Lease operating expense payable | 13,205 | 11,963 | |
Costs of purchased oil | 12,189 | 20,114 | |
Other accrued liabilities | 14,695 | 18,232 | |
Total other current liabilities | $ 106,222 | $ 101,032 | |
[1] | See Notes 15, 16 and 19.b for additional discussion regarding our equity method investee. |
Basis of presentation and sig54
Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Liability at beginning of year | $ 32,198 | $ 21,743 | ||
Liabilities added due to acquisitions, drilling, midstream service asset construction and other | 2,236 | 6,370 | ||
Accretion expense | 2,423 | 1,787 | $ 1,475 | |
Liabilities settled upon plugging and abandonment | (146) | (450) | ||
Liabilities removed due to sale of property | (2,005) | 0 | ||
Revision of estimates(1) | [1] | 11,600 | 2,748 | |
Liability at end of year | $ 46,306 | $ 32,198 | $ 21,743 | |
[1] | The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to declining commodity prices. |
Basis of presentation and sig55
Basis of presentation and significant accounting policies - Revenue recognition and General and administrative expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenue recognition | |||
Value of net underproduced (overproduced) positions arising during the period increasing (decreasing) oil and natural gas sales | $ 30 | ||
General and administrative expense | |||
Fees received for the operation of jointly-owned oil and natural gas properties | $ 3,125 | $ 3,265 | $ 3,398 |
Basis of presentation and sig56
Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accounting Policies [Abstract] | |||
Change in accrued capital expenditures | $ (86,369) | $ 31,913 | $ (5,284) |
Change in accrued capital contribution to equity method investee | 27,583 | (2,597) | 2,597 |
Capitalized asset retirement cost | 13,836 | 9,118 | 6,790 |
Capitalized stock-based compensation | 2,321 | 4,650 | 0 |
Equity issued in connection with acquisition | $ 0 | $ 0 | $ 3,029 |
Equity offering (Details)
Equity offering (Details) - USD ($) $ / shares in Units, $ in Thousands | Mar. 05, 2015 | Aug. 27, 2013 | Aug. 19, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Class of Stock [Line Items] | ||||||
Proceeds from issuance of common stock, net of offering costs | $ 754,200 | $ 298,100 | $ 754,163 | $ 0 | $ 298,104 | |
Common Stock | ||||||
Class of Stock [Line Items] | ||||||
Stock issued during the period (in shares) | 69,000,000 | 13,000,000 | 0 | |||
Sale of stock by existing shareholders (shares) | 1,577,583 | 3,000,000 | ||||
Shares issued (dollars per share) | $ 11.05 | $ 23.75 | ||||
Sale of stock, net of underwriting discount (dollars per share) | $ 22.9781 | |||||
Common Stock | Warburg Pincus LLC | ||||||
Class of Stock [Line Items] | ||||||
Stock issued during the period (in shares) | 29,800,000 | |||||
Ownership percentage | 41.00% |
Acquisitions and divestitures -
Acquisitions and divestitures - 2015 Divestiture of non-strategic assets (Details) - Disposal Group, Disposed of by Sale, Not Discontinued Operations - Non-strategic Assets $ in Millions | Sep. 15, 2015USD ($)aproperty |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Area of Land (in acres) | a | 6,060 |
Number of real estate Properties | property | 123 |
Sales price | $ 65.5 |
Total revenues from discontinued operations | $ 64.8 |
Acquisitions and divestitures59
Acquisitions and divestitures - 2015 Divestiture of non-strategic assets - Revenues and Expenses (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Oil, NGL and natural gas sales | $ 4,020 | |||
Non-strategic Assets | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Oil, NGL and natural gas sales | $ 5,138 | $ 19,337 | 24,187 | |
Expenses | [1] | $ 5,791 | $ 11,082 | $ 11,826 |
[1] | Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. |
Acquisitions and divestitures60
Acquisitions and divestitures - Summary of 2014 and 2013 acquisitions (Details) - USD ($) $ / shares in Units, $ in Thousands | Aug. 28, 2014 | Jun. 23, 2014 | Jun. 11, 2014 | Feb. 25, 2014 | Sep. 06, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Business Acquisition [Line Items] | ||||||||||
Oil and natural gas properties | $ 588,017 | $ 1,251,757 | $ 702,349 | |||||||
Payments to acquire mineral rights | 0 | 7,305 | 0 | |||||||
Cash consideration | $ 0 | $ 6,493 | $ 33,710 | |||||||
Leasehold Interests | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and natural gas properties | $ 192,484 | |||||||||
Common stock issued | [1] | $ 0 | ||||||||
Proved and Unproved Oil and Natural Gas Properties | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Costs incurred | $ 1,800 | $ 4,693 | ||||||||
Cash consideration | [2] | $ 33,710 | ||||||||
Common stock issued | [1] | $ 0 | $ 0 | 3,029 | [2] | |||||
Other assets | 200 | |||||||||
Liabilities assumed | $ 200 | |||||||||
Equity issued for acquisition, net of offering costs (in shares) | 123,803 | |||||||||
Closing price per share (in dollars per share) | $ 26.21 | |||||||||
Proved and Unproved Oil and Natural Gas Properties | Level 3 | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Lack of marketability discount to share price (as a percent) | 6.64% | |||||||||
Proved Oil and Natural Gas Properties | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Evaluated oil and natural gas properties | $ 9,700 | |||||||||
Unproved Oil and Natural Gas Properties | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Evaluated oil and natural gas properties | $ 27,100 | |||||||||
Mineral Interests | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Payments to acquire mineral rights | $ 7,305 | |||||||||
Common stock issued | [1] | $ 0 | ||||||||
[1] | In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). In accordance with federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 9. | |||||||||
[2] | The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities. |
Acquisitions and divestitures61
Acquisitions and divestitures - 2013 Divestitures (Details) a in Thousands, $ in Millions | Aug. 01, 2013USD ($) | Dec. 31, 2013USD ($) | Dec. 20, 2013USD ($)aproperty |
Dalhart Basin Acreage | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Area of Land (in acres) | a | 37 | ||
Number of real estate Properties | property | 1 | ||
Total revenues from discontinued operations | $ 20.4 | ||
Andarko Basin | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Consideration net of transaction costs | $ 428.3 | ||
Gain on disposal of assets | $ 3.2 | ||
EnerVest | Andarko Basin | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Proceeds from sale of oil and gas property and equipment, gross | 400 | ||
Other Third Parties | Andarko Basin | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Proceeds from sale of oil and gas property and equipment, gross | 38 | ||
Oil and Gas Properties | Andarko Basin | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Decrease in oil and gas property full cost | $ 388 |
Acquisitions and divestitures62
Acquisitions and divestitures - 2013 Divestitures - Results of operations (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2013USD ($) | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Midstream service revenue | $ 4,020 | |
Total revenues from discontinued operations | 4,020 | |
Midstream service expense, net | 1,189 | |
Depreciation and amortization | 627 | |
Total costs and expenses from discontinued operations | 1,816 | |
Non-operating expense, net | 0 | |
Income (loss) from discontinued operations before income tax | 2,204 | |
Income tax (expense) benefit | (781) | |
Income (loss) from discontinued operations | 1,423 | |
Andarko Basin | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Expenses | 46,357 | [1] |
Total revenues from discontinued operations | $ 59,631 | |
[1] | Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. |
Debt - Interest expense (Detail
Debt - Interest expense (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Debt Disclosure [Abstract] | ||||
Cash payments for interest | $ 112,693 | $ 105,086 | $ 95,877 | |
Amortization of debt issuance costs and other adjustments | 4,243 | 4,433 | 4,926 | |
Change in accrued interest | (13,481) | 11,804 | (221) | |
Interest costs incurred | 103,455 | 121,323 | 100,582 | |
Less capitalized interest | (236) | (150) | (255) | |
Total interest expense | [1] | $ 103,219 | $ 121,173 | $ 100,327 |
[1] | Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013. |
Debt - March 2023 Notes (Detail
Debt - March 2023 Notes (Details) - USD ($) | Mar. 18, 2015 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||
Face amount of debt | $ 1,435,000,000 | $ 1,801,295,000 | |
Senior Notes | March 2023 Notes | |||
Debt Instrument [Line Items] | |||
Face amount of debt | $ 350,000,000 | $ 350,000,000 | $ 0 |
Stated rate (as a percent) | 6.25% | ||
Net proceeds from offering | $ 343,600,000 | ||
Senior Notes | March 2023 Notes | Period 2 | |||
Debt Instrument [Line Items] | |||
Percentage of aggregate principal amount, that can be redeemed by equity offering | 35.00% | ||
Redemption price (as a percent) | 65.00% | ||
Debt instrument redemption principal amount outstanding threshold (in days) | 180 days | ||
Redemption start date | Mar. 18, 2015 | ||
Redemption end date | Mar. 15, 2018 | ||
Senior Notes | March 2023 Notes | Period 1 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 110.00% | ||
Redemption start date | Mar. 18, 2015 | ||
Redemption end date | Mar. 15, 2016 | ||
Senior Notes | March 2023 Notes | IPO | Period 2 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 106.25% |
Debt - January 2022 Notes (Deta
Debt - January 2022 Notes (Details) - USD ($) | Jan. 23, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||
Face amount of debt | $ 1,435,000,000 | $ 1,801,295,000 | |
Senior Notes | Senior Note 5.625% due 2022 | |||
Debt Instrument [Line Items] | |||
Face amount of debt | $ 450,000,000 | $ 450,000,000 | $ 450,000,000 |
Stated rate (as a percent) | 5.625% | ||
Net proceeds from offering | $ 442,200,000 | ||
Senior Notes | Senior Note 5.625% due 2022 | Period 2 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 100.00% | ||
Percentage of aggregate principal amount, that can be redeemed by equity offering | 35.00% | ||
Debt instrument redemption principal amount outstanding threshold (percentage) | 65.00% | ||
Debt instrument redemption principal amount outstanding threshold (in days) | 180 days | ||
Senior Notes | Senior Note 5.625% due 2022 | Period 3 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 105.625% |
Debt - May 2022 Notes (Details)
Debt - May 2022 Notes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Apr. 27, 2012 | |
Debt Instrument [Line Items] | |||
Face amount of debt | $ 1,435,000,000 | $ 1,801,295,000 | |
Senior Notes | Senior Notes 7.375 Percent Due 2022 | |||
Debt Instrument [Line Items] | |||
Face amount of debt | $ 500,000,000 | $ 500,000,000 | $ 500,000,000 |
Stated rate (as a percent) | 7.375% | ||
Senior Notes | May 2022 Notes | Period 2 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 103.688% | ||
Senior Notes | May 2022 Notes | Period 3 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 102.458% | ||
Senior Notes | May 2022 Notes | Period 4 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 101.229% | ||
Senior Notes | May 2022 Notes | Period 5 | |||
Debt Instrument [Line Items] | |||
Redemption price (as a percent) | 100.00% |
Debt - January 2019 Notes (Deta
Debt - January 2019 Notes (Details) - USD ($) | Apr. 06, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 19, 2011 | Jan. 20, 2011 | ||
Debt Instrument [Line Items] | ||||||||
Face amount of debt | $ 1,435,000,000 | $ 1,801,295,000 | ||||||
Loss on early redemption of debt | 31,537,000 | [1] | 0 | $ 0 | ||||
Senior Notes | January 2011 | ||||||||
Debt Instrument [Line Items] | ||||||||
Face amount of debt | $ 350,000,000 | |||||||
Stated rate (as a percent) | 9.50% | |||||||
Senior Notes | October 2011 | ||||||||
Debt Instrument [Line Items] | ||||||||
Face amount of debt | $ 200,000,000 | |||||||
Senior Notes | Senior Notes 9.5 Percent 2019 | ||||||||
Debt Instrument [Line Items] | ||||||||
Face amount of debt | [2] | $ 0 | $ 551,295,000 | |||||
Repurchased amount | $ 550,000,000 | |||||||
Redemption price (as a percent) | 104.75% | |||||||
Loss on early redemption of debt | $ 31,500,000 | |||||||
[1] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015. | |||||||
[2] | The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014. |
Debt - Senior Secured Credit Fa
Debt - Senior Secured Credit Facility (Details) - Secured Debt | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Line of Credit | |
Debt Instrument [Line Items] | |
Collateral as a percentage of present value of proved reserves | 80.00% |
Current ratio requirement (as a percent) | 1 |
Consolidated interest coverage ratio | 2.50 |
Letters of credit | |
Debt Instrument [Line Items] | |
Borrowing capacity | $ 20,000,000 |
Letters of credit outstanding | 0 |
Line of Credit | |
Debt Instrument [Line Items] | |
Borrowing capacity | 2,000,000,000 |
Current borrowing capacity | 1,150,000,000 |
Aggregate elected commitment | 1,000,000,000 |
Line of credit | $ 135,000,000 |
Interest rate (as a percent) | 1.90% |
Minimum | Base Rate | |
Debt Instrument [Line Items] | |
Basis spread on variable rate (percent) | 0.50% |
Minimum | London Interbank Offered Rate (LIBOR) | |
Debt Instrument [Line Items] | |
Basis spread on variable rate (percent) | 1.50% |
Minimum | Senior Secured Credit Facility | |
Debt Instrument [Line Items] | |
Commitment fee on unused capacity (as a percent) | 0.375% |
Maximum | Base Rate | |
Debt Instrument [Line Items] | |
Basis spread on variable rate (percent) | 1.50% |
Maximum | London Interbank Offered Rate (LIBOR) | |
Debt Instrument [Line Items] | |
Basis spread on variable rate (percent) | 2.50% |
Maximum | Senior Secured Credit Facility | |
Debt Instrument [Line Items] | |
Commitment fee on unused capacity (as a percent) | 0.50% |
Debt - Fair value of debt (Deta
Debt - Fair value of debt (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Senior Notes | October 2011 | |||
Debt Instrument [Line Items] | |||
Unamortized premium | $ 1,300 | ||
Long-term debt | |||
Debt Instrument [Line Items] | |||
Debt | $ 1,435,000 | 1,801,295 | |
Long-term debt | Senior Notes | Senior Notes 9.5 Percent 2019 | |||
Debt Instrument [Line Items] | |||
Debt | [1] | 0 | 551,295 |
Long-term debt | Senior Notes | Senior Note 5.625% due 2022 | |||
Debt Instrument [Line Items] | |||
Debt | 450,000 | 450,000 | |
Long-term debt | Senior Notes | Senior Notes 7.375 Percent Due 2022 | |||
Debt Instrument [Line Items] | |||
Debt | 500,000 | 500,000 | |
Long-term debt | Senior Notes | March 2023 Notes | |||
Debt Instrument [Line Items] | |||
Debt | 350,000 | 0 | |
Long-term debt | Line of Credit | Secured Debt | |||
Debt Instrument [Line Items] | |||
Debt | 135,000 | 300,000 | |
Fair value | |||
Debt Instrument [Line Items] | |||
Debt | 1,284,294 | 1,713,822 | |
Fair value | Senior Notes | Senior Notes 9.5 Percent 2019 | |||
Debt Instrument [Line Items] | |||
Debt | [1] | 0 | 550,000 |
Fair value | Senior Notes | Senior Note 5.625% due 2022 | |||
Debt Instrument [Line Items] | |||
Debt | 388,301 | 396,014 | |
Fair value | Senior Notes | Senior Notes 7.375 Percent Due 2022 | |||
Debt Instrument [Line Items] | |||
Debt | 460,000 | 467,529 | |
Fair value | Senior Notes | March 2023 Notes | |||
Debt Instrument [Line Items] | |||
Debt | 301,000 | 0 | |
Fair value | Line of Credit | Secured Debt | |||
Debt Instrument [Line Items] | |||
Debt | $ 134,993 | $ 300,279 | |
[1] | The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014. |
Debt - Debt issuance costs (Det
Debt - Debt issuance costs (Details) - USD ($) | Dec. 31, 2015 | Mar. 18, 2015 | Dec. 31, 2014 | Jan. 23, 2014 | Apr. 27, 2012 | |
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 1,435,000,000 | $ 1,801,295,000 | ||||
Debt issuance costs, net | (18,774,000) | (21,848,000) | ||||
Long-term debt, net | 1,416,226,000 | 1,779,447,000 | ||||
Senior Notes | Senior Notes 9.5 Percent 2019 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | [1] | 0 | 551,295,000 | |||
Debt issuance costs, net | [1] | 0 | (7,031,000) | |||
Long-term debt, net | [1] | 0 | 544,264,000 | |||
Senior Notes | Senior Note 5.625% due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 450,000,000 | 450,000,000 | $ 450,000,000 | |||
Debt issuance costs, net | (5,939,000) | (6,916,000) | ||||
Long-term debt, net | 444,061,000 | 443,084,000 | ||||
Senior Notes | Senior Notes 7.375 Percent Due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 500,000,000 | 500,000,000 | $ 500,000,000 | |||
Debt issuance costs, net | (7,066,000) | (7,901,000) | ||||
Long-term debt, net | 492,934,000 | 492,099,000 | ||||
Senior Notes | March 2023 Notes | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 350,000,000 | $ 350,000,000 | 0 | |||
Debt issuance costs, net | (5,769,000) | 0 | ||||
Long-term debt, net | 344,231,000 | 0 | ||||
Line of Credit | Secured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | [2] | 135,000,000 | 300,000,000 | |||
Debt issuance costs, net | [2] | 0 | 0 | |||
Long-term debt, net | [2] | $ 135,000,000 | $ 300,000,000 | |||
[1] | The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014. | |||||
[2] | Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the consolidated balance sheets. |
Employee compensation - Additio
Employee compensation - Additional Information (Details) | 3 Months Ended | 12 Months Ended | |||||
Mar. 31, 2016$ / shares | Mar. 31, 2015$ / shares | Dec. 31, 2015USD ($)shares | Dec. 31, 2014shares | Dec. 31, 2013USD ($)employee$ / sharesshares | Dec. 31, 2012shares | ||
Equity and stock-based compensation | |||||||
Incremental compensation cost due to plan modification | $ 4,700,000 | ||||||
Long Term Incentive Plan | |||||||
Equity and stock-based compensation | |||||||
Number of shares authorized | shares | 10,000,000 | ||||||
Restricted stock awards | |||||||
Equity and stock-based compensation | |||||||
Unrecognized equity and stock-based compensation expense | $ 21,600,000 | ||||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 8 months 25 days | ||||||
Granted (in shares) | shares | 1,902,000 | 1,234,000 | 1,469,000 | ||||
Options outstanding (in shares) | shares | 2,539,000 | 2,205,000 | 1,799,000 | 1,195,000 | |||
Restricted stock awards | Reorganization Grant Date | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 20.00% | ||||||
Restricted stock awards | Annual Vesting | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 20.00% | ||||||
Restricted stock awards | One Year From Grant Date | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 33.00% | ||||||
Restricted stock awards | Two Years from Grant Date | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 33.00% | ||||||
Restricted stock awards | Three Years from Grant Date | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 34.00% | ||||||
Restricted stock awards | Vesting in two years | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 50.00% | ||||||
Restricted stock awards | Vesting in three years | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 50.00% | ||||||
Restricted stock awards | Vesting one year from grant date | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 100.00% | ||||||
Restricted stock awards | Vesting three years from grant date | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 100.00% | ||||||
Restricted 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) | 2 years 4 months 7 days | ||||||
Intrinsic value, options exercisable | $ 0 | ||||||
Aggregate intrinsic value, vested and expected to vest | $ 0 | ||||||
Requisite service period (in years) | 4 years | ||||||
Unrecognized stock-based compensation expense | $ 7,000,000 | ||||||
Options, life of award (in years) | 10 years | ||||||
Post employment, vested awards expiration period | 1 year | ||||||
Post employment, vested awards expiration period | 90 days | ||||||
Performance unit awards | February 27 2014 and February 27, 2015 | February 2014 Performance Share Awards and February 2015 Performance Share Awards | |||||||
Equity and stock-based compensation | |||||||
Unrecognized equity and stock-based compensation expense | $ 9,900,000 | ||||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 10 months 8 days | ||||||
Requisite service period (in years) | 3 years | ||||||
Performance unit awards | February 27, 2015 | February 2015 Performance Share Awards | |||||||
Equity and stock-based compensation | |||||||
Granted (in shares) | shares | 602,501 | ||||||
Performance unit awards | February 27, 2014 | February 2014 Performance Share Awards | |||||||
Equity and stock-based compensation | |||||||
Options outstanding (in shares) | shares | 271,667 | ||||||
Performance Unit Awards | |||||||
Equity and stock-based compensation | |||||||
Cash paid for performance units (in dollars per share) | $ / shares | $ 100 | ||||||
Performance Unit Awards | Subsequent events | |||||||
Equity and stock-based compensation | |||||||
Cash paid for performance units (in dollars per share) | $ / shares | $ 143.75 | ||||||
Performance Unit Awards | February 15, 2013 and February 3, 2012 | |||||||
Equity and stock-based compensation | |||||||
Cash paid for performance units (in dollars per share) | $ / shares | $ 100 | ||||||
Performance Unit Awards | February 3, 2012 | |||||||
Equity and stock-based compensation | |||||||
Granted (in shares) | shares | [1] | 0 | |||||
Options outstanding (in shares) | shares | [1] | 0 | 0 | 27,000 | 47,000 | ||
Cash paid for performance units (in dollars per share) | $ / shares | $ 100 | ||||||
Fair value of awards | $ 3,800,000 | ||||||
Liability related to performance unit awards | $ 2,700,000 | ||||||
Performance Unit Awards | February 15, 2013 | |||||||
Equity and stock-based compensation | |||||||
Granted (in shares) | shares | [2] | 58,000 | |||||
Options outstanding (in shares) | shares | [2] | 0 | 44,000 | 44,000 | 0 | ||
Fair value of awards | $ 3,500,000 | $ 5,700,000 | |||||
Liability related to performance unit awards | $ 6,400,000 | ||||||
Performance Unit Awards | February 15, 2013 | Subsequent events | |||||||
Equity and stock-based compensation | |||||||
Cash paid for performance units (in dollars per share) | $ / shares | $ 143.75 | ||||||
Officer | |||||||
Equity and stock-based compensation | |||||||
Number of employees affected by plan modification | employee | 2 | ||||||
Employee | |||||||
Equity and stock-based compensation | |||||||
Number of employees affected by plan modification | employee | 20 | ||||||
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% | ||||||
[1] | The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015. | ||||||
[2] | The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016. |
Employee compensation - Restric
Employee compensation - Restricted stock awards activity (Details) - Restricted stock awards - $ / shares shares in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Restricted stock awards | ||||
Outstanding at the beginning of the period (in shares) | 2,205 | 1,799 | 1,195 | |
Granted (in shares) | 1,902 | 1,234 | 1,469 | |
Forfeited (in shares) | (553) | (148) | (229) | |
Vested (in shares) | [1] | (1,015) | (680) | (636) |
Outstanding at the end of the period (in shares) | 2,539 | 2,205 | 1,799 | |
Weighted-average grant date fair value (per award) | ||||
Outstanding at the beginning of the period (in dollars per share) | $ 22.63 | $ 19.17 | $ 15.06 | |
Fair value per performance share (in dollars per share) | 11.98 | 25.68 | 18.17 | |
Forfeited (in dollars per share) | 20.48 | 22.56 | 18.47 | |
Vested (in dollars per share) | [1] | 22.32 | 19.13 | 18.69 |
Outstanding at the end of the period (in dollars per share) | $ 15.26 | $ 22.63 | $ 19.17 | |
[1] | The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards. |
Employee compensation - Restr73
Employee compensation - Restricted stock option awards activity (Details) - Restricted stock option awards - $ / shares shares in Thousands | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Restricted stock option awards | |||||||
Outstanding at the beginning of the period (in shares) | 1,367 | 1,229 | 459 | ||||
Granted (in shares) | 632 | 336 | 1,019 | ||||
Exercised (in shares) | 0 | (95) | [1] | (104) | [1] | ||
Expired or canceled (in shares) | (82) | (30) | (12) | ||||
Forfeited (in shares) | (139) | (73) | (133) | ||||
Outstanding at the end of the period (in shares) | 1,778 | 1,367 | 1,229 | 459 | |||
Vested (in shares) | [2] | 545 | |||||
Vested, exercisable, and expected to vest at end of period (in shares) | [3] | 1,219 | |||||
Weighted-average price (per option) | |||||||
Outstanding at the end of the period (in dollars per share) | $ 20.76 | $ 19.32 | $ 24.11 | ||||
Granted (in dollars per share) | 11.93 | 25.60 | 17.34 | ||||
Exercised (in dollars per share) | 0 | 19.93 | [1] | 20.79 | [1] | ||
Expired or canceled (in dollars per share) | 19.92 | 21.15 | 24.11 | ||||
Forfeited (in dollars per share) | 18.17 | 19.68 | 19.88 | ||||
Outstanding at end of the period (in dollars per share) | 17.86 | $ 20.76 | $ 19.32 | $ 24.11 | |||
Vested and exercisable at end of period (in dollars per share) | [2] | 20.77 | |||||
Vested, exercisable, and expected to vest at end of period (in dollars per share) | [3] | $ 16.51 | |||||
Weighted-average remaining contractual term (years) | |||||||
Outstanding at the end of the period | 7 years 10 months 28 days | 8 years 2 months 1 day | 8 years 9 months 26 days | 10 years | |||
Vested and exercisable at the end of the period | [2] | 6 years 11 months 9 days | |||||
Vested, exercisable, and expected to vest at end of period | [3] | 8 years 4 months 2 days | |||||
[1] | The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards. | ||||||
[2] | The vested and exercisable options as of December 31, 2015 had no aggregate intrinsic value. | ||||||
[3] | The restricted stock options expected to vest as of December 31, 2015 had no aggregate intrinsic value. |
Employee compensation - Restr74
Employee compensation - Restricted stock option awards assumptions used to estimate the fair value (Details) - Restricted stock option awards | 12 Months Ended | |
Dec. 31, 2015$ / shares | ||
February 27, 2015 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate (as a percent) | 1.70% | [1] |
Expected option life (in years) | 6 years 3 months | [2] |
Expected volatility (as a percent) | 52.59% | [3] |
Fair value per option (in dollars per share) | $ 6.15 | |
February 27, 2014 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate (as a percent) | 1.88% | [1] |
Expected option life (in years) | 6 years 3 months | [2] |
Expected volatility (as a percent) | 53.21% | [3] |
Fair value per option (in dollars per share) | $ 13.41 | |
February 15, 2013 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate (as a percent) | 1.19% | [1] |
Expected option life (in years) | 6 years 3 months | [2] |
Expected volatility (as a percent) | 58.89% | [3] |
Fair value per option (in dollars per share) | $ 9.67 | |
February 3, 2012 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate (as a percent) | 1.14% | [1] |
Expected option life (in years) | 6 years 3 months | [2] |
Expected volatility (as a percent) | 59.98% | [3] |
Fair value per option (in dollars per share) | $ 13.52 | |
[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 option. | |
[2] | As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option 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 for the February 27, 2015 grant. The prior grants utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility. |
Employee compensation - Restr75
Employee compensation - Restricted stock option awards full years of continuous employment (Details) - Restricted stock option awards | 12 Months Ended |
Dec. 31, 2015 | |
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% |
Employee compensation - Perform
Employee compensation - Performance share awards assumptions used to estimate the fair value (Details) - Performance unit awards - $ / shares | Feb. 27, 2015 | Feb. 27, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate (as a percent) | 0.95% | 0.63% |
Dividend yield (as a percent) | 0.00% | 0.00% |
Expected volatility (as a percent) | 53.78% | 38.21% |
Share Price (in dollars per share) | $ 11.93 | $ 25.60 |
Fair value per performance share (in dollars per share) | $ 16.23 | $ 28.56 |
Employee compensation - Stock-b
Employee compensation - Stock-based compensation award expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Equity and stock-based compensation | |||
Total stock-based compensation, gross | $ 26,830 | $ 27,729 | $ 21,433 |
Less amounts capitalized in oil and natural gas properties | (2,321) | (4,650) | 0 |
Total stock-based compensation, net of amounts capitalized | 24,509 | 23,079 | 21,433 |
Restricted stock awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | 17,534 | 21,982 | 17,084 |
Restricted stock option awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | 4,074 | 3,639 | 4,349 |
Performance unit awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | $ 5,222 | $ 2,108 | $ 0 |
Employee compensation - Perfo78
Employee compensation - Performance unit awards outstanding (Details) - Performance Unit Awards - shares shares in Thousands | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
February 15, 2013 | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||||
Outstanding at the beginning of the period (in shares) | [1] | 44 | 44 | 0 | |
Granted (in shares) | [1] | 58 | |||
Forfeited (in shares) | [1] | (4) | |||
Vested (in shares) | [1] | (44) | 0 | (10) | [2] |
Outstanding at the end of the period (in shares) | [1] | 0 | 44 | 44 | |
February 3, 2012 | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||||
Outstanding at the beginning of the period (in shares) | [3] | 0 | 27 | 47 | |
Granted (in shares) | [3] | 0 | |||
Forfeited (in shares) | [3] | (9) | |||
Vested (in shares) | [3] | 0 | (27) | (11) | [2] |
Outstanding at the end of the period (in shares) | [3] | 0 | 0 | 27 | |
[1] | The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016. | ||||
[2] | During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit. | ||||
[3] | The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015. |
Employee compensation - Perfo79
Employee compensation - Performance unit award compensation expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | $ 24,509 | $ 23,079 | $ 21,433 |
Performance Unit Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | 4,081 | 601 | 4,733 |
February 15, 2013 | Performance Unit Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | 4,081 | 409 | 2,863 |
February 3, 2012 | Performance Unit Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | $ 0 | $ 192 | $ 1,870 |
Employee compensation - Cost re
Employee compensation - Cost recognized for the Company's defined contribution plan (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
401(k) Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Contributions | $ 1,847 | $ 2,202 | $ 1,886 |
Income taxes - Income tax benef
Income taxes - Income tax benefit (expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Current taxes: | ||||
Federal | $ 0 | $ 0 | $ 0 | |
State | 0 | 0 | 0 | |
Deferred taxes: | ||||
Federal | 152,590 | (147,445) | (64,034) | |
State | 24,355 | (16,841) | (10,473) | |
Income tax benefit (expense) | [1] | $ 176,945 | $ (164,286) | $ (74,507) |
[1] | Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% |
Income taxes - Comprehensive pr
Income taxes - Comprehensive provision for income taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Income Tax Disclosure [Abstract] | ||||
Continuing operations | [1] | $ 176,945 | $ (164,286) | $ (74,507) |
Discontinued operations | 0 | 0 | (781) | |
Comprehensive benefit (expense) for income taxes | $ 176,945 | $ (164,286) | $ (75,288) | |
[1] | Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% |
Income taxes - Income tax recon
Income taxes - Income tax reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Income Tax Disclosure [Abstract] | ||||
Income tax benefit (expense) computed by applying the statutory rate | $ 835,408 | $ (150,450) | $ (64,969) | |
State income tax, net of federal tax benefit and increase in valuation allowance | 13,975 | (11,099) | (7,532) | |
Non-deductible stock-based compensation | (256) | (509) | (1,070) | |
Stock-based compensation tax deficiency | (3,274) | (266) | (559) | |
Increase in deferred tax valuation allowance | (668,702) | (1,139) | (63) | |
Other items | (206) | (823) | (314) | |
Income tax benefit (expense) | [1] | $ 176,945 | $ (164,286) | $ (74,507) |
[1] | Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% |
Income taxes - Tax impact of sh
Income taxes - Tax impact of shortfalls (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Deferred income tax stock based compensation tax deficiency | $ 3,334 | $ 270 | $ 575 |
Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Deferred income tax stock based compensation tax deficiency | 3,334 | 112 | 425 |
Restricted stock option awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Deferred income tax stock based compensation tax deficiency | $ 0 | $ 158 | $ 150 |
Income taxes - Assets and liabi
Income taxes - Assets and liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Significant components of deferred tax assets | ||
Oil and natural gas properties, midstream service assets and other fixed assets | $ 306,997 | $ (424,712) |
Net operating loss carry-forward | 479,022 | 353,724 |
Derivatives | (98,675) | (121,365) |
Stock-based compensation | 11,597 | 10,718 |
Equity method investee | (31,711) | (2,331) |
Accrued bonus | 4,763 | 3,256 |
Capitalized interest | 2,525 | 3,049 |
Materials and supplies impairment | 1,647 | 642 |
Other | 1,173 | 1,373 |
Net deferred tax asset (liability) before valuation allowance | 677,338 | |
Net deferred tax asset (liability) before valuation allowance | (175,646) | |
Valuation allowance | (677,338) | (1,299) |
Net deferred tax asset (liability) | $ 0 | |
Net deferred tax asset (liability) | $ 176,945 |
Income taxes - Classification (
Income taxes - Classification (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Deferred tax asset | $ 0 | $ 0 | [1] | |
Current | 0 | 0 | [1] | |
Noncurrent | 0 | (176,945) | [1] | |
Net deferred tax asset (liability) | [1] | $ 0 | (176,945) | |
2014 | New Accounting Pronouncement, Early Adoption, Effect | ||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Deferred tax asset | [1] | 0 | ||
Current | [1] | (71,191) | ||
Noncurrent | [1] | (105,754) | ||
Net deferred tax asset (liability) | [1] | (176,945) | ||
Offset | New Accounting Pronouncement, Early Adoption, Effect | ||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Deferred tax asset | [1] | 0 | ||
Current | [1] | 71,191 | ||
Noncurrent | [1] | (71,191) | ||
Net deferred tax asset (liability) | [1] | $ 0 | ||
[1] | See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014. |
Income taxes - Operating losses
Income taxes - Operating losses (Details) - Federal $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 1,368,590 |
2,026 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 2,741 |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2026 |
2,027 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 38,651 |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2027 |
2,028 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 228,661 |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2028 |
2,029 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 101,932 |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2029 |
2,030 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 80,963 |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2030 |
Thereafter | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 915,642 |
Income taxes - Additional Infor
Income taxes - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Income Tax Examination [Line Items] | ||||
Federal statutory rate (as a percent) | 35.00% | 35.00% | 34.00% | |
Effective tax rate (as a percent) | 7.00% | 38.00% | 39.00% | |
Valuation allowance | $ 677,338 | $ 1,299 | ||
Income tax expense | [1] | (176,945) | $ 164,286 | $ 74,507 |
Additional paid-in-capital credits | 4,500 | |||
Valuation allowance | 676,000 | |||
Federal | ||||
Income Tax Examination [Line Items] | ||||
Net operating loss carry-forwards | 1,368,590 | |||
OKLAHOMA | State | ||||
Income Tax Examination [Line Items] | ||||
Net operating loss carry-forwards | $ 40,900 | |||
[1] | Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% |
Derivatives - Additional Inform
Derivatives - Additional Information (Details) - Derivatives not designated as hedges | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)contract | Dec. 31, 2014USD ($)contract | Dec. 31, 2013USD ($) | Sep. 30, 2013USD ($)derivative | ||
Derivative [Line Items] | ||||||
Number of instruments held | contract | 18 | |||||
Commodity derivatives | ||||||
Derivative [Line Items] | ||||||
Net proceeds | $ 76,700,000 | |||||
Cash settlements received for early terminations and modifications of derivatives, net | [1] | $ 0 | $ 76,660,000 | $ 6,008,000 | ||
Derivatives, deferred premium paid | $ 2,200,000 | |||||
Interest rate swap | ||||||
Derivative [Line Items] | ||||||
Number of interest rate derivatives | derivative | 1 | |||||
Interest rate (as a percent) | 1.11% | |||||
Interest rate cap | ||||||
Derivative [Line Items] | ||||||
Number of interest rate derivatives | derivative | 1 | |||||
Interest rate (as a percent) | 3.00% | |||||
Interest rate derivatives | ||||||
Derivative [Line Items] | ||||||
Number of instruments held | contract | 0 | 0 | ||||
Notional amount of derivatives | $ 100,000,000 | |||||
[1] | During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts. |
Derivatives - Anadarko Basin Sa
Derivatives - Anadarko Basin Sale (Details) - Andarko Basin - Derivatives not designated as hedges - Natural gas derivatives | Dec. 31, 2013MMBTU$ / MMBTU |
Swap August 2013 - December 2013 | Transferred On Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 2,386,800 |
Swap price (in dollars per unit) | 4.31 |
Swap January 2014 - December 2014 | Transferred On Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 3,978,500 |
Swap price (in dollars per unit) | 4.36 |
Collar September 2013 - December 2013 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 2,200,000 |
Floor price (in dollars per unit) | 4 |
Ceiling price (in dollars per unit) | 7.05 |
Put September 2013 - December 2013 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 2,200,000 |
Floor price (in dollars per unit) | 4 |
Ceiling price (in dollars per unit) | 0 |
Collar January 2014 - December 2014 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 3,480,000 |
Floor price (in dollars per unit) | 4 |
Ceiling price (in dollars per unit) | 7 |
Collar 2 January 2014 - December 2014 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 1,800,000 |
Floor price (in dollars per unit) | 4 |
Ceiling price (in dollars per unit) | 7.05 |
Collar 3 January 2014 - December 2014 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 1,680,000 |
Floor price (in dollars per unit) | 4 |
Ceiling price (in dollars per unit) | 7.05 |
Collar 4 January 2014 - December 2014 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 1,560,000 |
Floor price (in dollars per unit) | 3 |
Ceiling price (in dollars per unit) | 5.50 |
Collar January 2015 - December 2015 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 2,520,000 |
Floor price (in dollars per unit) | 3 |
Ceiling price (in dollars per unit) | 6 |
Collar 2 January 2015 - December 2015 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 2,400,000 |
Floor price (in dollars per unit) | 3 |
Ceiling price (in dollars per unit) | 6 |
Collar 3 January 2015 - December 2015 | Unwound on Divestiture | |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | MMBTU | 2,400,000 |
Floor price (in dollars per unit) | 3 |
Ceiling price (in dollars per unit) | 6 |
Derivatives - Gain (Loss) on De
Derivatives - Gain (Loss) on Derivatives (Details) - Derivatives not designated as hedges - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Commodity derivatives | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Cash settlements received for matured commodity derivatives | $ 255,281 | $ 28,241 | $ 4,046 | |
Early terminations and modification of commodity derivatives received | [1] | 0 | 76,660 | 6,008 |
Interest rate swap | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Cash settlements paid for matured interest rate swaps | 0 | 0 | (301) | |
Derivative | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Cash settlements received for derivatives, net | $ 255,281 | $ 104,901 | $ 9,753 | |
[1] | During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts. |
Derivatives - Open Positions (D
Derivatives - Open Positions (Details) - Derivatives not designated as hedges | 12 Months Ended | |
Dec. 31, 2015MMBTU$ / bbl$ / MMBTUbbl | ||
Short | Crude Oil | Options Held | ||
Derivative [Line Items] | ||
Notional amount | bbl | 1,296,000 | [1] |
Volume | 45 | [1] |
Short | Crude Oil | Swaps | ||
Derivative [Line Items] | ||
Notional amount | bbl | 1,573,800 | [1] |
Volume | 84.82 | [1] |
Short | Crude Oil | Collars | ||
Derivative [Line Items] | ||
Notional amount | bbl | 3,654,000 | [1] |
Short | Natural Gas | Collars | ||
Derivative [Line Items] | ||
Hedged volume (MMBtu) | MMBTU | 18,666,000 | [2] |
Short | Minimum | Crude Oil | ||
Derivative [Line Items] | ||
Notional amount | bbl | 6,523,800 | [1] |
Volume | 70.84 | [1] |
Short | Minimum | Crude Oil | Collars | ||
Derivative [Line Items] | ||
Volume | 73.99 | [1] |
Short | Minimum | Natural Gas | Collars | ||
Derivative [Line Items] | ||
Volume | $ / MMBTU | 3 | [2] |
Short | Maximum | Crude Oil | ||
Derivative [Line Items] | ||
Notional amount | bbl | 5,227,800 | [1] |
Volume | 88.18 | [1] |
Short | Maximum | Crude Oil | Collars | ||
Derivative [Line Items] | ||
Volume | 89.63 | [1] |
Short | Maximum | Natural Gas | Collars | ||
Derivative [Line Items] | ||
Volume | $ / MMBTU | 5.60 | [2] |
Long | Crude Oil | Options Held | ||
Derivative [Line Items] | ||
Notional amount | bbl | 0 | [1] |
Volume | 0 | [1] |
Long | Crude Oil | Swaps | ||
Derivative [Line Items] | ||
Notional amount | bbl | 0 | [1] |
Long | Crude Oil | Collars | ||
Derivative [Line Items] | ||
Notional amount | bbl | 2,628,000 | [1] |
Long | Natural Gas | Collars | ||
Derivative [Line Items] | ||
Hedged volume (MMBtu) | MMBTU | 5,475,000 | [2] |
Long | Minimum | Crude Oil | ||
Derivative [Line Items] | ||
Notional amount | bbl | 2,628,000 | [1] |
Volume | 77.22 | [1] |
Long | Minimum | Crude Oil | Collars | ||
Derivative [Line Items] | ||
Volume | 77.22 | [1] |
Long | Minimum | Natural Gas | Collars | ||
Derivative [Line Items] | ||
Volume | $ / MMBTU | 3 | [2] |
Long | Maximum | Crude Oil | ||
Derivative [Line Items] | ||
Notional amount | bbl | 2,628,000 | [1] |
Volume | 97.22 | [1] |
Long | Maximum | Crude Oil | Collars | ||
Derivative [Line Items] | ||
Volume | 97.22 | [1] |
Long | Maximum | Natural Gas | Collars | ||
Derivative [Line Items] | ||
Volume | $ / MMBTU | 4 | [2] |
[1] | Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX"). | |
[2] | Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period. |
Fair value measurements - Fair
Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Assets, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | $ 198,805 | $ 194,601 |
Net fair value presented on the consolidated balance sheets | 77,443 | 117,788 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 0 | (115) |
Recurring | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 312,274 | |
Recurring | Level 1 | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 0 | |
Recurring | Level 2 | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 321,559 | |
Recurring | Level 3 | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | (9,285) | |
Fair value | Recurring | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 312,274 | |
Crude Oil | Recurring | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 194,940 | 190,303 |
Net fair value presented on the consolidated balance sheets | 80,302 | 117,963 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Crude Oil | Recurring | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | (9,301) | (4,653) |
Net fair value presented on the consolidated balance sheets | (4,877) | (3,821) |
Liabilities, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 0 | (115) |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Natural Gas | Recurring | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 276,248 | |
Natural Gas | Recurring | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 13,166 | 9,647 |
Net fair value presented on the consolidated balance sheets | 2,459 | 3,646 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Natural Gas | Recurring | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 0 | (696) |
Net fair value presented on the consolidated balance sheets | (441) | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Natural Gas | Recurring | Level 1 | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 0 | |
Natural Gas | Recurring | Level 2 | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 290,867 | |
Natural Gas | Recurring | Level 3 | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | (14,619) | |
Natural Gas | Fair value | Recurring | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Net derivative position | 276,248 | |
Current: | Crude Oil | Recurring | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Current: | Crude Oil | Recurring | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | (9,301) | (4,653) |
Current: | Crude Oil | Recurring | Level 1 | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 1 | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 2 | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 194,940 | 190,303 |
Current: | Crude Oil | Recurring | Level 2 | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Fair value | Recurring | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 194,940 | 190,303 |
Current: | Crude Oil | Fair value | Recurring | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Current: | Natural Gas | Recurring | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | (696) |
Current: | Natural Gas | Recurring | Level 1 | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 1 | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 2 | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 13,166 | 9,647 |
Current: | Natural Gas | Recurring | Level 2 | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Fair value | Recurring | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 13,166 | 9,647 |
Current: | Natural Gas | Fair value | Recurring | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | (4,877) | (3,821) |
Noncurrent: | Crude Oil | Recurring | Level 1 | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 1 | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 80,302 | 117,963 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Fair value | Recurring | Oil Derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 80,302 | 117,963 |
Noncurrent: | Crude Oil | Fair value | Recurring | Oil Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Amounts offset | (441) | 0 |
Noncurrent: | Natural Gas | Recurring | Level 1 | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 1 | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 2,459 | 3,646 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Fair value | Recurring | Natural gas derivatives | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 2,459 | 3,646 |
Noncurrent: | Natural Gas | Fair value | Recurring | Natural Gas Deferred Premiums | ||
Assets, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Current: | Crude Oil | Recurring | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 9,301 | 4,653 |
Current: | Crude Oil | Recurring | Level 1 | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 1 | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 2 | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 2 | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | (9,301) | (4,768) |
Current: | Crude Oil | Fair value | Recurring | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Fair value | Recurring | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | (9,301) | (4,768) |
Current: | Natural Gas | Recurring | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Current: | Natural Gas | Recurring | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 696 |
Current: | Natural Gas | Recurring | Level 1 | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 1 | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 2 | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 2 | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | (696) |
Current: | Natural Gas | Fair value | Recurring | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Fair value | Recurring | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | (696) |
Noncurrent: | Crude Oil | Recurring | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 4,877 | 3,821 |
Noncurrent: | Crude Oil | Recurring | Level 1 | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 1 | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | (4,877) | (3,821) |
Noncurrent: | Crude Oil | Fair value | Recurring | Oil Derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Fair value | Recurring | Oil Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | (4,877) | (3,821) |
Noncurrent: | Natural Gas | Recurring | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Amounts offset | 441 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 1 | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 1 | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | (441) | 0 |
Noncurrent: | Natural Gas | Fair value | Recurring | Natural gas derivatives | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Fair value | Recurring | Natural Gas Deferred Premiums | ||
Liabilities, Fair Value Disclosure [Abstract] | ||
Total gross fair value | $ (441) | $ 0 |
Fair value measurements - Narra
Fair value measurements - Narrative (Details) - Deferred Premiums - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2013 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivatives, deferred premium paid | $ 2.2 | |
Minimum | Recurring | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Discount rate used (as a percent) | 1.69% | |
Maximum | Recurring | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Discount rate used (as a percent) | 3.56% |
Fair value measurements - Actua
Fair value measurements - Actual cash payments (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Fair Value Disclosures [Abstract] | |
2,016 | $ 8,629 |
2,017 | 5,796 |
2,018 | 426 |
Total | $ 14,851 |
Fair value measurements - Roll
Fair value measurements - Roll forward (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Changes in assets classified as Level 3 measurements | ||||
Change in net present value of deferred premiums for derivatives | $ 203 | $ 220 | $ 462 | |
Deferred Premiums | ||||
Changes in assets classified as Level 3 measurements | ||||
Balance of Level 3 at beginning of period | (9,285) | (12,684) | (24,709) | |
Change in net present value of deferred premiums for derivatives | (203) | (220) | (462) | |
Total purchases and settlements: | ||||
Purchases | (10,298) | (3,800) | 0 | |
Settlements | [1] | 5,167 | 7,419 | 12,487 |
Balance of Level 3 at end of period | $ (14,619) | $ (9,285) | $ (12,684) | |
[1] | The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive. |
Net income (loss) per share - N
Net income (loss) per share - Narrative (Details) - Restricted stock option awards - $ / shares | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
February 2014 Awards | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Antidilutive securities excluded from computation of earnings per share (in shares) | 336,140 | 336,140 |
Options outstanding weighted average exercise price (in dollars per shares) | $ 25.60 | $ 25.60 |
February 2012 Awards | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Antidilutive securities excluded from computation of earnings per share (in shares) | 280,626 | 280,626 |
Options outstanding weighted average exercise price (in dollars per shares) | $ 24.11 | $ 24.11 |
February 2013 Awards | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Antidilutive securities excluded from computation of earnings per share (in shares) | 750,338 | 750,338 |
Options outstanding weighted average exercise price (in dollars per shares) | $ 17.34 | $ 17.34 |
Net income (loss) per share - C
Net income (loss) per share - Calculation of net income per share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Net income (numerator): | ||||||||||||
Income (loss) from continuing operations—basic and diluted | $ (2,209,936) | $ 265,573 | $ 116,577 | |||||||||
Income from discontinued operations, net of tax—basic and diluted | 0 | 0 | 1,423 | |||||||||
Net loss | $ (964,647) | $ (847,783) | $ (397,034) | $ (472) | $ 201,278 | $ 83,407 | $ (18,899) | $ (213) | $ (2,209,936) | $ 265,573 | $ 118,000 | |
Weighted-average common shares outstanding (denominator): | ||||||||||||
Weighted-average common shares outstanding—basic (in shares) | [1] | 199,158 | 141,312 | 132,490 | ||||||||
Weighted-average common shares outstanding—diluted (in shares) | 199,158 | 143,554 | 134,378 | |||||||||
Net income (loss) per share: | ||||||||||||
Income (loss) from continuing operations - basic (in dollars per share) | $ (11.10) | $ 1.88 | $ 0.88 | |||||||||
Income from discontinued operations, net of tax - basic (in dollars per share) | 0 | 0 | 0.01 | |||||||||
Net income (loss) per share (in dollars per share) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ 1.42 | $ 0.59 | $ (0.13) | $ 0 | (11.10) | 1.88 | 0.89 | |
Income (loss) from continuing operations - diluted | (11.10) | 1.85 | 0.87 | |||||||||
Income from discontinued operations, net of tax - diluted | 0 | 0 | 0.01 | |||||||||
Net income (loss) per share (in dollars per share) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ 1.40 | $ 0.58 | $ (0.13) | $ 0 | $ (11.10) | $ 1.85 | $ 0.88 | |
Restricted stock awards | ||||||||||||
Weighted-average common shares outstanding (denominator): | ||||||||||||
Non-vested restricted stock awards (in shares) | 0 | 2,242 | 1,888 | |||||||||
[1] | For the year ended December 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders was computed taking into account the March 2015 Equity Offering. For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders was computed taking into account the August 2013 Equity Offering. |
Credit risk (Details)
Credit risk (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)customerpartner | Dec. 31, 2014customerpartner | Dec. 31, 2013customer | |
Credit risk | |||
Cash balances exceeded by balance insured by FDIC | $ | $ 51.3 | ||
Customers | Total revenues | Customer one and two | |||
Credit risk | |||
Number of major customers | 2 | 2 | |
Customers | Total revenues | Customer one | |||
Credit risk | |||
Concentration risk (as a percent) | 37.50% | 36.00% | 28.30% |
Customers | Total revenues | Customer two | |||
Credit risk | |||
Concentration risk (as a percent) | 20.30% | 13.70% | 11.70% |
Customers | Total revenues | Customer three | |||
Credit risk | |||
Concentration risk (as a percent) | 11.70% | ||
Customers | Total revenues | Customer one, two and three | |||
Credit risk | |||
Number of major customers | 3 | ||
Customers | Trade Accounts Receivable | Customer three, four and five | |||
Credit risk | |||
Number of major customers | 3 | ||
Customers | Purchased Oil Sales | |||
Credit risk | |||
Number of major customers | 1 | 1 | |
Concentration risk (as a percent) | 100.00% | 100.00% | |
Customers | Purchased Oil and Other Products Sales | |||
Credit risk | |||
Concentration risk (as a percent) | 99.60% | 97.30% | |
Credit Concentration Risk | Total revenues | Customer one | |||
Credit risk | |||
Concentration risk (as a percent) | 16.40% | ||
Credit Concentration Risk | Total revenues | Customer two | |||
Credit risk | |||
Concentration risk (as a percent) | 22.50% | ||
Credit Concentration Risk | Trade Accounts Receivable | Customer one and two | |||
Credit risk | |||
Number of additional customers | 2 | ||
Credit Concentration Risk | Trade Accounts Receivable | Customer one | |||
Credit risk | |||
Number of major customers | 1 | 1 | |
Concentration risk (as a percent) | 35.30% | 36.00% | |
Credit Concentration Risk | Trade Accounts Receivable | Customer two | |||
Credit risk | |||
Number of major customers | 1 | 1 | |
Concentration risk (as a percent) | 23.70% | 15.70% | |
Credit Concentration Risk | Trade Accounts Receivable | Customer three and four | |||
Credit risk | |||
Number of additional customers | 2 | ||
Credit Concentration Risk | Trade Accounts Receivable | Customer three | |||
Credit risk | |||
Concentration risk (as a percent) | 18.50% | 13.50% | |
Credit Concentration Risk | Trade Accounts Receivable | Customer four | |||
Credit risk | |||
Concentration risk (as a percent) | 10.70% | 12.50% | |
Credit Concentration Risk | Trade Accounts Receivable | Customer five | |||
Credit risk | |||
Concentration risk (as a percent) | 11.60% | ||
Partner Two | Credit Concentration Risk | Joint operations accounts receivable | |||
Credit risk | |||
Concentration risk (as a percent) | 17.10% | 13.20% | |
Partner One | Credit Concentration Risk | Joint operations accounts receivable | |||
Credit risk | |||
Concentration risk (as a percent) | 18.90% | 20.50% | |
Partner one and two | Credit Concentration Risk | Joint operations accounts receivable | |||
Credit risk | |||
Number of joint interest partners | partner | 2 | 2 |
Commitments and contingencie100
Commitments and contingencies (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Lease commitments | |||
2,016 | $ 3,087 | ||
2,017 | 3,244 | ||
2,018 | 3,160 | ||
2,019 | 2,408 | ||
2,020 | 1,294 | ||
Thereafter | 8,217 | ||
Total | 21,410 | ||
Rent expense | |||
Rent expense | 2,880 | $ 3,042 | $ 1,923 |
Drilling rig fees | 0 | $ 527 | $ 0 |
Firm Sale And Transportation Commitments | |||
Rent expense | |||
Future commitments | 425,700 | ||
Drilling Contracts | |||
Rent expense | |||
Future commitments | $ 10,300 |
Restructuring (Details)
Restructuring (Details) $ in Thousands | Jan. 20, 2015employee | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Restructuring Cost and Reserve [Line Items] | ||||
Restructuring expenses | $ | $ 6,042 | $ 0 | $ 0 | |
Reduction in Force | ||||
Restructuring Cost and Reserve [Line Items] | ||||
Restructuring expenses | $ | $ 6,000 | |||
Reduction in Force | Facility Closing | ||||
Restructuring Cost and Reserve [Line Items] | ||||
Employee positions eliminated | employee | 75 | |||
Reduction in Force | Contract Termination | ||||
Restructuring Cost and Reserve [Line Items] | ||||
Employee positions eliminated | employee | 24 |
Recently issued accounting s102
Recently issued accounting standards - Income taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | |
New Accounting Pronouncement, Early Adoption [Line Items] | ||||||
Total assets | $ 1,813,287 | $ 3,910,701 | ||||
Decrease in deferred income taxes | 0 | 0 | [1] | |||
Total current liabilities | 216,815 | 353,834 | ||||
Increase in deferred income taxes | 0 | 176,945 | [1] | |||
Total liabilities | $ 1,681,840 | 2,347,500 | ||||
Topic 740, Income Taxes | New Accounting Pronouncement, Early Adoption, Effect | ||||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||||
Decrease in deferred income taxes | $ (68,069) | $ (45,089) | $ 0 | 0 | ||
Total assets | (68,069) | (45,089) | 0 | 0 | ||
Decrease in deferred income taxes | (68,069) | (45,089) | (73,753) | (71,191) | ||
Total current liabilities | (68,069) | (45,089) | (73,753) | (71,191) | ||
Increase in deferred income taxes | 0 | 0 | 73,753 | 71,191 | ||
Total liabilities | $ (68,069) | $ (45,089) | $ 0 | $ 0 | ||
[1] | See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014. |
Recently issued accounting s103
Recently issued accounting standards - Debt issuance costs (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 |
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Debt issuance costs | $ 18,774 | $ 21,848 | ||
Subtopic 835-30, Interest-Imputation of Interest | New Accounting Pronouncement, Early Adoption, Effect | Decrease in debt issuance costs, net | ||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Debt issuance costs | $ (26,158) | $ (33,513) | (28,463) | |
Subtopic 835-30, Interest-Imputation of Interest | New Accounting Pronouncement, Early Adoption, Effect | Increase in other assets, net | ||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Debt issuance costs | 6,068 | 6,873 | 6,615 | |
Subtopic 835-30, Interest-Imputation of Interest | New Accounting Pronouncement, Early Adoption, Effect | Decrease in total assets | ||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Debt issuance costs | (20,090) | (26,640) | (21,848) | |
Subtopic 835-30, Interest-Imputation of Interest | New Accounting Pronouncement, Early Adoption, Effect | Decrease in long-term debt, net | ||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Debt issuance costs | (20,090) | (26,640) | (21,848) | |
Subtopic 835-30, Interest-Imputation of Interest | New Accounting Pronouncement, Early Adoption, Effect | Decrease in total liabilities | ||||
New Accounting Pronouncement, Early Adoption [Line Items] | ||||
Debt issuance costs | $ (20,090) | $ (26,640) | $ (21,848) |
Variable interest entity (Detai
Variable interest entity (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Equity Method Investments [Line Items] | |||
Investment in equity method investee | $ 99,855 | $ 55,164 | $ 3,287 |
Minimum volume commitments | 5,235 | 2,552 | $ 891 |
Variable Interest Entity, Not Primary Beneficiary | Medallion Gathering And Processing LLC | |||
Schedule of Equity Method Investments [Line Items] | |||
Investment in equity method investee | $ 99,900 | $ 55,200 | |
Ownership percentage | 49.00% | ||
Ownership percentage held by investment partner | 51.00% | ||
Percentage required for key decisions | 75.00% | ||
Minimum volume commitments | $ 3,000 |
Variable Interest entity - Summ
Variable Interest entity - Summarized financial information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Statement of Operations | |||||
Total revenues | $ 34,288 | [1] | $ 4,623 | $ 892 | |
Gross profit(1) | [2] | 29,826 | [1] | 4,623 | 892 |
Income (loss) from continuing operations | 13,821 | [1] | (333) | 54 | |
Net income (loss)(2) | [3] | 13,821 | [1] | (333) | $ 54 |
Balance Sheet | |||||
Current assets | 78,411 | 25,777 | |||
Noncurrent assets | 329,956 | 112,753 | |||
Total assets | 408,367 | [4] | 138,530 | ||
Current liabilities | 15,461 | 19,522 | |||
Noncurrent liabilities | 0 | 0 | |||
Total liabilities | $ 15,461 | [4] | $ 19,522 | ||
[1] | Medallion's consolidated statement of operations for the year ended December 31, 2015 was unaudited as of February 17, 2016. | ||||
[2] | Medallion's pipeline did not become operational until 2015, accordingly no costs of good sold were recorded for the years ended December 31, 2014 and 2013. | ||||
[3] | As Medallion's financial statements are unaudited at the time of filing the Company's Annual Report on Form 10-K, the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations for the years ended December 31, 2015 and 2014 include immaterial prior period Medallion audit adjustments. | ||||
[4] | Medallion's consolidated balance sheet as of December 31, 2015 was unaudited as of February 17, 2016. |
Related Parties - Consolidated
Related Parties - Consolidated statements of operations related to Medallion (Details) - Medallion Gathering And Processing LLC - Equity Method Investee - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Midstream service revenues | |||
Related Party Transaction [Line Items] | |||
Related party revenues | $ 487 | $ 0 | $ 0 |
Minimum volume commitments | |||
Related Party Transaction [Line Items] | |||
Related party revenues | 5,235 | 2,552 | 891 |
Interest and other income | |||
Related Party Transaction [Line Items] | |||
Related party revenues | $ 158 | $ 0 | $ 0 |
Related Parties - Consolidat107
Related Parties - Consolidated balance sheets related to Medallion (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Medallion Gathering And Processing LLC | |||
Related Party Transaction [Line Items] | |||
Accounts receivable, net | $ 1,163 | $ 0 | |
Medallion Gathering And Processing LLC | Equity Method Investee | Other assets, net(1) | |||
Related Party Transaction [Line Items] | |||
Related party assets and liabilities | [1] | (1,025) | (1,110) |
Medallion Gathering And Processing LLC | Equity Method Investee | Other current liabilities(2) | |||
Related Party Transaction [Line Items] | |||
Related party assets and liabilities | [2] | $ 27,583 | $ 3,443 |
[1] | Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline. | ||
[2] | Amounts included in "Other current liabilities" above for the year ended December 31, 2015 represents LMS's capital contribution payable to Medallion, of which a portion was paid subsequent to December 31, 2015. "Other current liabilities" above for the year ended December 31, 2014 represents LMS's minimum volume commitment payable to Medallion. See Note 15 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion. |
Related Parties - Net oil, NGL
Related Parties - Net oil, NGL and natural gas sales (Details) - Targa Resources Corp. - Affiliated Entity - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil, NGL and natural gas sales | |||
Related Party Transaction [Line Items] | |||
Related party revenues | $ 99,992 | $ 96,100 | $ 74,245 |
Midstream service revenues | |||
Related Party Transaction [Line Items] | |||
Related party revenues | $ 590 | $ 0 | $ 0 |
Related Parties - Amounts inclu
Related Parties - Amounts included in oil, NGL and natural gas sales receivable from Targa (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Targa Resources Corp. | Affiliated Entity | ||
Related Party Transaction [Line Items] | ||
Accounts receivable, net | $ 6,097 | $ 12,869 |
Related Parties - Lease operati
Related Parties - Lease operating expenses related to Archrock Partners (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Archrock Partners, L.P. | Affiliated Entity | Lease Operating Expenses | |||
Related Party Transaction [Line Items] | |||
Lease operating expenses | $ 1,477 | $ 975 | $ 51 |
Related Parties - Capitalized o
Related Parties - Capitalized oil and natural gas properties related to Archrock Partners (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | $ 588,017 | $ 1,251,757 | $ 702,349 |
Midstream service assets | 35,459 | 60,548 | 24,409 |
Archrock Partners, L.P. | Affiliated Entity | Oil and natural gas properties | |||
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | 0 | 57 | 0 |
Archrock Partners, L.P. | Affiliated Entity | Midstream service assets | |||
Related Party Transaction [Line Items] | |||
Midstream service assets | $ 64 | $ 833 | $ 0 |
Related Parties - Accounts paya
Related Parties - Accounts payable from Archrock Partners (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Archrock Partners, L.P. | Affiliated Entity | ||
Related Party Transaction [Line Items] | ||
Accounts payable | $ 13 | $ 0 |
Related Parties - Capitalize113
Related Parties - Capitalized oil and natural gas properties related to H&P (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | $ 588,017 | $ 1,251,757 | $ 702,349 |
Archrock Partners, L.P. | Affiliated Entity | Oil and natural gas properties | |||
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | $ 2,434 | $ 9,518 | $ 9,943 |
Segments - Selected financial i
Segments - Selected financial information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | $ 431,734 | $ 737,203 | $ 664,844 | ||||||||||||
Midstream service revenues | 6,548 | 2,245 | 413 | ||||||||||||
Sales of purchased oil | 168,358 | 54,437 | 0 | ||||||||||||
Total operating revenues | $ 123,275 | $ 150,340 | $ 182,331 | $ 150,694 | $ 237,290 | $ 200,241 | $ 183,044 | $ 173,310 | 606,640 | 793,885 | 665,257 | ||||
Lease operating expenses, including production tax | 141,233 | 146,815 | 121,532 | ||||||||||||
Midstream service expenses, including minimum volume commitments | 11,081 | 7,981 | 4,259 | ||||||||||||
Costs of purchased oil | 174,338 | 53,967 | 0 | ||||||||||||
General and administrative | [1] | 90,425 | 106,044 | 89,696 | |||||||||||
Depletion, depreciation and amortization | [2] | 277,724 | 246,474 | 233,944 | |||||||||||
Impairment expense | 2,374,888 | 3,904 | 0 | ||||||||||||
Other operating costs and expenses | [3] | 8,465 | 2,314 | 1,475 | |||||||||||
Operating income (loss) | (1,015,677) | $ (927,859) | $ (501,480) | $ (26,498) | 32,623 | $ 69,164 | $ 64,561 | $ 60,038 | (2,471,514) | 226,386 | 214,351 | ||||
Income (loss) from equity method investee | 6,799 | (192) | 29 | ||||||||||||
Interest expense | [4] | (103,219) | (121,173) | (100,327) | |||||||||||
Loss on early redemption of debt | (31,537) | [5] | 0 | 0 | |||||||||||
Total income tax benefit (expense) | [6] | 176,945 | (164,286) | (74,507) | |||||||||||
Capital expenditures | (632,601) | (1,339,749) | [7] | (743,015) | [7] | ||||||||||
Gross property and equipment | [8] | 5,645,976 | 5,021,017 | 5,645,976 | 5,021,017 | 3,575,112 | |||||||||
Operating Segments | Exploration and production | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | 432,711 | 738,455 | 664,844 | ||||||||||||
Midstream service revenues | 0 | 0 | 328 | ||||||||||||
Sales of purchased oil | 0 | 0 | |||||||||||||
Total operating revenues | 432,711 | 738,455 | 665,172 | ||||||||||||
Lease operating expenses, including production tax | 151,918 | 153,427 | 130,152 | ||||||||||||
Midstream service expenses, including minimum volume commitments | 4,399 | 0 | 2,807 | ||||||||||||
Costs of purchased oil | 0 | 0 | |||||||||||||
General and administrative | [1] | 82,251 | 99,075 | 86,951 | |||||||||||
Depletion, depreciation and amortization | [2] | 269,631 | 241,834 | 231,703 | |||||||||||
Impairment expense | 2,372,296 | 1,802 | |||||||||||||
Other operating costs and expenses | [3] | 8,123 | 2,248 | 1,475 | |||||||||||
Operating income (loss) | (2,455,907) | 240,069 | 212,084 | ||||||||||||
Income (loss) from equity method investee | 0 | 0 | 0 | ||||||||||||
Interest expense | [4] | (98,040) | (117,560) | (98,680) | |||||||||||
Loss on early redemption of debt | [5] | (30,056) | |||||||||||||
Total income tax benefit (expense) | [6] | 171,952 | (170,551) | (73,476) | |||||||||||
Capital expenditures | (597,086) | (1,279,142) | [7] | (718,606) | [7] | ||||||||||
Gross property and equipment | [8] | 5,302,716 | 4,841,895 | 5,302,716 | 4,841,895 | 3,516,406 | |||||||||
Operating Segments | Midstream and marketing | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | 1,692 | 1,660 | 0 | ||||||||||||
Midstream service revenues | 27,965 | 7,838 | 8,824 | ||||||||||||
Sales of purchased oil | 168,358 | 54,437 | |||||||||||||
Total operating revenues | 198,015 | 63,935 | 8,824 | ||||||||||||
Lease operating expenses, including production tax | 0 | 0 | 0 | ||||||||||||
Midstream service expenses, including minimum volume commitments | 18,393 | 9,641 | 1,571 | ||||||||||||
Costs of purchased oil | 174,338 | 53,967 | |||||||||||||
General and administrative | [1] | 8,174 | 6,969 | 2,745 | |||||||||||
Depletion, depreciation and amortization | [2] | 8,093 | 4,640 | 2,241 | |||||||||||
Impairment expense | 2,592 | 2,102 | |||||||||||||
Other operating costs and expenses | [3] | 342 | 66 | 0 | |||||||||||
Operating income (loss) | (13,917) | (13,450) | 2,267 | ||||||||||||
Income (loss) from equity method investee | 6,799 | (192) | 29 | ||||||||||||
Interest expense | [4] | (5,179) | (3,613) | (1,647) | |||||||||||
Loss on early redemption of debt | [5] | (1,481) | |||||||||||||
Total income tax benefit (expense) | [6] | 4,993 | 6,265 | (1,031) | |||||||||||
Capital expenditures | (35,515) | (60,607) | [7] | (24,409) | [7] | ||||||||||
Gross property and equipment | [8] | 345,183 | 179,355 | 345,183 | 179,355 | 58,706 | |||||||||
Eliminations | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | (2,669) | (2,912) | 0 | ||||||||||||
Midstream service revenues | (21,417) | (5,593) | (8,739) | ||||||||||||
Sales of purchased oil | 0 | 0 | |||||||||||||
Total operating revenues | (24,086) | (8,505) | (8,739) | ||||||||||||
Lease operating expenses, including production tax | (10,685) | (6,612) | (8,620) | ||||||||||||
Midstream service expenses, including minimum volume commitments | (11,711) | (1,660) | (119) | ||||||||||||
Costs of purchased oil | 0 | 0 | |||||||||||||
General and administrative | [1] | 0 | 0 | 0 | |||||||||||
Depletion, depreciation and amortization | [2] | 0 | 0 | 0 | |||||||||||
Impairment expense | 0 | 0 | |||||||||||||
Other operating costs and expenses | [3] | 0 | 0 | 0 | |||||||||||
Operating income (loss) | (1,690) | (233) | 0 | ||||||||||||
Income (loss) from equity method investee | 0 | 0 | 0 | ||||||||||||
Interest expense | [4] | 0 | 0 | 0 | |||||||||||
Loss on early redemption of debt | [5] | 0 | |||||||||||||
Total income tax benefit (expense) | [6] | 0 | 0 | 0 | |||||||||||
Capital expenditures | 0 | 0 | [7] | 0 | [7] | ||||||||||
Gross property and equipment | [8] | $ (1,923) | $ (233) | $ (1,923) | $ (233) | $ 0 | |||||||||
[1] | General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013. | ||||||||||||||
[2] | Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. | ||||||||||||||
[3] | Other operating costs and expenses include restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015, accretion of asset retirement obligations and drilling rig fees for the year ended December 31, 2014 and accretion of asset retirement obligations for the year ended December 31, 2013. These expenses are based on actual costs and are not allocated. | ||||||||||||||
[4] | Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013. | ||||||||||||||
[5] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015. | ||||||||||||||
[6] | Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% | ||||||||||||||
[7] | Capital expenditures exclude acquisition of oil and natural gas properties and acquisition of mineral interests for the year ended December 31, 2014 and excludes acquisitions of oil and natural gas properties for the year ended December 31, 2013. | ||||||||||||||
[8] | Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $192.5 million, $58.3 million and $5.9 million as of December 31, 2015, 2014 and 2013, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2015, 2014 and 2013. |
Segments - Additional informati
Segments - Additional information (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)segment | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Segment Reporting Information [Line Items] | |||
Number of segments | segment | 2 | ||
Investment in equity method investee | $ 192,524 | $ 58,288 | |
Midstream and marketing | |||
Segment Reporting Information [Line Items] | |||
Investment in equity method investee | $ 192,500 | $ 58,300 | $ 5,900 |
Operating Segments | Midstream Segment | |||
Segment Reporting Information [Line Items] | |||
Effective tax rate (as a percent) | 36.00% |
Subsidiary guarantors - Condens
Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Subsidiary guarantees | ||||
Accounts receivable, net | $ 87,699 | $ 126,929 | ||
Other current assets | 244,533 | 238,324 | ||
Total oil and natural gas properties, net | 1,024,992 | 3,203,275 | ||
Total midstream service assets, net | 131,725 | 108,462 | ||
Other fixed assets, net | 43,538 | 42,345 | ||
Investment in subsidiaries and equity method investee | 192,524 | 58,288 | ||
Total other long-term assets | 88,276 | 133,078 | ||
Total assets | 1,813,287 | 3,910,701 | ||
Accounts payable | 14,181 | 39,008 | ||
Other current liabilities | 202,634 | 314,826 | ||
Long-term debt, net | 1,416,226 | 1,779,447 | ||
Other long-term liabilities | 48,799 | 214,219 | ||
Stockholders' equity | 131,447 | 1,563,201 | $ 1,272,256 | $ 831,723 |
Total liabilities and stockholders' equity | 1,813,287 | 3,910,701 | ||
Reportable Legal Entities | Laredo | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 74,613 | 107,860 | ||
Other current assets | 244,477 | 238,300 | ||
Total oil and natural gas properties, net | 1,017,565 | 3,196,231 | ||
Total midstream service assets, net | 0 | 0 | ||
Other fixed assets, net | 43,210 | 42,046 | ||
Investment in subsidiaries and equity method investee | 301,891 | 163,349 | ||
Total other long-term assets | 84,360 | 128,582 | ||
Total assets | 1,766,116 | 3,876,368 | ||
Accounts payable | 12,203 | 38,453 | ||
Other current liabilities | 158,283 | 283,026 | ||
Long-term debt, net | 1,416,226 | 1,779,447 | ||
Other long-term liabilities | 46,034 | 212,008 | ||
Stockholders' equity | 133,370 | 1,563,434 | ||
Total liabilities and stockholders' equity | 1,766,116 | 3,876,368 | ||
Reportable Legal Entities | Subsidiary Guarantors | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 13,086 | 19,069 | ||
Other current assets | 56 | 24 | ||
Total oil and natural gas properties, net | 9,350 | 7,277 | ||
Total midstream service assets, net | 131,725 | 108,462 | ||
Other fixed assets, net | 328 | 299 | ||
Investment in subsidiaries and equity method investee | 192,524 | 58,288 | ||
Total other long-term assets | 3,916 | 4,496 | ||
Total assets | 350,985 | 197,915 | ||
Accounts payable | 1,978 | 555 | ||
Other current liabilities | 44,351 | 31,800 | ||
Long-term debt, net | 0 | 0 | ||
Other long-term liabilities | 2,765 | 2,211 | ||
Stockholders' equity | 301,891 | 163,349 | ||
Total liabilities and stockholders' equity | 350,985 | 197,915 | ||
Intercompany eliminations | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 0 | 0 | ||
Other current assets | 0 | 0 | ||
Total oil and natural gas properties, net | (1,923) | (233) | ||
Total midstream service assets, net | 0 | 0 | ||
Other fixed assets, net | 0 | 0 | ||
Investment in subsidiaries and equity method investee | (301,891) | (163,349) | ||
Total other long-term assets | 0 | 0 | ||
Total assets | (303,814) | (163,582) | ||
Accounts payable | 0 | 0 | ||
Other current liabilities | 0 | 0 | ||
Long-term debt, net | 0 | 0 | ||
Other long-term liabilities | 0 | 0 | ||
Stockholders' equity | (303,814) | (163,582) | ||
Total liabilities and stockholders' equity | $ (303,814) | $ (163,582) |
Subsidiary guarantors - Cond117
Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Subsidiary guarantees | ||||||||||||
Total operating revenues | $ 123,275 | $ 150,340 | $ 182,331 | $ 150,694 | $ 237,290 | $ 200,241 | $ 183,044 | $ 173,310 | $ 606,640 | $ 793,885 | $ 665,257 | |
Total operating costs and expenses | 3,078,154 | 567,499 | 450,906 | |||||||||
Income (loss) from operations | (1,015,677) | (927,859) | (501,480) | (26,498) | 32,623 | 69,164 | 64,561 | 60,038 | (2,471,514) | 226,386 | 214,351 | |
Interest expense and other, net | (102,793) | (120,879) | (100,164) | |||||||||
Other non-operating income (expense) | 187,426 | 324,352 | 76,897 | |||||||||
Income (loss) from continuing operations before income taxes | (2,386,881) | 429,859 | 191,084 | |||||||||
Total income tax benefit (expense) | [1] | 176,945 | (164,286) | (74,507) | ||||||||
Income (loss) from continuing operations—basic and diluted | (2,209,936) | 265,573 | 116,577 | |||||||||
Income from discontinued operations, net of tax | 0 | 0 | 1,423 | |||||||||
Net income (loss) | $ (964,647) | $ (847,783) | $ (397,034) | $ (472) | $ 201,278 | $ 83,407 | $ (18,899) | $ (213) | (2,209,936) | 265,573 | 118,000 | |
Reportable Legal Entities | Laredo | ||||||||||||
Subsidiary guarantees | ||||||||||||
Total operating revenues | 432,478 | 738,446 | 665,172 | |||||||||
Total operating costs and expenses | 2,897,272 | 505,455 | 455,972 | |||||||||
Income (loss) from operations | (2,464,794) | 232,991 | 209,200 | |||||||||
Interest expense and other, net | (102,793) | (120,879) | (100,164) | |||||||||
Other non-operating income (expense) | 182,396 | 317,980 | 84,861 | |||||||||
Income (loss) from continuing operations before income taxes | (2,385,191) | 430,092 | 193,897 | |||||||||
Total income tax benefit (expense) | 176,945 | (164,286) | (74,507) | |||||||||
Income (loss) from continuing operations—basic and diluted | (2,208,246) | 265,806 | 119,390 | |||||||||
Income from discontinued operations, net of tax | (1,390) | |||||||||||
Net income (loss) | (2,208,246) | 265,806 | 118,000 | |||||||||
Reportable Legal Entities | Subsidiary Guarantors | ||||||||||||
Subsidiary guarantees | ||||||||||||
Total operating revenues | 198,248 | 63,944 | 8,824 | |||||||||
Total operating costs and expenses | 203,278 | 70,316 | 3,673 | |||||||||
Income (loss) from operations | (5,030) | (6,372) | 5,151 | |||||||||
Interest expense and other, net | 0 | 0 | 0 | |||||||||
Other non-operating income (expense) | 6,708 | (339) | 2,268 | |||||||||
Income (loss) from continuing operations before income taxes | 1,678 | (6,711) | 7,419 | |||||||||
Total income tax benefit (expense) | 0 | 0 | 0 | |||||||||
Income (loss) from continuing operations—basic and diluted | 1,678 | (6,711) | 7,419 | |||||||||
Income from discontinued operations, net of tax | 2,813 | |||||||||||
Net income (loss) | 1,678 | (6,711) | 10,232 | |||||||||
Intercompany eliminations | ||||||||||||
Subsidiary guarantees | ||||||||||||
Total operating revenues | (24,086) | (8,505) | (8,739) | |||||||||
Total operating costs and expenses | (22,396) | (8,272) | (8,739) | |||||||||
Income (loss) from operations | (1,690) | (233) | 0 | |||||||||
Interest expense and other, net | 0 | 0 | 0 | |||||||||
Other non-operating income (expense) | (1,678) | 6,711 | (10,232) | |||||||||
Income (loss) from continuing operations before income taxes | (3,368) | 6,478 | (10,232) | |||||||||
Total income tax benefit (expense) | 0 | 0 | 0 | |||||||||
Income (loss) from continuing operations—basic and diluted | (3,368) | 6,478 | (10,232) | |||||||||
Income from discontinued operations, net of tax | 0 | |||||||||||
Net income (loss) | $ (3,368) | $ 6,478 | $ (10,232) | |||||||||
[1] | Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% |
Subsidiary guarantors - Cond118
Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Subsidiary guarantees | |||
Net cash flows provided by operating activities | $ 315,947 | $ 498,277 | $ 364,729 |
Change in investments between affiliates | 0 | 0 | 0 |
Capital expenditures and other | (667,507) | (1,406,961) | (329,884) |
Net cash flows provided by financing activities | 353,393 | 739,852 | 130,084 |
Net increase (decrease) in cash and cash equivalents | 1,833 | (168,832) | 164,929 |
Cash and cash equivalents, beginning of period | 29,321 | 198,153 | 33,224 |
Cash and cash equivalents, end of period | 31,154 | 29,321 | 198,153 |
Reportable Legal Entities | Laredo | |||
Subsidiary guarantees | |||
Net cash flows provided by operating activities | 316,838 | 496,955 | 359,198 |
Change in investments between affiliates | (136,252) | (113,449) | 23,986 |
Capital expenditures and other | (532,146) | (1,292,191) | (348,339) |
Net cash flows provided by financing activities | 353,393 | 739,852 | 130,084 |
Net increase (decrease) in cash and cash equivalents | 1,833 | (168,833) | 164,929 |
Cash and cash equivalents, beginning of period | 29,320 | 198,153 | 33,224 |
Cash and cash equivalents, end of period | 31,153 | 29,320 | 198,153 |
Reportable Legal Entities | Subsidiary Guarantors | |||
Subsidiary guarantees | |||
Net cash flows provided by operating activities | 787 | (5,389) | 15,763 |
Change in investments between affiliates | 134,574 | 120,160 | (34,218) |
Capital expenditures and other | (135,361) | (114,770) | 18,455 |
Net cash flows provided by financing activities | 0 | 0 | 0 |
Net increase (decrease) in cash and cash equivalents | 0 | 1 | 0 |
Cash and cash equivalents, beginning of period | 1 | 0 | 0 |
Cash and cash equivalents, end of period | 1 | 1 | 0 |
Intercompany eliminations | |||
Subsidiary guarantees | |||
Net cash flows provided by operating activities | (1,678) | 6,711 | (10,232) |
Change in investments between affiliates | 1,678 | (6,711) | 10,232 |
Capital expenditures and other | 0 | 0 | 0 |
Net cash flows provided by financing activities | 0 | 0 | 0 |
Net increase (decrease) 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. 16, 2016 | Jan. 15, 2016 | Jan. 14, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Subsequent Event [Line Items] | ||||||
Capital contribution payable to equity method investee | $ 99,855 | $ 55,164 | $ 3,287 | |||
Secured Debt | Subsequent events | ||||||
Subsequent Event [Line Items] | ||||||
Borrowing capacity | $ 35,000 | |||||
Line of credit | $ 170,000 | |||||
Medallion Gathering And Processing LLC | Subsequent events | ||||||
Subsequent Event [Line Items] | ||||||
Capital contribution payable to equity method investee | $ 8,300 | $ 12,700 |
Subsequent events - New derivat
Subsequent events - New derivative contracts (Details) - Crude Oil - Put - Subsequent events $ in Millions | Feb. 16, 2016USD ($)MMBTU$ / MMBTU | |
Subsequent Event [Line Items] | ||
Deferred premium | $ | $ 4.3 | |
January 2017 - December 2017 | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (in MMBtu) | MMBTU | 8,040,000 | [1] |
Floor price (in dollars per unit) | $ / MMBTU | 2.5 | [1] |
January 2018 - December 2018 | ||
Subsequent Event [Line Items] | ||
Aggregate volumes (in MMBtu) | MMBTU | 8,220,000 | [1] |
Floor price (in dollars per unit) | $ / MMBTU | 2.5 | [1] |
[1] | The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts. |
Supplemental oil, NGL and na121
Supplemental oil, NGL and natural gas disclosures - Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Property acquisition costs: | ||||
Evaluated | $ 0 | $ 3,873 | $ 9,652 | |
Unevaluated | 0 | 9,925 | 27,087 | |
Exploration | [1] | 20,697 | 242,284 | 48,763 |
Development costs | [2] | 500,577 | 1,049,317 | 654,452 |
Total costs incurred | 521,274 | 1,305,399 | 739,954 | |
Asset Retirement Obligation Costs | ||||
Property acquisition costs: | ||||
Total costs incurred | $ 13,400 | $ 6,900 | $ 6,800 | |
[1] | The Company acquired significant leasehold interests during the year ended December 31, 2014. | |||
[2] | The costs incurred for oil, NGL and natural gas development activities include $13.4 million, $6.9 million and $6.8 million in asset retirement obligations for the years ended December 31, 2015, 2014 and 2013, respectively. |
Supplemental oil, NGL and na122
Supplemental oil, NGL and natural gas disclosures - Capitalized oil, NGL and natural gas costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2011 | |
Aggregate capitalized costs related to oil and natural gas production activities | ||||
Evaluated properties | $ 5,103,635 | $ 4,446,781 | $ 3,276,578 | |
Unevaluated properties not being depleted | 140,299 | 342,731 | 208,085 | |
Capitalized costs | 5,243,934 | 4,789,512 | 3,484,663 | |
Less accumulated depletion and impairment | (4,218,942) | (1,586,237) | (1,349,315) | |
Net capitalized costs | 1,024,992 | 3,203,275 | 2,135,348 | |
Oil and natural gas property costs not being amortized | ||||
Unevaluated properties not being depleted | 12,640 | 110,955 | 9,293 | $ 7,411 |
Unproved properties, cummulative cost | $ 140,299 | $ 342,731 | $ 208,085 |
Supplemental oil, NGL and na123
Supplemental oil, NGL and natural gas disclosures - Results of oil, NGL and natural gas producing activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Revenues: | ||||
Oil, NGL and natural gas sales | $ 431,734 | $ 737,203 | $ 664,844 | |
Production costs: | ||||
Lease operating expenses | 108,341 | 96,503 | 79,136 | |
Production and ad valorem taxes | 32,892 | 50,312 | 42,396 | |
Total production costs | 141,233 | 146,815 | 121,532 | |
Other costs: | ||||
Depletion | 263,666 | 237,067 | 227,992 | |
Accretion of asset retirement obligations | 2,236 | 1,721 | 1,475 | |
Impairment expense | 2,369,477 | 0 | 0 | |
Income tax expense | [1] | (164,141) | 126,576 | 112,984 |
Results of operations | $ (2,180,737) | $ 225,024 | $ 200,861 | |
Effective tax rate (as a percent) | 7.00% | 38.00% | 39.00% | |
[1] | During the year ended December 31, 2015, the Company recorded a valuation allowance against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the year ended December 31, 2015, income tax benefit is computed utilizing the Company's effective rate of 7%, 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 benefit for the period. For the years ended December 31, 2014 and 2013, income tax expense is computed utilizing the statutory rate. |
Supplemental oil, NGL and na124
Supplemental oil, NGL and natural gas disclosures - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands | 12 Months Ended | ||
Dec. 31, 2015MBoeMMcfMBbls | Dec. 31, 2014MBoeMMcfMBbls | Dec. 31, 2013MBoeMMcfMBbls | |
Proved developed and undeveloped reserves: | |||
Beginning of year (MBOE) | MBoe | 247,322 | 203,615 | 188,632 |
Revisions (Provisions) of previous estimates (MBOE) | MBoe | (124,180) | (21,359) | (15,338) |
Extensions, discoveries and other additions (MBOE) | MBoe | 22,388 | 76,539 | 69,888 |
Purchases of reserves in place (MBOE) | MBoe | 256 | 412 | |
Sales of reserves in place (MBOE) | MBoe | (3,486) | (28,768) | |
Production (MBOE) | MBoe | (16,346) | (11,729) | (11,211) |
End of year (MBOE) | MBoe | 125,698 | 247,322 | 203,615 |
Proved developed reserves: | |||
Beginning of year (energy) | MBoe | 105,557 | 71,725 | 81,490 |
End of year (energy) | MBoe | 100,395 | 105,557 | 71,725 |
Proved undeveloped reserves: | |||
Beginning of year (energy) | MBoe | 141,765 | 131,890 | 107,142 |
End of year (energy) | MBoe | 25,303 | 141,765 | 131,890 |
Oil (MBbls) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 140,190 | 111,498 | 98,141 |
Revisions of previous estimates | (88,900) | (10,134) | (17,956) |
Extensions, discoveries and other additions | 10,511 | 45,554 | 37,850 |
Purchases of reserves in place | 173 | 170 | |
Sales of reserves in place | (1,552) | (1,220) | |
Production | (7,610) | (6,901) | (5,487) |
End of year | 52,639 | 140,190 | 111,498 |
Proved developed reserves: | |||
Beginning of year (volume) | 56,975 | 37,878 | 33,316 |
End of year (volume) | 40,944 | 56,975 | 37,878 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | 83,215 | 73,620 | 64,825 |
End of year (volume) | 11,695 | 83,215 | 73,620 |
Natural Gas Liquids | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 0 | ||
Revisions of previous estimates | 35,477 | ||
Extensions, discoveries and other additions | 5,865 | ||
Sales of reserves in place | (1,008) | ||
Production | (4,267) | ||
End of year | 36,067 | 0 | |
Proved developed reserves: | |||
Beginning of year (volume) | 0 | ||
End of year (volume) | 29,349 | 0 | |
Proved undeveloped reserves: | |||
Beginning of year (volume) | 0 | ||
End of year (volume) | 6,718 | 0 | |
Natural Gas (MMcf) | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | MMcf | 642,794 | 552,702 | 542,946 |
Revisions of previous estimates | MMcf | (424,546) | (67,350) | 15,710 |
Extensions, discoveries and other additions | MMcf | 36,074 | 185,909 | 192,229 |
Purchases of reserves in place | MMcf | 498 | 1,454 | |
Sales of reserves in place | MMcf | (5,554) | (165,289) | |
Production | MMcf | (26,816) | (28,965) | (34,348) |
End of year | MMcf | 221,952 | 642,794 | 552,702 |
Proved developed reserves: | |||
Beginning of year (volume) | MMcf | 291,493 | 203,082 | 289,045 |
End of year (volume) | MMcf | 180,613 | 291,493 | 203,082 |
Proved undeveloped reserves: | |||
Beginning of year (volume) | MMcf | 351,301 | 349,620 | 253,901 |
End of year (volume) | MMcf | 41,339 | 351,301 | 349,620 |
Supplemental oil, NGL and na125
Supplemental oil, NGL and natural gas disclosures - Net proved oil, NGL and natural gas reserves - (unaudited) - Narrative (Details) MBoe in Thousands | 12 Months Ended | ||
Dec. 31, 2015MBoelocation | Dec. 31, 2014MBoelocation | Dec. 31, 2013MBoelocation | |
Net proved oil and natural gas reserves | |||
Percentage of proved reserves estimated by independent reserve engineers | 100.00% | 100.00% | 100.00% |
Revisions (Provisions) of previous estimates (MBOE) | 124,180 | 21,359 | 15,338 |
Extensions, discoveries and other additions (MBOE) | 22,388 | 76,539 | 69,888 |
Number of proved and undeveloped locations removed | location | 378 | 226 | 174 |
Number of proved and undeveloped locations removed, Wolfberry wells | location | 182 | ||
Number of proved and undeveloped locations removed, Horizontal wells | location | 196 | ||
Number of proved undeveloped locations redetermined | location | 34 | 345 | 501 |
Number of locations in new proved undeveloped locations | location | 4 | 113 | |
Purchases of reserves in place (MBOE) | 256 | 412 | |
Permian Basin | |||
Net proved oil and natural gas reserves | |||
Number of locations in new proved undeveloped locations | location | 85 | ||
Proved Undeveloped Properties | |||
Net proved oil and natural gas reserves | |||
Extensions, discoveries and other additions (MBOE) | 2,669 | 41,757 | 47,643 |
Proved Undeveloped Properties | Permian Basin | |||
Net proved oil and natural gas reserves | |||
Extensions, discoveries and other additions (MBOE) | 45,510 | ||
Removal Of Proved And Undeveloped Locations and Reinterpretation of Undeveloped Locations | |||
Net proved oil and natural gas reserves | |||
Revisions (Provisions) of previous estimates (MBOE) | 106,883 | 26,017 | 11,944 |
Drilling of New Wells | |||
Net proved oil and natural gas reserves | |||
Extensions, discoveries and other additions (MBOE) | 19,719 | 34,782 | 22,245 |
Performance, Pricing and Other Changes | |||
Net proved oil and natural gas reserves | |||
Revisions (Provisions) of previous estimates (MBOE) | (17,297) | (4,658) | (3,394) |
Supplemental oil, NGL and na126
Supplemental oil, NGL and natural gas disclosures - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Future cash inflows | $ 3,269,184 | $ 16,663,685 | $ 13,337,798 | |
Future production costs | (1,321,471) | (3,616,775) | (3,059,368) | |
Future development costs | (376,701) | (2,471,985) | (2,250,950) | |
Future income tax expenses | 0 | (2,827,763) | (2,150,983) | |
Future net cash flows | 1,571,012 | 7,747,162 | 5,876,497 | |
10% discount for estimated timing of cash flows | (740,265) | (4,500,434) | (3,554,293) | |
Standardized measure of discounted future net cash flows | $ 830,747 | $ 3,246,728 | $ 2,322,204 | $ 1,877,456 |
Supplemental oil, NGL and na127
Supplemental oil, NGL and natural gas disclosures - Changes in the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | $ 3,246,728 | $ 2,322,204 | $ 1,877,456 |
Changes in the year resulting from: | |||
Sales, less production costs | (290,501) | (590,388) | (543,312) |
Revisions of previous quantity estimates | (2,444,322) | (320,275) | (190,961) |
Extensions, discoveries and other additions | 192,979 | 1,340,022 | 1,166,481 |
Net change in prices and production costs | (1,495,144) | 145,740 | 313,947 |
Changes in estimated future development costs | (2,974) | (22,961) | 921 |
Previously estimated development costs incurred during the period | 162,237 | 92,135 | 89,396 |
Purchases of reserves in place | 0 | 6,100 | 7,604 |
Divestitures of reserves in place | (29,149) | 0 | (239,148) |
Accretion of discount | 424,453 | 305,325 | 234,852 |
Net change in income taxes | 997,805 | (266,757) | (259,991) |
Timing differences and other | 68,635 | 235,583 | (135,041) |
Standardized measure of discounted future net cash flows, end of year | $ 830,747 | $ 3,246,728 | $ 2,322,204 |
Supplemental quarterly finan128
Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $ 123,275 | $ 150,340 | $ 182,331 | $ 150,694 | $ 237,290 | $ 200,241 | $ 183,044 | $ 173,310 | $ 606,640 | $ 793,885 | $ 665,257 |
Operating loss | (1,015,677) | (927,859) | (501,480) | (26,498) | 32,623 | 69,164 | 64,561 | 60,038 | (2,471,514) | 226,386 | 214,351 |
Net loss | $ (964,647) | $ (847,783) | $ (397,034) | $ (472) | $ 201,278 | $ 83,407 | $ (18,899) | $ (213) | $ (2,209,936) | $ 265,573 | $ 118,000 |
Net income (loss) per common share: | |||||||||||
Basic (in dollars per share) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ 1.42 | $ 0.59 | $ (0.13) | $ 0 | $ (11.10) | $ 1.88 | $ 0.89 |
Diluted (in dollars per share) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ 1.40 | $ 0.58 | $ (0.13) | $ 0 | $ (11.10) | $ 1.85 | $ 0.88 |