Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 13, 2017 | Jun. 30, 2016 | |
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, 2016 | ||
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 | 241,920,942 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Entity voluntary filer | No | ||
Entity well known seasoned issuer | Yes | ||
Entity public float | $ 1.1 |
Consolidated balance sheets
Consolidated balance sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Current assets: | |||
Cash and cash equivalents | $ 32,672 | $ 31,154 | |
Accounts receivable, net | 86,867 | 87,699 | |
Derivatives | 20,947 | 198,805 | |
Other current assets | 14,291 | 14,574 | |
Total current assets | 154,777 | 332,232 | |
Oil and natural gas properties, full cost method: | |||
Evaluated properties | 5,488,756 | 5,103,635 | |
Unevaluated properties not being depleted | 221,281 | [1] | 140,299 |
Less accumulated depletion and impairment | (4,514,183) | (4,218,942) | |
Oil and natural gas properties, net | 1,195,854 | 1,024,992 | |
Midstream service assets, net | 126,240 | 131,725 | |
Other fixed assets, net | 44,773 | 43,538 | |
Property and equipment, net | 1,366,867 | 1,200,255 | |
Derivatives | 8,718 | 77,443 | |
Investment in equity method investee | 243,953 | 192,524 | |
Other assets, net | 8,031 | 10,833 | |
Total assets | 1,782,346 | 1,813,287 | |
Current liabilities: | |||
Accounts payable | 15,054 | 14,181 | |
Undistributed revenue and royalties | 26,838 | 34,540 | |
Accrued capital expenditures | 30,845 | 61,872 | |
Derivatives | 20,993 | 0 | |
Other current liabilities | 94,215 | 106,222 | |
Total current liabilities | 187,945 | 216,815 | |
Long-term debt, net | 1,353,909 | 1,416,226 | |
Derivatives | 5,694 | 0 | |
Asset retirement obligations | 50,604 | 44,759 | |
Other noncurrent liabilities | 3,621 | 4,040 | |
Total liabilities | 1,601,773 | 1,681,840 | |
Commitments and contingencies | |||
Stockholders' equity: | |||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2016 and 2015 | 0 | 0 | |
Common stock, $0.01 par value, 450,000,000 shares authorized and 241,929,070 and 213,808,003 issued and outstanding as of December 31, 2016 and 2015, respectively | 2,419 | 2,138 | |
Additional paid-in capital | 2,396,236 | 2,086,652 | |
Accumulated deficit | (2,218,082) | (1,957,343) | |
Total stockholders' equity | 180,573 | 131,447 | |
Total liabilities and stockholders' equity | $ 1,782,346 | $ 1,813,287 | |
[1] | (1)Acquisition costs comprise 95% of the $221.3 million in unevaluated properties not being depleted. |
Consolidated balance sheets (Pa
Consolidated balance sheets (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
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 | 241,929,070 | 213,808,003 |
Common stock outstanding | 241,929,070 | 213,808,003 |
Consolidated statements of oper
Consolidated statements of operations - USD ($) shares in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Revenues: | ||||||
Oil, NGL and natural gas sales | $ 426,485,000 | $ 431,734,000 | $ 737,203,000 | |||
Midstream service revenues | 8,342,000 | 6,548,000 | 2,245,000 | |||
Sales of purchased oil | 162,551,000 | 168,358,000 | 54,437,000 | |||
Total revenues | 597,378,000 | 606,640,000 | 793,885,000 | |||
Costs and expenses: | ||||||
Lease operating expenses | 75,327,000 | 108,341,000 | 96,503,000 | |||
Production and ad valorem taxes | 28,586,000 | 32,892,000 | 50,312,000 | |||
Midstream service expenses | 4,077,000 | 5,846,000 | 5,429,000 | |||
Minimum volume commitments | 2,209,000 | 5,235,000 | 2,552,000 | |||
Costs of purchased oil | 169,536,000 | 174,338,000 | 53,967,000 | |||
Drilling rig fees | 0 | 0 | 527,000 | |||
General and administrative | [1] | 91,756,000 | 90,425,000 | 106,044,000 | ||
Restructuring expenses | 0 | 6,042,000 | 0 | |||
Accretion of asset retirement obligations | 3,483,000 | 2,423,000 | 1,787,000 | |||
Depletion, depreciation and amortization | [2] | 148,339,000 | 277,724,000 | 246,474,000 | ||
Impairment expense | 162,027,000 | 2,374,888,000 | 3,904,000 | |||
Total costs and expenses | 685,340,000 | 3,078,154,000 | 567,499,000 | |||
Operating income (loss) | (87,962,000) | (2,471,514,000) | 226,386,000 | |||
Non-operating income (expense): | ||||||
Gain (loss) on derivatives, net | (87,425,000) | 214,291,000 | 327,920,000 | |||
Income (loss) from equity method investee | 9,403,000 | 6,799,000 | (192,000) | |||
Interest expense | [3] | (93,298,000) | (103,219,000) | (121,173,000) | ||
Interest and other income | 175,000 | 426,000 | 294,000 | |||
Loss on early redemption of debt | 0 | (31,537,000) | [4] | 0 | ||
Write-off of debt issuance costs | (842,000) | 0 | (124,000) | |||
Loss on disposal of assets, net | (790,000) | (2,127,000) | (3,252,000) | |||
Non-operating income (expense), net | (172,777,000) | 84,633,000 | 203,473,000 | |||
Income (loss) before income taxes | (260,739,000) | (2,386,881,000) | 429,859,000 | |||
Income tax benefit (expense): | ||||||
Deferred | 0 | 176,945,000 | (164,286,000) | |||
Total income tax benefit (expense) | 0 | 176,945,000 | [5] | (164,286,000) | [5] | |
Net income (loss) | $ (260,739,000) | $ (2,209,936,000) | $ 265,573,000 | |||
Net income (loss) per common share: | ||||||
Basic (in dollars per share) | $ (1.16) | $ (11.10) | $ 1.88 | |||
Diluted (in dollars per share) | $ (1.16) | $ (11.10) | $ 1.85 | |||
Weighted-average common shares outstanding: | ||||||
Basic (shares) | [6] | 225,512 | 199,158 | 141,312 | ||
Diluted (shares) | [6] | 225,512 | 199,158 | 143,554 | ||
[1] | General and administrative expense was allocated based on the number of employees in the respective segment as of December 31, 2016, 2015 and 2014. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. | |||||
[2] | Depletion, depreciation and amortization were actual expenses 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 as of December 31, 2016, 2015 and 2014. | |||||
[3] | Interest expense was allocated to the exploration and production segment based on gross property and equipment as of December 31, 2016, 2015 and 2014 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 as of December 31, 2016, 2015 and 2014. | |||||
[4] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of 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 as of December 31, 2015. | |||||
[5] | Income tax expense or benefit for the midstream and marketing segment was calculated by multiplying income or loss before income taxes by 36% for the years ended December 31, 2015 and 2014. | |||||
[6] | Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the years ended December 31, 2016 and 2015. There were no comparable equity offerings during the year ended December 31, 2014. See Note 3 for additional discussion of the Company's equity offerings. |
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, 2013 | 142,671 | 0 | |||
Balance at beginning 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 issuance, net of offering costs (in shares) | 69,000 | ||||
Equity issuance, 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) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (in shares) | 2,982 | ||||
Restricted stock awards | $ 30 | (30) | |||
Restricted stock forfeitures (in shares) | (457) | ||||
Restricted stock forfeitures | $ (5) | 5 | |||
Vested restricted stock exchanged for tax withholding (in shares) | 296 | ||||
Vested restricted stock exchanged for tax withholding | (1,635) | $ (1,635) | |||
Retirement of treasury stock (in shares) | (296) | (296) | |||
Retirement of treasury stock | $ (3) | (1,632) | $ 1,635 | ||
Exercise of employee stock options (in shares) | 17 | ||||
Exercise of employee stock options | 208 | $ 0 | 208 | ||
Equity issuance, net of offering costs (in shares) | 25,875 | ||||
Equity issuance, net of offering costs | 276,052 | $ 259 | 275,793 | ||
Stock-based compensation | 35,240 | 35,240 | |||
Net income (loss) | (260,739) | (260,739) | |||
Balance at end of year (in shares) at Dec. 31, 2016 | 241,929 | 0 | |||
Balance at end of year at Dec. 31, 2016 | $ 180,573 | $ 2,419 | $ 2,396,236 | $ 0 | $ (2,218,082) |
Consolidated statements of cash
Consolidated statements of cash flows - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Cash flows from operating activities: | ||||
Net income (loss) | $ (260,739) | $ (2,209,936) | $ 265,573 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
Deferred income tax (benefit) expense | 0 | (176,945) | 164,286 | |
Depletion, depreciation and amortization | 148,339 | 277,724 | 246,474 | |
Impairment expense | 162,027 | 2,374,888 | 3,904 | |
Loss on early redemption of debt | 0 | 31,537 | [1] | 0 |
Bad debt expense | 0 | 255 | 342 | |
Non-cash stock-based compensation, net of amounts capitalized | 29,229 | 24,509 | 23,079 | |
Mark-to-market on derivatives: | ||||
(Gain) loss on derivatives, net | 87,425 | (214,291) | (327,920) | |
Cash settlements received for matured derivatives, net | 195,281 | 255,281 | 28,241 | |
Cash settlements received for early terminations of derivatives, net | 80,000 | 0 | 76,660 | |
Change in net present value of derivative deferred premiums | 232 | 203 | 220 | |
Cash premiums paid for derivatives | (89,669) | (5,167) | (7,419) | |
Amortization of debt issuance costs | 4,279 | 4,727 | 5,137 | |
Write-off of debt issuance costs | 842 | 0 | 124 | |
(Income) loss from equity method investee | (9,403) | (6,799) | 192 | |
Cash settlement of performance unit awards | (6,394) | (2,738) | 0 | |
Other, net | 4,596 | 4,554 | 5,442 | |
Decrease (increase) in accounts receivable | 832 | 38,975 | (49,953) | |
Increase in other assets | (1,013) | (2,309) | (16,688) | |
Increase (decrease) in accounts payable | 873 | (24,827) | 23,006 | |
(Decrease) increase in undistributed revenues and royalties | (7,735) | (30,898) | 30,314 | |
Increase (decrease) in other accrued liabilities | 17,712 | (26,996) | 23,837 | |
(Decrease) increase in other noncurrent liabilities | (419) | 119 | 2,825 | |
Increase in fair value of performance unit awards | 0 | 4,081 | 601 | |
Net cash provided by operating activities | 356,295 | 315,947 | 498,277 | |
Cash flows from investing activities: | ||||
Deposit received for sale of oil and natural gas properties | 3,000 | 0 | 0 | |
Capital expenditures: | ||||
Acquisitions of oil and natural gas properties | (124,660) | 0 | (6,493) | |
Acquisition of mineral interests | 0 | 0 | (7,305) | |
Oil and natural gas properties | (360,679) | (588,017) | (1,251,757) | |
Midstream service assets | (5,240) | (35,459) | (60,548) | |
Other fixed assets | (7,611) | (9,125) | (27,444) | |
Investment in equity method investee | (69,609) | (99,855) | (55,164) | |
Proceeds from dispositions of capital assets, net of selling costs | 397 | 64,949 | 1,750 | |
Net cash used in investing activities | (564,402) | (667,507) | (1,406,961) | |
Cash flows from financing activities: | ||||
Borrowings on Senior Secured Credit Facility | 239,682 | 310,000 | 300,000 | |
Payments on Senior Secured Credit Facility | (304,682) | (475,000) | 0 | |
Redemption of January 2019 Notes | 0 | (576,200) | 0 | |
Proceeds from issuance of common stock, net of offering costs | 276,052 | 754,163 | 0 | |
Purchase of treasury stock | (1,635) | (2,811) | (4,242) | |
Proceeds from exercise of employee stock options | 208 | 0 | 1,885 | |
Payments for debt issuance costs | 0 | (6,759) | (7,791) | |
Net cash provided by financing activities | 209,625 | 353,393 | 739,852 | |
Net increase (decrease) in cash and cash equivalents | 1,518 | 1,833 | (168,832) | |
Cash and cash equivalents, beginning of period | 31,154 | 29,321 | 198,153 | |
Cash and cash equivalents, end of period | 32,672 | 31,154 | 29,321 | |
March 2023 Notes | ||||
Cash flows from financing activities: | ||||
Issuance of Notes | 0 | 350,000 | 0 | |
January 2022 Notes | ||||
Cash flows from financing activities: | ||||
Issuance of Notes | $ 0 | $ 0 | $ 450,000 | |
[1] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of 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 as of December 31, 2015. |
Organization
Organization | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Organization Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate. The Company operates in two business segments: (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 third parties with 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 delivery and takeaway. |
Basis of presentation and signi
Basis of presentation and significant accounting policies | 12 Months Ended |
Dec. 31, 2016 | |
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 14 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, natural gas liquids ("NGL") and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed in an acquisition and (ix) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. c. Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2016 presentation. These reclassifications had no impact to previously reported balance sheets, net income (loss) or stockholders' equity. 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 oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company'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. 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) 2016 2015 Oil, NGL and natural gas sales $ 46,999 $ 25,582 Sales of purchased oil and other products 16,213 11,775 Joint operations, net (1) 12,175 21,375 Matured derivatives 11,059 27,469 Other 421 1,498 Total $ 86,867 $ 87,699 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of December 31, 2016 and 2015 . As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of production revenues. f. Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL 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, in prior periods, basis swaps. 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 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 exploring for or developing oil, NGL and natural gas properties, are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being 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 $221.3 million and $140.3 million of such costs were excluded from the depletion base as of December 31, 2016 and 2015 , 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 $4.5 billion and $4.2 billion for the years ended December 31, 2016 and 2015 , respectively. Depletion expense for oil and natural gas properties was $134.1 million , $263.7 million and $237.1 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $7.39 , $16.13 and $20.21 for the years ended December 31, 2016 , 2015 and 2014 , respectively. The following table presents capitalized employee-related costs for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Capitalized employee-related costs $ 19,222 $ 10,688 $ 16,345 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 to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment. See Note 20.b for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission ("SEC") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2016 December 31, 2015 December 31, 2014 (1) Benchmark Prices: Oil ($/Bbl) $ 39.25 $ 46.79 $ 91.48 NGL ($/Bbl) $ 18.24 $ 18.75 $ — Natural gas ($/MMBtu) $ 2.33 $ 2.47 $ 4.25 Realized Prices: Oil ($/Bbl) $ 37.44 $ 45.58 $ 89.57 NGL ($/Bbl) $ 11.72 $ 12.50 $ — Natural gas ($/Mcf) $ 1.78 $ 1.89 $ 6.39 _____________________________________________________________________________ (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 2016 and 2015 with prior periods. Full cost ceiling impairment expense for the years ended December 31, 2016 and 2015 in the consolidated statements of operations was $161.1 million and $2.4 billion , respectively. There were no full cost ceiling impairments recorded during the year ended December 31, 2014. These amounts are 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 16. h. Midstream service assets Midstream service assets, which consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost, are recorded at cost, net of impairment. See Note 2.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 for midstream service assets was $8.3 million , $7.5 million and $4.3 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Midstream service assets consisted of the following as of December 31: (in thousands) 2016 2015 Midstream service assets $ 150,629 $ 147,811 Less accumulated depreciation and impairment (24,389 ) (16,086 ) Total, net $ 126,240 $ 131,725 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 for other fixed assets was $5.9 million , $6.5 million and $5.1 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Other fixed assets consisted of the following as of December 31: (in thousands) 2016 2015 Computer hardware and software $ 12,710 $ 12,148 Aircraft 11,352 4,952 Real estate and buildings 7,618 7,618 Leasehold improvements 7,549 7,710 Vehicles 7,413 9,266 Other 5,849 5,105 Depreciable total 52,491 46,799 Less accumulated depreciation and amortization (22,632 ) (18,169 ) Depreciable total, net 29,859 28,630 Land 14,914 14,908 Total, net $ 44,773 $ 43,538 j. Long-lived assets and inventory 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. Beginning in the fourth quarter of 2016, the Company early-adopted a new accounting standard that simplified the measurement of inventory and has applied its provisions prospectively. 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 lower of cost or market ("LCM") to the lower of cost or net realizable value. Net realizable value ("NRV") is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. There was no effect to the consolidated financials statements upon adoption of this guidance. See additional discussion in Note 18. Materials and supplies inventory, which is used in the Company's production activities of oil and natural gas properties and midstream service assets, is carried at the lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory is determined utilizing a replacement cost approach (Level 2). Beginning in 2016, the Company has frac pit water inventory, which is used in developing oil and natural gas properties and is carried at lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other current assets" on the consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach (Level 2). 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 lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the consolidated balance sheets. The net realizable value is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). The following table presents inventory impairments recorded as of the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Inventory impairments: Materials and supplies (1) $ 963 $ 2,819 $ 1,802 Line-fill (2) — 1,314 2,102 Total inventory impairments $ 963 $ 4,133 $ 3,904 ______________________________________________________________________________ (1) Included in "Impairment expense" in the consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16. (2) Included in "Impairment expense" in the consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16. 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 16. There were no comparable impairments recorded for the years ended December 31, 2016 or 2014. 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). No debt issuance costs were capitalized in the year ended December 31, 2016. The Company had total debt issuance costs of $18.8 million and $23.9 million , net of accumulated amortization of $21.3 million and $17.0 million , as of December 31, 2016 and 2015 , respectively. The Company wrote-off $0.8 million of debt issuance costs during the year ended December 31, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility (as defined below), which are included in the consolidated statements of operations in the "Write-off of debt issuance costs" line item. The Company wrote-off $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 are 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 due to the issuance of the January 2022 Notes, which are included in the consolidated statements of operations in the "Write-off of debt issuance costs" line item. Debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's consolidated balance sheets. See Note 5.h 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, 2016 2017 $ 4,238 2018 4,068 2019 2,915 2020 3,005 2021 3,102 Thereafter 1,483 Total $ 18,811 l. Other current assets and liabilities Other current assets consisted of the following components as of December 31: (in thousands) 2016 2015 Inventory (1) $ 8,063 $ 6,974 Prepaid expenses and other 6,228 7,600 Total other current assets $ 14,291 $ 14,574 ______________________________________________________________________________ (1) See Note 2.j for discussion of inventory held by the Company. Other current liabilities consisted of the following components as of December 31: (in thousands) 2016 2015 Accrued compensation and benefits $ 25,947 $ 14,342 Accrued interest payable 24,152 24,208 Purchased oil payable 17,213 12,189 Lease operating expense payable 10,572 13,205 Capital contribution payable to equity method investee (1) — 27,583 Other accrued liabilities 16,331 14,695 Total other current liabilities $ 94,215 $ 106,222 _____________________________________________________________________________ (1) See Notes 14 and 15.a for additional discussion regarding the Company's 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 assets 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 gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable. The following reconciles the Company's asset retirement obligation liability as of December 31: (in thousands) 2016 2015 Liability at beginning of year $ 46,306 $ 32,198 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 1,528 2,236 Accretion expense 3,483 2,423 Liabilities settled upon plugging and abandonment (1,242 ) (146 ) Liabilities removed due to sale of property — (2,005 ) Revision of estimates (1) 2,132 11,600 Liability at end of year $ 52,207 $ 46,306 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 was 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, 2016 or 2015. 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) 2016 2015 2014 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,477 $ 3,125 $ 3,265 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 values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included 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. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2016 or 2015 . See Note 7 for additional information regarding the Company's income taxes. t. 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 environment |
Equity offering
Equity offering | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Equity offerings | Equity offerings a. July 2016 Equity Offering On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of $136.3 million , after underwriting discounts, commissions and offering expenses. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of Laredo's common stock, which resulted in net proceeds to the Company of $20.5 million , after underwriting discounts, commissions and offering expenses. b. May 2016 Equity Offering On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million , after underwriting discounts, commissions and offering expenses. c. March 2015 Equity Offering On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock (the "March 2015 Equity Offering") for net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering. There were no comparative offerings of Laredo's stock during the year ended December 31, 2014. |
Acquisitions and divestiture
Acquisitions and divestiture | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Acquisitions and divestiture | Acquisitions and divestiture a. 2016 Acquisitions of evaluated and unevaluated oil and natural gas properties The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 9. During the year ended December 31, 2016, the Company acquired 9,200 net acres of additional leasehold interests and working interests in 81 producing vertical wells in western Glasscock and Reagan counties (which included production of approximately 300 net BOE/D) within the Company's core development area for an aggregate purchase price of $ 124.7 million subject to customary closing adjustments. The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723 b. 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 wells 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 Oil, NGL and natural gas sales $ 5,138 $ 19,337 Expenses (1) $ 5,791 $ 11,082 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. c. Summary of 2014 acquisitions The following table presents the Company's material 2014 acquisitions. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions, see Note 3 to the consolidated financial statements included in the Company's 2014 Annual Report on Form 10-K. (in thousands) Accounting treatment Cash consideration 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 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
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) 2016 2015 2014 Cash payments for interest $ 89,726 $ 112,693 $ 105,086 Amortization of debt issuance costs and other adjustments 3,922 4,243 4,433 Change in accrued interest (56 ) (13,481 ) 11,804 Interest costs incurred 93,592 103,455 121,323 Less capitalized interest (294 ) (236 ) (150 ) Total interest expense $ 93,298 $ 103,219 $ 121,173 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, 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. 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 has 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. 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 in aggregate principal amount of 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 in aggregate principal amount of 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, 2016 , the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures on November 4, 2018 , had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $815.0 million with $70.0 million outstanding and was subject to an interest rate of 2.31% . The borrowing base is subject to a semi-annual redetermination occurring by May 1 and November 1 of each year based on the lenders' evaluation of the Company's oil 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% , based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility; and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one -month, two -month, three -month, six -month or, to the extent available, 12 -month interest periods (and in the case of six -month and 12 -month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate plus an applicable margin, which ranges from 1.5% 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 Guarantors' assets (other than LMS's interest in Medallion (defined below)) 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 covenants on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00 . As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, at the end of each calendar quarter, the Company must maintain a ratio of (I) its consolidated net income (loss) (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus other non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of consolidated net interest expense plus letter of credit fees of not less than 2.50 to 1.00 , in each case for the four quarters then ending. The Company was in compliance with these covenants for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million . No letters of credit were outstanding as of December 31, 2016 or 2015 . See Note 19.a for discussion of a payment made to the Senior Secured Credit Facility subsequent to December 31, 2016. g. Fair value of debt The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the periods presented: December 31, 2016 December 31, 2015 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 456,382 $ 450,000 $ 388,301 May 2022 Notes 500,000 521,413 500,000 460,000 March 2023 Notes 350,000 365,649 350,000 301,000 Senior Secured Credit Facility 70,000 69,975 135,000 134,993 Total value of debt $ 1,370,000 $ 1,413,419 $ 1,435,000 $ 1,284,294 The fair values of the debt outstanding on the January 2022 Notes, the May 2022 Notes and the March 2023 Notes were determined using the December 31, 2016 and 2015 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, 2016 and 2015 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels. h. Long-term debt, net The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets as of the periods presented: December 31, 2016 December 31, 2015 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (4,963 ) $ 445,037 $ 450,000 $ (5,939 ) $ 444,061 May 2022 Notes 500,000 (6,164 ) 493,836 500,000 (7,066 ) 492,934 March 2023 Notes 350,000 (4,964 ) 345,036 350,000 (5,769 ) 344,231 Senior Secured Credit Facility (1) 70,000 — 70,000 135,000 — 135,000 Total $ 1,370,000 $ (16,091 ) $ 1,353,909 $ 1,435,000 $ (18,774 ) $ 1,416,226 _____________________________________________________________________________ (1) Debt issuance costs related to our Senior Secured Credit Facility of $2.7 million and $5.2 million as of December 31, 2016 and 2015 , respectively, are recorded net in "Other assets, net" on the consolidated balance sheets. |
Employee compensation
Employee compensation | 12 Months Ended |
Dec. 31, 2016 | |
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, stock option awards, performance share awards, performance unit awards and other awards. During the year ended December 31, 2016, Laredo's stockholders approved an increase in the maximum number of shares of Laredo's common stock issuable under the LTIP from 10,000,000 shares to 24,350,000 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, in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. a. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Historically, restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33% , 33% and 34% per year beginning on the first anniversary date of the grant, (ii) 50% in year two and 50% in year three, (iii) fully on the first anniversary of the grant date and (iv) 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 restricted stock award activity for the years ended December 31, 2014, 2015 and 2016: (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, 2013 1,799 $ 19.17 Granted 1,234 $ 25.68 Forfeited (148 ) $ 22.56 Vested (680 ) $ 19.13 Outstanding as of December 31, 2014 2,205 $ 22.63 Granted 1,902 $ 11.98 Forfeited (553 ) $ 20.48 Vested (1,015 ) $ 22.32 Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1) (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2016 was $7.3 million . The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of December 31, 2016 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $29.7 million . Such cost is expected to be recognized over a weighted-average period of 1.88 years. b. Stock option awards 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, 2014, 2015 and 2016: (in thousands, except for weighted-average price and weighted-average remaining contractual term) Stock option Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2013 1,229 $ 19.32 8.82 Granted 336 $ 25.60 Exercised (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 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Vested and exercisable at end of period (1) 831 $ 19.43 6.25 Expected to vest at end of period (2) 1,536 $ 8.78 8.51 _____________________________________________________________________________ (1) The vested and exercisable stock option awards as of December 31, 2016 had $0.3 million aggregate intrinsic value. (2) The stock option awards expected to vest as of December 31, 2016 had $10.0 million aggregate intrinsic value. The Company utilizes the Black-Scholes option pricing model to determine the fair value of 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, 2016 , unrecognized stock-based compensation related to stock option awards expected to vest was $9.8 million . Such cost is expected to be recognized over a weighted-average period of 2.76 years. The assumptions used to estimate the fair value of stock option awards granted during the period are as follows: May 25, 2016 April 1, 2016 February 27, 2015 February 27, 2014 Risk-free interest rate (1) 1.58 % 1.44 % 1.70 % 1.88 % Expected option life (2) 6.25 years 6.25 years 6.25 years 6.25 years Expected volatility (3) 61.94 % 61.34 % 52.59 % 53.21 % Fair value per stock option award $ 9.75 $ 4.44 $ 6.15 $ 13.41 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own volatility in order to develop the expected volatility for the May 25, 2016, April 1, 2016 and February 27, 2015 grants. The February 27, 2014 grant 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 stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the stock option award will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause. c. Performance share awards The performance share awards granted to management on May 25, 2016 and April 1, 2016 (collectively the "2016 Performance Share Awards"), 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 1,670,577 outstanding 2016 Performance Share Awards have a performance period of January 1, 2016 to December 31, 2018, and any shares earned under such awards are expected to be issued in the first quarter of 2019 if the performance criteria are met. The 454,164 outstanding 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. The 200,516 outstanding 2014 Performance Share Awards had a performance period of January 1, 2014 to December 31, 2016 and, as their performance criteria were satisfied, 75% of the shares will be issued during the first quarter of 2017 if the February 27, 2017 vesting criteria is satisfied. The following table reflects the performance share award activity for the years ended December 31, 2014, 2015 and 2016: (in thousands, except for weighted-average grant date fair values) Performance share Weighted-average Outstanding as of December 31, 2013 — $ — Granted 272 $ 28.56 Forfeited — $ — Vested — $ — Outstanding as of December 31, 2014 272 $ 28.56 Granted 602 $ 16.23 Forfeited — $ — Vested — $ — Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Vested — $ — Outstanding as of December 31, 2016 2,325 $ 18.35 As of December 31, 2016 , unrecognized stock-based compensation related to the performance share awards expected to vest was $26.2 million . Such cost is expected to be recognized over a weighted-average period of 2.03 years. The assumptions used to estimate the fair value of the performance share awards granted are as follows: May 25, 2016 April 1, 2016 February 27, 2015 February 27, 2014 Risk-free rate (1) 1.02 % 0.87 % 0.95 % 0.63 % Dividend yield — % — % — % — % Expected volatility (2) 74.73 % 71.54 % 53.78 % 38.21 % Laredo stock closing price as of the grant date $ 12.36 $ 7.71 $ 11.93 $ 25.60 Fair value per performance share $ 17.86 $ 9.83 $ 16.23 $ 28.56 _____________________________________________________________________________ (1) The risk-free rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility over a look-back period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility for these grants. d. Stock-based compensation expense The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Restricted stock award compensation $ 21,609 $ 17,534 $ 21,982 Stock option award compensation 4,519 4,074 3,639 Restricted performance share award compensation 9,112 5,222 2,108 Total stock-based compensation, gross 35,240 26,830 27,729 Less amounts capitalized in oil and natural gas properties (6,011 ) (2,321 ) (4,650 ) Total stock-based compensation, net of amounts capitalized $ 29,229 $ 24,509 $ 23,079 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 44,481 settled 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 27,381 settled 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 $100.00 per unit during 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 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 Performance Unit Award compensation expense $ 4,081 $ 409 2012 Performance Unit Award compensation expense — 192 Total performance unit award compensation expense $ 4,081 $ 601 For the years ended December 31, 2015 and 2014, compensation expense for the performance unit awards is recognized in "General and administrative" in the Company's consolidated statements of operations, and as of December 31, 2015, the corresponding liability is included in "Other current 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) 2016 2015 2014 Contributions $ 1,789 $ 1,847 $ 2,202 |
Income taxes
Income taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income taxes The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit (expense) for the periods presented consisted of the following: For the years ended December 31, (in thousands) 2016 2015 2014 Current taxes: Federal $ — $ — $ — State — — — Deferred taxes: Federal — 152,590 (147,445 ) State — 24,355 (16,841 ) Income tax benefit (expense) $ — $ 176,945 $ (164,286 ) Income tax benefit (expense) differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2016, 2015 and 2014 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2016 2015 2014 Income tax benefit (expense) computed by applying the statutory rate $ 91,259 $ 835,408 $ (150,450 ) Increase in deferred tax valuation allowance (86,569 ) (668,702 ) (1,139 ) Stock-based compensation tax deficiency (4,144 ) (3,274 ) (266 ) State income tax and increase in valuation allowance (370 ) 13,975 (11,099 ) Non-deductible stock-based compensation — (256 ) (509 ) Other items (176 ) (206 ) (823 ) Income tax benefit (expense) $ — $ 176,945 $ (164,286 ) The effective tax rate for the Company's operations was 0% , 7% and 38% for the years ended December 31, 2016, 2015 and 2014, 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 the year ended December 31, 2016, in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil, NGL and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2016, management determined it was more likely than not that the net deferred tax assets were not realizable, therefore a valuation allowance of $87.5 million was recorded. During the year ended December 31, 2015, a valuation allowance of $676.0 million was recorded. 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, 2016, a total valuation allowance of $764.8 million has been recorded against the deferred tax asset. The Company early-adopted a new accounting standard that simplified the accounting for stock-based compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2016 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. The resulting deferred tax asset was assessed for realizability in accordance with GAAP. Due to the Company's valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2016, and therefore, the net effect of the early adoption of this new accounting standard was zero . See Note 18 for additional discussion of the early adoption of this new accounting standard. The following table presents significant components of the Company's net deferred tax asset as of December 31: (in thousands) 2016 2015 Net operating loss carry-forward $ 573,521 $ 479,022 Oil and natural gas properties, midstream service assets and other fixed assets 186,473 306,997 Equity method investee (24,293 ) (31,711 ) Stock-based compensation 15,639 11,597 Accrued bonus 8,834 4,763 Materials and supplies impairment 1,982 1,647 Capitalized interest 1,767 2,525 Derivatives 150 (98,675 ) Other 743 1,173 Net deferred tax asset before valuation allowance 764,816 677,338 Valuation allowance (764,816 ) (677,338 ) Net deferred tax asset $ — $ — 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, 2016 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,180,937 Total $ 1,633,885 The Company had federal net operating loss carry-forwards totaling $1.6 billion and state of Oklahoma net operating loss carry-forwards totaling $42.6 million as of December 31, 2016. These carry-forwards begin expiring in 2026. As of December 31, 2016, 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, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2016, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income. The Company files a single return. The Company's income tax returns for the years 2013 through 2016 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. See Note 2.s for further discussion of accounting policies regarding income taxes. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives a. Commodity derivatives The Company engages in derivative transactions such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risks due to unfavorable changes in oil, NGL and natural gas prices related to its production. As of December 31, 2016 , the Company had 20 open derivative contracts with financial institutions that extend from January 2017 to December 2018. 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 earnings. Gains and losses on derivatives are reported on the consolidated statements of operations on the "Gain (loss) on derivatives, net" line item. 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. In prior years, the oil basis swap transactions had an established fixed basis differential. The Company's oil basis swaps' differential was between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude oil price and the West Texas Intermediate NYMEX ("WTI NYMEX") index crude oil price. When the WTI NYMEX price less the fixed basis differential was greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential was less than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid by the Company to the counterparty. The Company's oil derivatives are settled based on the month's average daily NYMEX index price for the First Nearby Month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane and TET Propane. The Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period. During the year ended December 31, 2016 , the Company successfully completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount of $80.0 million , which was settled in full by applying the proceeds to prepay the premiums on two new derivatives entered into during the restructuring. During the year ended December 31, 2016 , the following derivatives were terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Contract period Oil: Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 During the year ended December 31, 2016 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: (3) Put 600,000 $ 40.00 $ — May 2016 - December 2016 Put (4) 2,263,000 $ 60.00 $ — January 2017 - December 2017 Swap 1,003,750 $ 51.90 $ 51.90 January 2017 - December 2017 Swap 1,003,750 $ 51.17 $ 51.17 January 2017 - December 2017 Collar 1,168,000 $ 50.00 $ 60.75 January 2017 - December 2017 Put (5) 2,098,750 $ 60.00 $ — January 2017 - December 2018 Swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 NGL: Swap - Ethane 444,000 $ 11.24 $ 11.24 January 2017 - December 2017 Swap - Propane 375,000 $ 22.26 $ 22.26 January 2017 - December 2017 Natural gas: (6) Put 8,040,000 $ 2.50 $ — January 2017 - December 2017 Collar 5,256,000 $ 2.50 $ 3.05 January 2017 - December 2017 Collar 3,723,000 $ 3.00 $ 3.54 January 2017 - December 2017 Collar 4,562,500 $ 3.00 $ 3.55 January 2017 - December 2017 Put 8,220,000 $ 2.50 $ — January 2018 - December 2018 Collar 4,635,500 $ 2.50 $ 3.60 January 2018 - December 2018 _____________________________________________________________________________ (1) Oil and NGL are in Bbl and natural gas is in MMBtu. (2) Oil and NGL are in $/Bbl and natural gas is in $/MMBtu. (3) There were $2.9 million in deferred premiums associated with these contracts upon inception. (4) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception. (5) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (6) There were $5.1 million in deferred premiums associated with these contracts upon inception. During the year ended December 31, 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. The following represents cash settlements received for derivatives, net for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Cash settlements received for matured derivatives, net (1) $ 195,281 $ 255,281 $ 28,241 Cash settlements received for early terminations of derivatives, net (2) 80,000 — 76,660 Cash settlements received for derivatives, net $ 275,281 $ 255,281 $ 104,901 _____________________________________________________________________________ (1) The settlement amount does not include premiums paid attributable to contracts that matured during the respective period. (2) The settlement amount for the year ended December 31, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they derive. The following table summarizes open positions as of December 31, 2016 , and represents, as of such date, derivatives in place through December 2018 on annual production volumes: Year 2017 Year 2018 Oil positions: Puts: Hedged volume (Bbl) 1,049,375 1,049,375 Weighted-average price ($/Bbl) $ 60.00 $ 60.00 Swaps: Hedged volume (Bbl) 2,007,500 1,095,000 Weighted-average price ($/Bbl) $ 51.54 $ 52.12 Collars: Hedged volume (Bbl) 3,796,000 — Weighted-average floor price ($/Bbl) $ 56.92 $ — Weighted-average ceiling price ($/Bbl) $ 86.00 $ — Totals: Total volume hedged with floor price (Bbl) 6,852,875 2,144,375 Weighted-average floor price ($/Bbl) $ 55.82 $ 55.98 Total volume hedged with ceiling price (Bbl) 5,803,500 1,095,000 Weighted-average ceiling price ($/Bbl) $ 74.08 $ 52.12 NGL positions: Swaps - Ethane: Hedged volume (Bbl) 444,000 — Weighted-average price ($/Bbl) $ 11.24 $ — Swaps - Propane: Hedged volume (Bbl) 375,000 — Weighted-average price ($/Bbl) $ 22.26 $ — Totals: Total volume hedged with floor price (Bbl) 819,000 — Total volume hedged with ceiling price (Bbl) 819,000 — Natural gas positions: Puts: Hedged volume (MMBtu) 8,040,000 8,220,000 Weighted-average price ($/MMBtu) $ 2.50 $ 2.50 Collars: Hedged volume (MMBtu) 19,016,500 4,635,500 Weighted-average floor price ($/MMBtu) $ 2.86 $ 2.50 Weighted-average ceiling price ($/MMBtu) $ 3.54 $ 3.60 Totals: Total volumed hedged with floor price (MMBtu) 27,056,500 12,855,500 Weighted-average floor price ($/MMBtu) $ 2.75 $ 2.50 Total volume hedged with ceiling price (MMBtu) 19,016,500 4,635,500 Weighted-average ceiling price ($/MMBtu) $ 3.54 $ 3.60 b. Balance sheet presentation In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil, NGL and natural gas 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, 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, NGL 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, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The 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, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair value measurements | Fair value measurements The Company accounts for its oil, NGL and natural gas 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, 2016 , 2015 or 2014 . 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 As of December 31, 2016: Assets Current: Oil derivatives $ — $ 22,527 $ — $ 22,527 $ — $ 22,527 NGL derivatives — — — — — — Natural gas derivatives — 270 — 270 (270 ) — Oil deferred premiums — — — — (1,580 ) (1,580 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 8,718 $ — $ 8,718 $ — $ 8,718 NGL derivatives — — — — — — Natural gas derivatives — 1,377 — 1,377 (1,377 ) — Oil deferred premiums — — — — — — Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,789 ) $ — $ (9,789 ) $ — $ (9,789 ) NGL derivatives — (2,803 ) — (2,803 ) — (2,803 ) Natural gas derivatives — (3,639 ) — (3,639 ) 270 (3,369 ) Oil deferred premiums — — (3,569 ) (3,569 ) 1,580 (1,989 ) Natural gas deferred premiums — — (3,043 ) (3,043 ) — (3,043 ) Noncurrent: Oil derivatives $ — $ (4,552 ) $ — $ (4,552 ) $ — $ (4,552 ) NGL derivatives — — — — — — Natural gas derivatives — (133 ) — (133 ) 1,377 1,244 Oil deferred premiums — — — — — — Natural gas deferred premiums — — (2,386 ) (2,386 ) — (2,386 ) Net derivative position $ — $ 11,976 $ (8,998 ) $ 2,978 $ — $ 2,978 (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 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 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 derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (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, 2016 2017 $ 6,442 2018 2,683 Total $ 9,125 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) 2016 2015 2014 Balance of Level 3 at beginning of period $ (14,619 ) $ (9,285 ) $ (12,684 ) Change in net present value of derivative deferred premiums (232 ) (203 ) (220 ) Total purchases and settlements: Purchases (7,715 ) (10,298 ) (3,800 ) Settlements (1) 13,568 5,167 7,419 Balance of Level 3 at end of period $ (8,998 ) $ (14,619 ) $ (9,285 ) _____________________________________________________________________________ (1) The amount for the year ended December 31, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's restructuring upon their early termination. 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. The Company accounts for the impairment of inventory, if any, at lower of cost or NRV on a nonrecurring basis. For purposes of market measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.j for discussion regarding the Company's impairment of (i) materials and supplies for the years ended December 31, 2016 , 2015 and 2014 , (ii) line-fill for the years ended December 31, 2015 and 2014 and (iii) other fixed assets for the year ended December 31, 2015. 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. The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. See Note 4.a for additional discussion of the Company's acquisitions. |
Net income (loss) per common sh
Net income (loss) per common share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Net income (loss) per common share | Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding stock options. For the years ended December 31, 2016 and 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 loss per common share. The effect of the Company's outstanding stock options was excluded from the calculation of diluted net income per common share for the year ended December 31, 2014. The inclusion of these options would be anti-dilutive due to the following: (i) utilizing the treasury stock method, the sum of the assumed proceeds exceeded the average stock price during the period for the restricted stock option awards granted in February 2013 and (ii) the exercise prices were greater than the average market price during the period for the restricted stock option awards granted in February 2012 and February 2014. 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. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards and performance share awards. The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2016 2015 2014 Net income (loss) (numerator): Net income (loss)—basic and diluted $ (260,739 ) $ (2,209,936 ) $ 265,573 Weighted-average common shares outstanding (denominator): (1) Basic 225,512 199,158 141,312 Non-vested restricted stock awards — — 2,242 Diluted 225,512 199,158 143,554 Net income (loss) per common share: Basic $ (1.16 ) $ (11.10 ) $ 1.88 Diluted $ (1.16 ) $ (11.10 ) $ 1.85 _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the years ended December 31, 2016 and 2015. There were no comparable equity offerings during the year ended December 31, 2014. See Note 3 for additional discussion of the Company's equity offerings. |
Credit risk
Credit risk | 12 Months Ended |
Dec. 31, 2016 | |
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, NGL and natural gas price volatility. 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, 2016 , the Company had three customers that accounted for (i) 48.5% , 23.0% and 17.0% of total oil, NGL and natural gas sales, and (ii) 45.7% , 24.7% and 22.6% of oil, NGL and natural gas sales accounts receivable as of December 31, 2016 . For the year ended December 31, 2015 , the Company had (A) two customers that accounted for (i) 37.5% and 20.3% of total oil, NGL and natural gas sales, and (ii) 35.3% and 23.7% of oil, NGL and natural gas sales accounts receivable, and (B) 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 (A) two customers that accounted for (i) 36.0% and 13.7% of total oil, NGL and natural gas sales, and (ii) 16.4% and 22.5% of oil, NGL and natural gas sales accounts receivable, and (B) 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 . These customers and percentages reported are related to the Company's exploration and production segment, see Note 16. As of December 31, 2016 , the Company had one partner whose joint operations accounts receivable accounted for 19.3% of the Company's total joint operations accounts receivable. 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. These customers and percentages reported are related to the Company's exploration and production segment, see Note 16. For the year ended December 31, 2016 , the Company had one customer that accounted for 100.0% of total sales of purchased oil, with the same customer accounting for 99.7% of purchased oil and other product sales receivable as of December 31, 2016 . 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 . The customer and percentages reported relate to the Company's midstream and marketing segment, see Note 16. The Company's cash balances are insured by the FDIC up to $250,000 per bank. The Company had cash balances on deposit with a certain bank as of December 31, 2016 that exceeded the balance insured by the FDIC in the amount of $40.1 million . Management believes that the risk of loss is mitigated by the bank's reputation and financial position. |
Commitments and contingencies
Commitments and contingencies | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2017 $ 3,127 2018 3,177 2019 3,121 2020 2,031 2021 1,826 Thereafter 7,022 Total $ 20,304 The following has been recorded to rent expense for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Rent expense $ 2,664 $ 2,880 $ 3,042 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 several drilling contracts with a third party to facilitate the Company's drilling plans. Certain of these contracts contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. 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 for the years ended December 31, 2016 or 2015. Future commitments of $7.9 million as of December 31, 2016 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2017 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 of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to deficiency payments. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. 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. During the years ended December 31, 2016, 2015 and 2014, the Company incurred $2.2 million , $5.2 million and $2.6 million , respectively, in deficiency payments which are reported on the consolidated statements of operations on the "Minimum volume commitments" line item. During the year ended December 31, 2015, $3.0 million of the deficiency payments was a result of a negotiated buyout of a minimum volume commitment for future periods to Medallion (as defined below). See Note 14 for additional discussion regarding Medallion, the Company's equity method investment. Future commitments of $441.0 million as of December 31, 2016 are not recorded in the accompanying consolidated balance sheets. 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, 14 and 15.a for the amount of and discussion regarding outstanding commitments to the Company's equity method investment. |
2015 Restructuring
2015 Restructuring | 12 Months Ended |
Dec. 31, 2016 | |
Restructuring and Related Activities [Abstract] | |
Restructuring | 2015 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, 2016 or 2014. |
Variable interest entity
Variable interest entity | 12 Months Ended |
Dec. 31, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Variable interest entity | Variable interest entity An entity is referred to as a variable interest entity ("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 $69.6 million and $99.9 million during the years ended December 31, 2016 and 2015 , respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together, "Medallion"). Medallion's pipeline is located in the Midland Basin. LMS holds 49% of Medallion's 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." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. No such distributions have been received to date. During the years ended December 31, 2016 and 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. During the year ended December 31, 2015, Medallion began recognizing revenue due to its pipeline, located in the Midland Basin, becoming fully 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 15.a for discussion of items included in the Company's 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) 2016 (1) 2015 (2) 2014 Total revenues $ 56,075 $ 38,306 $ 4,623 Gross profit (3) 55,821 30,869 4,623 Net income (loss) (4) 19,601 13,409 (333 ) _____________________________________________________________________________ (1) Medallion's consolidated statement of operations for the year ended December 31, 2016 was unaudited as of February 16, 2017. (2) Medallion's audited consolidated statement of operations for the year ended December 31, 2015 was finalized after the filing of the Company's Annual Report on Form 10-K for the year ended December 31, 2015. (3) Medallion's pipeline did not become operational until 2015, accordingly no costs of goods sold were recorded for the year ended December 31, 2014. (4) 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 Company's consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 includes immaterial prior period Medallion audit adjustments. 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 December 31, (in thousands) 2016 (1) 2015 (2) Assets: Current assets $ 51,390 $ 82,145 Noncurrent assets 460,995 352,121 Total assets $ 512,385 $ 434,266 Liabilities: Current liabilities $ 14,523 $ 41,772 Noncurrent liabilities — — Total liabilities $ 14,523 $ 41,772 _____________________________________________________________________________ (1) Medallion's consolidated balance sheet as of December 31, 2016 was unaudited as of February 16, 2017. (2) Medallion's audited consolidated balance sheet as of December 31, 2015 was finalized after the filing of the Company's Annual Report on Form 10-K for the year ended December 31, 2015. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2016 | |
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) 2016 2015 2014 Midstream service revenues $ — $ 487 $ — Minimum volume commitments $ — $ 5,235 $ 2,552 Interest and other income $ — $ 158 $ — The following table summarizes items included in the consolidated balance sheets related to Medallion as of the dates presented: December 31, (in thousands) 2016 2015 Accounts receivable, net $ — $ 1,163 Accrued capital expenditures $ 586 $ — Other current liabilities (1) $ 118 $ 27,583 _____________________________________________________________________________ (1) Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline, accrued third-party fees due to Medallion as of December 31, 2016 and capital contribution payable to Medallion as of December 31, 2015. b. 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) 2016 2015 2014 Lease operating expenses $ 1,975 $ 1,477 $ 975 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) 2016 2015 2014 Capital expenditures: Oil and natural gas properties $ — $ — $ 57 Midstream service assets $ 20 $ 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) 2016 2015 Accounts payable $ 177 $ 13 c. 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) 2016 2015 2014 Capital expenditures: Oil and natural gas properties $ — $ 2,434 $ 9,518 |
Segments
Segments | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Segments | Segments The Company operates in two business segments: (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 third parties with 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 delivery and takeaway. 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 Eliminations Consolidated company Year ended December 31, 2016 Oil, NGL and natural gas sales $ 427,231 $ 1,141 $ (1,887 ) $ 426,485 Midstream service revenues — 49,971 (41,629 ) 8,342 Sales of purchased oil — 162,551 — 162,551 Total revenues 427,231 213,663 (43,516 ) 597,378 Lease operating expenses, including production and ad valorem tax 115,496 — (11,583 ) 103,913 Midstream service expenses — 29,693 (25,616 ) 4,077 Costs of purchased oil — 169,536 — 169,536 General and administrative (1) 83,901 7,855 — 91,756 Depletion, depreciation and amortization (2) 139,407 8,932 — 148,339 Impairment expense 162,027 — — 162,027 Other operating costs and expenses (3) 5,483 209 — 5,692 Operating loss $ (79,083 ) $ (2,562 ) $ (6,317 ) $ (87,962 ) Other financial information: Income from equity method investee $ — $ 9,403 $ — $ 9,403 Interest expense (4) $ (87,485 ) $ (5,813 ) $ — $ (93,298 ) Capital expenditures (5) $ (368,290 ) $ (5,240 ) $ — $ (373,530 ) Gross property and equipment (6) $ 5,780,137 $ 400,127 $ (8,240 ) $ 6,172,024 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 and ad valorem tax 151,918 — (10,685 ) 141,233 Midstream service expenses — 17,557 (11,711 ) 5,846 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) 12,522 1,178 — 13,700 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 (7) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Income tax benefit (8) $ 171,952 $ 4,993 $ — $ 176,945 Capital expenditures $ (597,086 ) $ (35,515 ) $ — $ (632,601 ) Gross property and equipment (6) $ 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 and ad valorem tax 153,427 — (6,612 ) 146,815 Midstream service expenses — 7,089 (1,660 ) 5,429 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 2,618 — 4,866 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 (8) $ (170,551 ) $ 6,265 $ — $ (164,286 ) Capital expenditures (5) $ (1,279,142 ) $ (60,607 ) $ — $ (1,339,749 ) Gross property and equipment (6) $ 4,841,895 $ 179,355 $ (233 ) $ 5,021,017 _____________________________________________________________________________ (1) General and administrative expense was allocated based on the number of employees in the respective segment as of December 31, 2016 , 2015 and 2014 . Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses 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 as of December 31, 2016 , 2015 and 2014 . (3) Other operating costs and expenses consist of (i) minimum volumes commitments and accretion of asset retirement obligations for the year ended December 31, 2016 , (ii) minimum volume commitments, restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015 and (iii) minimum volume commitments, drilling rig fees and accretion of asset retirement obligations for the year ended December 31, 2014 . These are actual costs and expenses and were not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of December 31, 2016 , 2015 and 2014 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 as of December 31, 2016 , 2015 and 2014 . (5) Capital expenditures exclude acquisition of oil and natural gas properties for the years ended December 31, 2016 and 2014 and acquisition of mineral interests for the year ended December 31, 2014 . (6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $244.0 million , $192.5 million and $58.3 million as of December 31, 2016 , 2015 and 2014 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2016 , 2015 and 2014 . (7) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of 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 as of December 31, 2015 . (8) Income tax expense or benefit for the midstream and marketing segment was calculated by multiplying income or loss before income taxes by 36% for the years ended December 31, 2015 and 2014 . |
Subsidiary guarantors
Subsidiary guarantors | 12 Months Ended |
Dec. 31, 2016 | |
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 balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2016 and 2015 and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2016 , 2015 and 2014 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, 2016, certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost. During the year ended December 31, 2014, certain assets were transferred from Laredo to LMS at historical cost. Condensed consolidating balance sheet December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 70,570 $ 16,297 $ — $ 86,867 Other current assets 65,884 2,026 — 67,910 Oil and natural gas properties, net 1,194,801 9,293 (8,240 ) 1,195,854 Midstream service assets, net — 126,240 — 126,240 Other fixed assets, net 44,221 552 — 44,773 Investment in subsidiaries and equity method investee 376,028 243,953 (376,028 ) 243,953 Other long-term assets 13,065 3,684 — 16,749 Total assets $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346 Accounts payable $ 14,427 $ 627 $ — $ 15,054 Other current liabilities 150,531 22,360 — 172,891 Long-term debt, net 1,353,909 — — 1,353,909 Other long-term liabilities 56,889 3,030 — 59,919 Stockholders' equity 188,813 376,028 (384,268 ) 180,573 Total liabilities and stockholders' equity $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346 Condensed consolidating balance sheet December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 74,613 $ 13,086 $ — $ 87,699 Other current assets 244,477 56 — 244,533 Oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Midstream service assets, net — 131,725 — 131,725 Other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 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 statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense & other, net (93,123 ) — — (93,123 ) Other non-operating income (expense) (73,844 ) 9,381 (15,191 ) (79,654 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 ) Condensed consolidating statement of operations For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 432,478 $ 198,248 $ (24,086 ) $ 606,640 Total costs and expenses 2,897,272 203,278 (22,396 ) 3,078,154 Operating loss (2,464,794 ) (5,030 ) (1,690 ) (2,471,514 ) Interest expense & other, net (102,793 ) — — (102,793 ) Other non-operating income 182,396 6,708 (1,678 ) 187,426 Income (loss) before income tax (2,385,191 ) 1,678 (3,368 ) (2,386,881 ) Income tax benefit 176,945 — — 176,945 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 Intercompany Consolidated Total revenues $ 738,446 $ 63,944 $ (8,505 ) $ 793,885 Total costs and expenses 505,455 70,316 (8,272 ) 567,499 Operating income (loss) 232,991 (6,372 ) (233 ) 226,386 Interest expense & other, net (120,879 ) — — (120,879 ) Other non-operating income (expense) 317,980 (339 ) 6,711 324,352 Income (loss) before income tax 430,092 (6,711 ) 6,478 429,859 Income tax expense (164,286 ) — — (164,286 ) Net income (loss) $ 265,806 $ (6,711 ) $ 6,478 $ 265,573 Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash flows provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672 Condensed consolidating statement of cash flows For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated 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, beginning of period 29,320 1 — 29,321 Cash and cash equivalents, 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 Intercompany Consolidated Net cash flows provided by (used in) 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, beginning of period 198,153 — — 198,153 Cash and cash equivalents, end of period $ 29,320 $ 1 $ — $ 29,321 |
Recently issued or adopted acco
Recently issued or adopted accounting pronouncements | 12 Months Ended |
Dec. 31, 2016 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recently issued or adopted accounting pronouncements | Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The ASUs listed below were either adopted during the year ended December 31, 2016 or the discussion of the ASU was determined to be meaningful to the Company's consolidated financial statements. In August 2016, the FASB issued new guidance in Topic 230, Classification of Certain Cash Receipts and Cash Payments, to address the following cash flow issues: (i) debt prepayment or debt extinguishment costs; (ii) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; (iii) contingent consideration payments made after a business combination; (iv) proceeds from the settlement of insurance claims; (v) proceeds from the settlement of corporate-owned life insurance policies; (vi) distributions received from equity method investees; (vii) beneficial interests in securitization transactions and (viii) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. If practical, the amendments in this ASU should be applied using a retrospective transition method to each period presented. The Company elected to early-adopt this guidance in the third quarter of 2016 on a retrospective basis, and the adoption did not have an effect on its consolidated financial statements. In March 2016, the FASB issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplify the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the third quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy of estimating forfeitures. See Note 7 for discussion of additional accounting consequences related to the adoption of this ASU. In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company expects to provide insight regarding the impact the adoption of this standard will have on its consolidated financial statements in third-quarter 2017. 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 NRV. NRV is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this ASU 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 early-adopted this ASU in the fourth quarter of 2016 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. See Note 2.j for additional discussion of the Company's inventory. In April 2015, the FASB issued new guidance in Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company adopted this ASU in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. 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. In March, April, May and December 2016, the FASB, issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This new guidance 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 the adoption of this standard will have on its consolidated financial statements. |
Subsequent events
Subsequent events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent events | Subsequent events a. Divestiture of oil and natural gas properties On January 17, 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.6 million . After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.4 million net of working capital and closing adjustments and subject to final closing adjustments. A portion of these proceeds were used to pay down $55.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $15.0 million as of the filing of this Annual Report. |
Supplemental oil, NGL and natur
Supplemental oil, NGL and natural gas disclosures (unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental oil, NGL and natural gas disclosures (unaudited) | Supplemental oil, NGL and natural gas disclosures (unaudited) a. Costs incurred in oil and natural gas property acquisition, exploration and development activities 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) 2016 2015 2014 Property acquisition costs: Evaluated (1) $ 5,905 $ — $ 3,873 Unevaluated 119,923 — 9,925 Exploration costs (2) 41,333 20,697 242,284 Development costs (3) 298,942 500,577 1,049,317 Total costs incurred $ 466,103 $ 521,274 $ 1,305,399 _____________________________________________________________________________ (1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the year ended December 31, 2016. See Note 4.a for additional discussion. (2) The Company acquired significant leasehold interests during the year ended December 31, 2014. See Note 4.c for additional discussion. (3) Development costs include $ 2.5 million , $ 13.4 million and $ 6.9 million in asset retirement obligations for the years ended December 31, 2016 , 2015 and 2014 , 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) 2016 2015 2014 Capitalized costs: Evaluated properties $ 5,488,756 $ 5,103,635 $ 4,446,781 Unevaluated properties not being depleted 221,281 140,299 342,731 5,710,037 5,243,934 4,789,512 Less accumulated depletion and impairment (4,514,183 ) (4,218,942 ) (1,586,237 ) Net capitalized costs $ 1,195,854 $ 1,024,992 $ 3,203,275 The following table shows a summary of the unevaluated property costs not being depleted as of December 31, 2016 , by year in which such costs were incurred: (in thousands) 2016 2015 2014 2013 and prior Total Unevaluated properties not being depleted (1) $ 148,647 $ 1,839 $ 67,467 $ 3,328 $ 221,281 _____________________________________________________________________________ (1) Acquisition costs comprise 95% of the $221.3 million in unevaluated properties not being depleted. 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) 2016 2015 2014 Revenues: Oil, NGL and natural gas sales $ 426,485 $ 431,734 $ 737,203 Production costs: Lease operating expenses 75,327 108,341 96,503 Production and ad valorem taxes 28,586 32,892 50,312 103,913 141,233 146,815 Other costs: Depletion 134,105 263,666 237,067 Accretion of asset retirement obligations 3,274 2,236 1,721 Impairment expense 161,064 2,369,477 — Income tax (benefit) expense (1) — (164,141 ) 126,576 Results of operations $ 24,129 $ (2,180,737 ) $ 225,024 _____________________________________________________________________________ (1) During the years ended December 31, 2016 and 2015, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the years ended December 31, 2016 and 2015, income tax benefit is computed utilizing the Company's effective rates of 0% and 7% , respectively, 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 year ended December 31, 2014, income tax expense is computed utilizing the statutory rate. d. Net proved oil, NGL and natural gas reserves Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2016 , 2015 and 2014 . In accordance with SEC regulations, reserves as of December 31, 2016 , 2015 and 2014 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, 2016 and 2015 are reported in three streams: oil, NGL and natural gas. The Company's reserves as of December 31, 2014 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 2016 and 2015 with 2014. 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 years ended December 31, 2016 and 2015 and of oil and liquids-rich natural gas for the year ended December 31, 2014 , all of which are located within the U.S. Year ended December 31, 2016 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Purchases of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945 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 reporting. For period 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 of 2016 and 2015 with 2014. 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 For the year ended December 31, 2016 , the Company's positive revision of 34,082 MBOE of previously estimated quantities is primarily attributable to the combination of positive performance, lower operating costs and other changes to proved developed producing wells. 26,049 MBOE is due to a combination of positive performance, reduction in operating costs and other factors. Previously estimated quantities of 2,292 MBOE were removed due to derecognizing certain proved undeveloped locations and proved developed non-producing targets due to changes in development and drilling plans. In addition, 10,325 MBOE of revisions is due to proved undeveloped locations that were removed from the development plan in prior years, four of these locations were drilled in 2016 and seven are scheduled to be drilled in 2017. Extensions, discoveries and other additions of 24,940 MBOE during the year ended December 31, 2016 consisted of 13,302 MBOE that resulted from new wells drilled during the year and 11,638 MBOE that resulted from new horizontal proved undeveloped locations added during the year. 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. e. Standardized measure of discounted future net cash flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2016 , 2015 and 2014 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 March 31, 2016 and each of the quarterly periods in 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) 2016 2015 2014 Future cash inflows $ 3,548,567 $ 3,269,184 $ 16,663,685 Future production costs (1,238,369 ) (1,321,471 ) (3,616,775 ) Future development costs (290,505 ) (376,701 ) (2,471,985 ) Future income tax expenses — — (2,827,763 ) Future net cash flows 2,019,693 1,571,012 7,747,162 10% discount for estimated timing of cash flows (1,041,199 ) (740,265 ) (4,500,434 ) Standardized measure of discounted future net cash flows $ 978,494 $ 830,747 $ 3,246,728 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) 2016 2015 2014 Standardized measure of discounted future net cash flows, beginning of year $ 830,747 $ 3,246,728 $ 2,322,204 Changes in the year resulting from: Sales, less production costs (322,573 ) (290,501 ) (590,388 ) Revisions of previous quantity estimates 179,297 (2,444,322 ) (320,275 ) Extensions, discoveries and other additions 133,472 192,979 1,340,022 Net change in prices and production costs (80,102 ) (1,495,144 ) 145,740 Changes in estimated future development costs 22,153 (2,974 ) (22,961 ) Previously estimated development costs incurred during the period 189,085 162,237 92,135 Purchases of reserves in place 3,422 — 6,100 Divestitures of reserves in place — (29,149 ) — Accretion of discount 83,075 424,453 305,325 Net change in income taxes — 997,805 (266,757 ) Timing differences and other (60,082 ) 68,635 235,583 Standardized measure of discounted future net cash flows, end of year $ 978,494 $ 830,747 $ 3,246,728 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, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Supplemental quarterly financial data (unaudited) | Supplemental quarterly financial data (unaudited) The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2016 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 106,557 $ 146,773 $ 159,734 $ 184,314 Operating income (loss) (176,788 ) 17,874 25,492 45,460 Net income (loss) (180,371 ) (71,432 ) 9,485 (18,421 ) Net income (loss) per common share: Basic $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 ) Diluted $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 ) 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 ) |
Basis of presentation and sig28
Basis of presentation and significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Net income (loss) per common share | Net income (loss) per common share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding stock options. |
Business Combinations | The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 9. |
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, natural gas liquids ("NGL") and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed in an acquisition and (ix) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. |
Reclassifications | Reclassifications Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2016 presentation. These reclassifications had no impact to previously reported balance sheets, net income (loss) or stockholders' equity. |
Cash and cash equivalents | Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. |
Accounts receivable | Accounts receivable The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company'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. 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. |
Derivatives | Derivatives The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL 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, in prior periods, basis swaps. 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 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 to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment. See Note 20.b for further information regarding unevaluated property costs. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10% . The Securities and Exchange Commission ("SEC") guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for or developing oil, NGL and natural gas properties, are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being 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. |
Midstream service assets | Midstream service assets Midstream service assets, which consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost, are recorded at cost, net of impairment. See Note 2.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 and inventory | 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. |
Debt issuance costs | Debt issuance costs Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. |
Asset retirement obligations | Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation, 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 gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable. |
Fair value measurements | Fair value measurements The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, 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, NGL and natural gas 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. The Company accounts for the impairment of inventory, if any, at lower of cost or NRV on a nonrecurring basis. For purposes of market measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.j for discussion regarding the Company's impairment of (i) materials and supplies for the years ended December 31, 2016 , 2015 and 2014 , (ii) line-fill for the years ended December 31, 2015 and 2014 and (iii) other fixed assets for the year ended December 31, 2015. 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. The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. See Note 4.a for additional discussion of the Company's acquisitions. |
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 | 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, 2016 or 2015. 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. |
Fees received for the operation of jointly-owned oil and natural gas properties | Fees received for the operation of jointly-owned oil and natural gas properties 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. |
Compensation 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 values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included 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. 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. |
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, 2016 or 2015 . |
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, stock option awards, performance share awards, performance unit awards and other awards. During the year ended December 31, 2016, Laredo's stockholders approved an increase in the maximum number of shares of Laredo's common stock issuable under the LTIP from 10,000,000 shares to 24,350,000 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, in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included 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, NGL and natural gas price volatility. 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. |
Variable interest entity | Variable interest entity An entity is referred to as a variable interest entity ("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. 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." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. |
Recently issued or adopted accounting pronouncements | Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The ASUs listed below were either adopted during the year ended December 31, 2016 or the discussion of the ASU was determined to be meaningful to the Company's consolidated financial statements. In August 2016, the FASB issued new guidance in Topic 230, Classification of Certain Cash Receipts and Cash Payments, to address the following cash flow issues: (i) debt prepayment or debt extinguishment costs; (ii) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; (iii) contingent consideration payments made after a business combination; (iv) proceeds from the settlement of insurance claims; (v) proceeds from the settlement of corporate-owned life insurance policies; (vi) distributions received from equity method investees; (vii) beneficial interests in securitization transactions and (viii) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. If practical, the amendments in this ASU should be applied using a retrospective transition method to each period presented. The Company elected to early-adopt this guidance in the third quarter of 2016 on a retrospective basis, and the adoption did not have an effect on its consolidated financial statements. In March 2016, the FASB issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplify the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the third quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy of estimating forfeitures. See Note 7 for discussion of additional accounting consequences related to the adoption of this ASU. In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company expects to provide insight regarding the impact the adoption of this standard will have on its consolidated financial statements in third-quarter 2017. 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 NRV. NRV is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this ASU 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 early-adopted this ASU in the fourth quarter of 2016 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. See Note 2.j for additional discussion of the Company's inventory. In April 2015, the FASB issued new guidance in Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company adopted this ASU in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements. 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. In March, April, May and December 2016, the FASB, issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This new guidance 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 the adoption of this standard will have on its consolidated financial statements. |
Oil and Gas Properties Policy | Beginning in the fourth quarter of 2016, the Company early-adopted a new accounting standard that simplified the measurement of inventory and has applied its provisions prospectively. 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 lower of cost or market ("LCM") to the lower of cost or net realizable value. Net realizable value ("NRV") is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. There was no effect to the consolidated financials statements upon adoption of this guidance. See additional discussion in Note 18. Materials and supplies inventory, which is used in the Company's production activities of oil and natural gas properties and midstream service assets, is carried at the lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory is determined utilizing a replacement cost approach (Level 2). Beginning in 2016, the Company has frac pit water inventory, which is used in developing oil and natural gas properties and is carried at lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other current assets" on the consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach (Level 2). 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 lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the consolidated balance sheets. The net realizable value is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). |
Basis of presentation and sig29
Basis of presentation and significant accounting policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Schedule of components of accounts receivable | Accounts receivable consisted of the following components as of December 31: (in thousands) 2016 2015 Oil, NGL and natural gas sales $ 46,999 $ 25,582 Sales of purchased oil and other products 16,213 11,775 Joint operations, net (1) 12,175 21,375 Matured derivatives 11,059 27,469 Other 421 1,498 Total $ 86,867 $ 87,699 _____________________________________________________________________________ (1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of December 31, 2016 and 2015 . As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of production revenues. |
Schedule of employee-related costs capitalized to oil and gas properties | The following table presents capitalized employee-related costs for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Capitalized employee-related costs $ 19,222 $ 10,688 $ 16,345 |
Schedule of Benchmark Prices and Realized Prices used in the full cost ceiling calculation | The following table presents the Benchmark Prices and Realized Prices as of the dates presented: December 31, 2016 December 31, 2015 December 31, 2014 (1) Benchmark Prices: Oil ($/Bbl) $ 39.25 $ 46.79 $ 91.48 NGL ($/Bbl) $ 18.24 $ 18.75 $ — Natural gas ($/MMBtu) $ 2.33 $ 2.47 $ 4.25 Realized Prices: Oil ($/Bbl) $ 37.44 $ 45.58 $ 89.57 NGL ($/Bbl) $ 11.72 $ 12.50 $ — Natural gas ($/Mcf) $ 1.78 $ 1.89 $ 6.39 _____________________________________________________________________________ (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 2016 and 2015 with prior periods. |
Schedule of midstream service assets | Midstream service assets consisted of the following as of December 31: (in thousands) 2016 2015 Midstream service assets $ 150,629 $ 147,811 Less accumulated depreciation and impairment (24,389 ) (16,086 ) Total, net $ 126,240 $ 131,725 Other fixed assets consisted of the following as of December 31: (in thousands) 2016 2015 Computer hardware and software $ 12,710 $ 12,148 Aircraft 11,352 4,952 Real estate and buildings 7,618 7,618 Leasehold improvements 7,549 7,710 Vehicles 7,413 9,266 Other 5,849 5,105 Depreciable total 52,491 46,799 Less accumulated depreciation and amortization (22,632 ) (18,169 ) Depreciable total, net 29,859 28,630 Land 14,914 14,908 Total, net $ 44,773 $ 43,538 |
Schedule of inventory impairments | The following table presents inventory impairments recorded as of the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Inventory impairments: Materials and supplies (1) $ 963 $ 2,819 $ 1,802 Line-fill (2) — 1,314 2,102 Total inventory impairments $ 963 $ 4,133 $ 3,904 ______________________________________________________________________________ (1) Included in "Impairment expense" in the consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16. (2) Included in "Impairment expense" in the consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16. |
Schedule of future amortization expense of debt issuance costs | Future amortization expense of debt issuance costs as of the period presented is as follows: (in thousands) December 31, 2016 2017 $ 4,238 2018 4,068 2019 2,915 2020 3,005 2021 3,102 Thereafter 1,483 Total $ 18,811 |
Schedule of components of other current assets | Other current assets consisted of the following components as of December 31: (in thousands) 2016 2015 Inventory (1) $ 8,063 $ 6,974 Prepaid expenses and other 6,228 7,600 Total other current assets $ 14,291 $ 14,574 ______________________________________________________________________________ (1) See Note 2.j for discussion of inventory held by the Company. |
Schedule of components of other current liabilities | Other current liabilities consisted of the following components as of December 31: (in thousands) 2016 2015 Accrued compensation and benefits $ 25,947 $ 14,342 Accrued interest payable 24,152 24,208 Purchased oil payable 17,213 12,189 Lease operating expense payable 10,572 13,205 Capital contribution payable to equity method investee (1) — 27,583 Other accrued liabilities 16,331 14,695 Total other current liabilities $ 94,215 $ 106,222 _____________________________________________________________________________ (1) See Notes 14 and 15.a for additional discussion regarding the Company's 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) 2016 2015 Liability at beginning of year $ 46,306 $ 32,198 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 1,528 2,236 Accretion expense 3,483 2,423 Liabilities settled upon plugging and abandonment (1,242 ) (146 ) Liabilities removed due to sale of property — (2,005 ) Revision of estimates (1) 2,132 11,600 Liability at end of year $ 52,207 $ 46,306 _____________________________________________________________________________ (1) The revision of estimates that occurred during the year ended December 31, 2015 was 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) 2016 2015 2014 Fees received for the operation of jointly-owned oil and natural gas properties $ 2,477 $ 3,125 $ 3,265 |
Schedule of non-cash investing and supplemental cash flow information | The following presents the non-cash investing and supplemental cash flow information for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Non-cash investing information: Change in accrued capital expenditures $ (31,027 ) $ (86,369 ) $ 31,913 Change in accrued capital contribution to equity method investee (1) $ (27,583 ) $ 27,583 $ (2,597 ) Capitalized asset retirement cost $ 3,660 $ 13,836 $ 9,118 Supplemental cash flow information: Cash paid for interest, net of $294, $236 and $150 of capitalized interest, respectively $ 89,432 $ 112,457 $ 104,936 ______________________________________________________________________________ (1) See Notes 14 and 15.a for additional discussion of the Company's equity method investee. |
Acquisitions and divestiture (T
Acquisitions and divestiture (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table presents the Company's material 2014 acquisitions. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions, see Note 3 to the consolidated financial statements included in the Company's 2014 Annual Report on Form 10-K. (in thousands) Accounting treatment Cash consideration 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 The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the year ended December 31, 2016: (in thousands) Fair value of acquisitions Fair value of net assets: Evaluated oil and natural gas properties $ 4,800 Unevaluated oil and natural gas properties 119,923 Asset retirement cost 1,105 Total assets acquired 125,828 Asset retirement obligations (1,105 ) Net assets acquired $ 124,723 Fair value of consideration paid for net assets: Cash consideration $ 124,723 |
Operating results from discontinued operations | 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 Oil, NGL and natural gas sales $ 5,138 $ 19,337 Expenses (1) $ 5,791 $ 11,082 _____________________________________________________________________________ (1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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) 2016 2015 2014 Cash payments for interest $ 89,726 $ 112,693 $ 105,086 Amortization of debt issuance costs and other adjustments 3,922 4,243 4,433 Change in accrued interest (56 ) (13,481 ) 11,804 Interest costs incurred 93,592 103,455 121,323 Less capitalized interest (294 ) (236 ) (150 ) Total interest expense $ 93,298 $ 103,219 $ 121,173 |
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, 2016 December 31, 2015 (in thousands) Long-term Fair value Long-term Fair value January 2022 Notes $ 450,000 $ 456,382 $ 450,000 $ 388,301 May 2022 Notes 500,000 521,413 500,000 460,000 March 2023 Notes 350,000 365,649 350,000 301,000 Senior Secured Credit Facility 70,000 69,975 135,000 134,993 Total value of debt $ 1,370,000 $ 1,413,419 $ 1,435,000 $ 1,284,294 |
Schedule of net presentation of the Company's long-term debt and debt issuance cost | The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the consolidated balance sheets as of the periods presented: December 31, 2016 December 31, 2015 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (4,963 ) $ 445,037 $ 450,000 $ (5,939 ) $ 444,061 May 2022 Notes 500,000 (6,164 ) 493,836 500,000 (7,066 ) 492,934 March 2023 Notes 350,000 (4,964 ) 345,036 350,000 (5,769 ) 344,231 Senior Secured Credit Facility (1) 70,000 — 70,000 135,000 — 135,000 Total $ 1,370,000 $ (16,091 ) $ 1,353,909 $ 1,435,000 $ (18,774 ) $ 1,416,226 _____________________________________________________________________________ (1) Debt issuance costs related to our Senior Secured Credit Facility of $2.7 million and $5.2 million as of December 31, 2016 and 2015 , respectively, are recorded net in "Other assets, net" on the consolidated balance sheets. |
Employee compensation (Tables)
Employee compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity and stock-based compensation | |
Schedule of Nonvested Share Activity | The following table reflects the restricted stock award activity for the years ended December 31, 2014, 2015 and 2016: (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, 2013 1,799 $ 19.17 Granted 1,234 $ 25.68 Forfeited (148 ) $ 22.56 Vested (680 ) $ 19.13 Outstanding as of December 31, 2014 2,205 $ 22.63 Granted 1,902 $ 11.98 Forfeited (553 ) $ 20.48 Vested (1,015 ) $ 22.32 Outstanding as of December 31, 2015 2,539 $ 15.26 Granted 2,982 $ 12.28 Forfeited (457 ) $ 13.95 Vested (1) (1,186 ) $ 16.07 Outstanding as of December 31, 2016 3,878 $ 12.88 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the year ended December 31, 2016 was $7.3 million . |
Schedule of Share-based Compensation, Stock Options, Activity | The following table reflects the stock option award activity for the years ended December 31, 2014, 2015 and 2016: (in thousands, except for weighted-average price and weighted-average remaining contractual term) Stock option Weighted-average Weighted-average remaining contractual term (years) Outstanding as of December 31, 2013 1,229 $ 19.32 8.82 Granted 336 $ 25.60 Exercised (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 Granted 1,016 $ 4.18 Exercised (17 ) $ 11.93 Expired or canceled (109 ) $ 21.71 Forfeited (298 ) $ 12.49 Outstanding as of December 31, 2016 2,370 $ 12.54 7.71 Vested and exercisable at end of period (1) 831 $ 19.43 6.25 Expected to vest at end of period (2) 1,536 $ 8.78 8.51 _____________________________________________________________________________ (1) The vested and exercisable stock option awards as of December 31, 2016 had $0.3 million aggregate intrinsic value. (2) The stock option awards expected to vest as of December 31, 2016 had $10.0 million aggregate intrinsic value. |
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions | The assumptions used to estimate the fair value of stock option awards granted during the period are as follows: May 25, 2016 April 1, 2016 February 27, 2015 February 27, 2014 Risk-free interest rate (1) 1.58 % 1.44 % 1.70 % 1.88 % Expected option life (2) 6.25 years 6.25 years 6.25 years 6.25 years Expected volatility (3) 61.94 % 61.34 % 52.59 % 53.21 % Fair value per stock option award $ 9.75 $ 4.44 $ 6.15 $ 13.41 _____________________________________________________________________________ (1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. (2) As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. (3) The Company utilized its own volatility in order to develop the expected volatility for the May 25, 2016, April 1, 2016 and February 27, 2015 grants. The February 27, 2014 grant 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 stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant: Full years of continuous employment Incremental percentage of Cumulative percentage of Less than one — % — % One 25 % 25 % Two 25 % 50 % Three 25 % 75 % Four 25 % 100 % |
Share-based Compensation, Performance Shares Award Unvested Activity [Table Text Block] | The following table reflects the performance share award activity for the years ended December 31, 2014, 2015 and 2016: (in thousands, except for weighted-average grant date fair values) Performance share Weighted-average Outstanding as of December 31, 2013 — $ — Granted 272 $ 28.56 Forfeited — $ — Vested — $ — Outstanding as of December 31, 2014 272 $ 28.56 Granted 602 $ 16.23 Forfeited — $ — Vested — $ — Outstanding as of December 31, 2015 874 $ 20.06 Granted 1,801 $ 17.71 Forfeited (350 ) $ 19.34 Vested — $ — Outstanding as of December 31, 2016 2,325 $ 18.35 |
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 Performance Unit Award compensation expense $ 4,081 $ 409 2012 Performance Unit Award compensation expense — 192 Total performance unit award compensation expense $ 4,081 $ 601 The following has been recorded to stock-based compensation expense for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Restricted stock award compensation $ 21,609 $ 17,534 $ 21,982 Stock option award compensation 4,519 4,074 3,639 Restricted performance share award compensation 9,112 5,222 2,108 Total stock-based compensation, gross 35,240 26,830 27,729 Less amounts capitalized in oil and natural gas properties (6,011 ) (2,321 ) (4,650 ) Total stock-based compensation, net of amounts capitalized $ 29,229 $ 24,509 $ 23,079 |
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) 2016 2015 2014 Contributions $ 1,789 $ 1,847 $ 2,202 |
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: May 25, 2016 April 1, 2016 February 27, 2015 February 27, 2014 Risk-free rate (1) 1.02 % 0.87 % 0.95 % 0.63 % Dividend yield — % — % — % — % Expected volatility (2) 74.73 % 71.54 % 53.78 % 38.21 % Laredo stock closing price as of the grant date $ 12.36 $ 7.71 $ 11.93 $ 25.60 Fair value per performance share $ 17.86 $ 9.83 $ 16.23 $ 28.56 _____________________________________________________________________________ (1) The risk-free rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility over a look-back period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility for these grants. |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of income tax (expense) benefit | Income tax benefit (expense) for the periods presented consisted of the following: For the years ended December 31, (in thousands) 2016 2015 2014 Current taxes: Federal $ — $ — $ — State — — — Deferred taxes: Federal — 152,590 (147,445 ) State — 24,355 (16,841 ) Income tax benefit (expense) $ — $ 176,945 $ (164,286 ) |
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) differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2016, 2015 and 2014 to pre-tax earnings as a result of the following: For the years ended December 31, (in thousands) 2016 2015 2014 Income tax benefit (expense) computed by applying the statutory rate $ 91,259 $ 835,408 $ (150,450 ) Increase in deferred tax valuation allowance (86,569 ) (668,702 ) (1,139 ) Stock-based compensation tax deficiency (4,144 ) (3,274 ) (266 ) State income tax and increase in valuation allowance (370 ) 13,975 (11,099 ) Non-deductible stock-based compensation — (256 ) (509 ) Other items (176 ) (206 ) (823 ) Income tax benefit (expense) $ — $ 176,945 $ (164,286 ) |
Schedule of Deferred Tax Assets and Liabilities | The following table presents significant components of the Company's net deferred tax asset as of December 31: (in thousands) 2016 2015 Net operating loss carry-forward $ 573,521 $ 479,022 Oil and natural gas properties, midstream service assets and other fixed assets 186,473 306,997 Equity method investee (24,293 ) (31,711 ) Stock-based compensation 15,639 11,597 Accrued bonus 8,834 4,763 Materials and supplies impairment 1,982 1,647 Capitalized interest 1,767 2,525 Derivatives 150 (98,675 ) Other 743 1,173 Net deferred tax asset before valuation allowance 764,816 677,338 Valuation allowance (764,816 ) (677,338 ) Net deferred tax asset $ — $ — |
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, 2016 2026 $ 2,741 2027 38,651 2028 228,661 2029 101,932 2030 80,963 Thereafter 1,180,937 Total $ 1,633,885 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative contracts transferred to buyers on sale of assets | During the year ended December 31, 2016 , the following derivatives were terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Contract period Oil: Put portion of the associated collars 2,263,000 $ 80.00 January 2017 - December 2017 |
Summary of derivative contracts unwound in connection with sale of assets | During the year ended December 31, 2016 , the following derivatives were entered into: Aggregate volumes (1) Floor price (2) Ceiling price (2) Contract period Oil: (3) Put 600,000 $ 40.00 $ — May 2016 - December 2016 Put (4) 2,263,000 $ 60.00 $ — January 2017 - December 2017 Swap 1,003,750 $ 51.90 $ 51.90 January 2017 - December 2017 Swap 1,003,750 $ 51.17 $ 51.17 January 2017 - December 2017 Collar 1,168,000 $ 50.00 $ 60.75 January 2017 - December 2017 Put (5) 2,098,750 $ 60.00 $ — January 2017 - December 2018 Swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 NGL: Swap - Ethane 444,000 $ 11.24 $ 11.24 January 2017 - December 2017 Swap - Propane 375,000 $ 22.26 $ 22.26 January 2017 - December 2017 Natural gas: (6) Put 8,040,000 $ 2.50 $ — January 2017 - December 2017 Collar 5,256,000 $ 2.50 $ 3.05 January 2017 - December 2017 Collar 3,723,000 $ 3.00 $ 3.54 January 2017 - December 2017 Collar 4,562,500 $ 3.00 $ 3.55 January 2017 - December 2017 Put 8,220,000 $ 2.50 $ — January 2018 - December 2018 Collar 4,635,500 $ 2.50 $ 3.60 January 2018 - December 2018 _____________________________________________________________________________ (1) Oil and NGL are in Bbl and natural gas is in MMBtu. (2) Oil and NGL are in $/Bbl and natural gas is in $/MMBtu. (3) There were $2.9 million in deferred premiums associated with these contracts upon inception. (4) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception. (5) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. (6) There were $5.1 million in deferred premiums associated with these contracts upon inception. |
Schedule of gains and losses on derivative instruments | The following represents cash settlements received for derivatives, net for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Cash settlements received for matured derivatives, net (1) $ 195,281 $ 255,281 $ 28,241 Cash settlements received for early terminations of derivatives, net (2) 80,000 — 76,660 Cash settlements received for derivatives, net $ 275,281 $ 255,281 $ 104,901 _____________________________________________________________________________ (1) The settlement amount does not include premiums paid attributable to contracts that matured during the respective period. (2) The settlement amount for the year ended December 31, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they derive. |
Schedule of notional amounts of outstanding derivative positions | The following table summarizes open positions as of December 31, 2016 , and represents, as of such date, derivatives in place through December 2018 on annual production volumes: Year 2017 Year 2018 Oil positions: Puts: Hedged volume (Bbl) 1,049,375 1,049,375 Weighted-average price ($/Bbl) $ 60.00 $ 60.00 Swaps: Hedged volume (Bbl) 2,007,500 1,095,000 Weighted-average price ($/Bbl) $ 51.54 $ 52.12 Collars: Hedged volume (Bbl) 3,796,000 — Weighted-average floor price ($/Bbl) $ 56.92 $ — Weighted-average ceiling price ($/Bbl) $ 86.00 $ — Totals: Total volume hedged with floor price (Bbl) 6,852,875 2,144,375 Weighted-average floor price ($/Bbl) $ 55.82 $ 55.98 Total volume hedged with ceiling price (Bbl) 5,803,500 1,095,000 Weighted-average ceiling price ($/Bbl) $ 74.08 $ 52.12 NGL positions: Swaps - Ethane: Hedged volume (Bbl) 444,000 — Weighted-average price ($/Bbl) $ 11.24 $ — Swaps - Propane: Hedged volume (Bbl) 375,000 — Weighted-average price ($/Bbl) $ 22.26 $ — Totals: Total volume hedged with floor price (Bbl) 819,000 — Total volume hedged with ceiling price (Bbl) 819,000 — Natural gas positions: Puts: Hedged volume (MMBtu) 8,040,000 8,220,000 Weighted-average price ($/MMBtu) $ 2.50 $ 2.50 Collars: Hedged volume (MMBtu) 19,016,500 4,635,500 Weighted-average floor price ($/MMBtu) $ 2.86 $ 2.50 Weighted-average ceiling price ($/MMBtu) $ 3.54 $ 3.60 Totals: Total volumed hedged with floor price (MMBtu) 27,056,500 12,855,500 Weighted-average floor price ($/MMBtu) $ 2.75 $ 2.50 Total volume hedged with ceiling price (MMBtu) 19,016,500 4,635,500 Weighted-average ceiling price ($/MMBtu) $ 3.54 $ 3.60 |
Fair value measurements (Tables
Fair value measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 As of December 31, 2016: Assets Current: Oil derivatives $ — $ 22,527 $ — $ 22,527 $ — $ 22,527 NGL derivatives — — — — — — Natural gas derivatives — 270 — 270 (270 ) — Oil deferred premiums — — — — (1,580 ) (1,580 ) Natural gas deferred premiums — — — — — — Noncurrent: Oil derivatives $ — $ 8,718 $ — $ 8,718 $ — $ 8,718 NGL derivatives — — — — — — Natural gas derivatives — 1,377 — 1,377 (1,377 ) — Oil deferred premiums — — — — — — Natural gas deferred premiums — — — — — — Liabilities Current: Oil derivatives $ — $ (9,789 ) $ — $ (9,789 ) $ — $ (9,789 ) NGL derivatives — (2,803 ) — (2,803 ) — (2,803 ) Natural gas derivatives — (3,639 ) — (3,639 ) 270 (3,369 ) Oil deferred premiums — — (3,569 ) (3,569 ) 1,580 (1,989 ) Natural gas deferred premiums — — (3,043 ) (3,043 ) — (3,043 ) Noncurrent: Oil derivatives $ — $ (4,552 ) $ — $ (4,552 ) $ — $ (4,552 ) NGL derivatives — — — — — — Natural gas derivatives — (133 ) — (133 ) 1,377 1,244 Oil deferred premiums — — — — — — Natural gas deferred premiums — — (2,386 ) (2,386 ) — (2,386 ) Net derivative position $ — $ 11,976 $ (8,998 ) $ 2,978 $ — $ 2,978 (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 |
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, 2016 2017 $ 6,442 2018 2,683 Total $ 9,125 |
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) 2016 2015 2014 Balance of Level 3 at beginning of period $ (14,619 ) $ (9,285 ) $ (12,684 ) Change in net present value of derivative deferred premiums (232 ) (203 ) (220 ) Total purchases and settlements: Purchases (7,715 ) (10,298 ) (3,800 ) Settlements (1) 13,568 5,167 7,419 Balance of Level 3 at end of period $ (8,998 ) $ (14,619 ) $ (9,285 ) _____________________________________________________________________________ (1) The amount for the year ended December 31, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's restructuring upon their early termination. |
Net income (loss) per common 36
Net income (loss) per common share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 common share for the periods presented: For the years ended December 31, (in thousands, except for per share data) 2016 2015 2014 Net income (loss) (numerator): Net income (loss)—basic and diluted $ (260,739 ) $ (2,209,936 ) $ 265,573 Weighted-average common shares outstanding (denominator): (1) Basic 225,512 199,158 141,312 Non-vested restricted stock awards — — 2,242 Diluted 225,512 199,158 143,554 Net income (loss) per common share: Basic $ (1.16 ) $ (11.10 ) $ 1.88 Diluted $ (1.16 ) $ (11.10 ) $ 1.85 _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the years ended December 31, 2016 and 2015. There were no comparable equity offerings during the year ended December 31, 2014. See Note 3 for additional discussion of the Company's equity offerings. |
Commitments and contingencies (
Commitments and contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2017 $ 3,127 2018 3,177 2019 3,121 2020 2,031 2021 1,826 Thereafter 7,022 Total $ 20,304 |
Schedule of rent expense | The following has been recorded to rent expense for the periods presented: For the years ended December 31, (in thousands) 2016 2015 2014 Rent expense $ 2,664 $ 2,880 $ 3,042 |
Variable interest entity (Table
Variable interest entity (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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) 2016 (1) 2015 (2) 2014 Total revenues $ 56,075 $ 38,306 $ 4,623 Gross profit (3) 55,821 30,869 4,623 Net income (loss) (4) 19,601 13,409 (333 ) _____________________________________________________________________________ (1) Medallion's consolidated statement of operations for the year ended December 31, 2016 was unaudited as of February 16, 2017. (2) Medallion's audited consolidated statement of operations for the year ended December 31, 2015 was finalized after the filing of the Company's Annual Report on Form 10-K for the year ended December 31, 2015. (3) Medallion's pipeline did not become operational until 2015, accordingly no costs of goods sold were recorded for the year ended December 31, 2014. (4) 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 Company's consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 includes immaterial prior period Medallion audit adjustments. 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 December 31, (in thousands) 2016 (1) 2015 (2) Assets: Current assets $ 51,390 $ 82,145 Noncurrent assets 460,995 352,121 Total assets $ 512,385 $ 434,266 Liabilities: Current liabilities $ 14,523 $ 41,772 Noncurrent liabilities — — Total liabilities $ 14,523 $ 41,772 _____________________________________________________________________________ (1) Medallion's consolidated balance sheet as of December 31, 2016 was unaudited as of February 16, 2017. (2) Medallion's audited consolidated balance sheet as of December 31, 2015 was finalized after the filing of the Company's Annual Report on Form 10-K for the year ended December 31, 2015. |
Related Parties (Tables)
Related Parties (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Oil and gas related party transactions | 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) 2016 2015 2014 Midstream service revenues $ — $ 487 $ — Minimum volume commitments $ — $ 5,235 $ 2,552 Interest and other income $ — $ 158 $ — The following table summarizes items included in the consolidated balance sheets related to Medallion as of the dates presented: December 31, (in thousands) 2016 2015 Accounts receivable, net $ — $ 1,163 Accrued capital expenditures $ 586 $ — Other current liabilities (1) $ 118 $ 27,583 _____________________________________________________________________________ (1) Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline, accrued third-party fees due to Medallion as of December 31, 2016 and capital contribution payable to Medallion as of December 31, 2015. 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) 2016 2015 2014 Lease operating expenses $ 1,975 $ 1,477 $ 975 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) 2016 2015 2014 Capital expenditures: Oil and natural gas properties $ — $ — $ 57 Midstream service assets $ 20 $ 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) 2016 2015 Accounts payable $ 177 $ 13 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) 2016 2015 2014 Capital expenditures: Oil and natural gas properties $ — $ 2,434 $ 9,518 |
Segments (Tables)
Segments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 Eliminations Consolidated company Year ended December 31, 2016 Oil, NGL and natural gas sales $ 427,231 $ 1,141 $ (1,887 ) $ 426,485 Midstream service revenues — 49,971 (41,629 ) 8,342 Sales of purchased oil — 162,551 — 162,551 Total revenues 427,231 213,663 (43,516 ) 597,378 Lease operating expenses, including production and ad valorem tax 115,496 — (11,583 ) 103,913 Midstream service expenses — 29,693 (25,616 ) 4,077 Costs of purchased oil — 169,536 — 169,536 General and administrative (1) 83,901 7,855 — 91,756 Depletion, depreciation and amortization (2) 139,407 8,932 — 148,339 Impairment expense 162,027 — — 162,027 Other operating costs and expenses (3) 5,483 209 — 5,692 Operating loss $ (79,083 ) $ (2,562 ) $ (6,317 ) $ (87,962 ) Other financial information: Income from equity method investee $ — $ 9,403 $ — $ 9,403 Interest expense (4) $ (87,485 ) $ (5,813 ) $ — $ (93,298 ) Capital expenditures (5) $ (368,290 ) $ (5,240 ) $ — $ (373,530 ) Gross property and equipment (6) $ 5,780,137 $ 400,127 $ (8,240 ) $ 6,172,024 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 and ad valorem tax 151,918 — (10,685 ) 141,233 Midstream service expenses — 17,557 (11,711 ) 5,846 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) 12,522 1,178 — 13,700 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 (7) $ (30,056 ) $ (1,481 ) $ — $ (31,537 ) Income tax benefit (8) $ 171,952 $ 4,993 $ — $ 176,945 Capital expenditures $ (597,086 ) $ (35,515 ) $ — $ (632,601 ) Gross property and equipment (6) $ 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 and ad valorem tax 153,427 — (6,612 ) 146,815 Midstream service expenses — 7,089 (1,660 ) 5,429 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 2,618 — 4,866 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 (8) $ (170,551 ) $ 6,265 $ — $ (164,286 ) Capital expenditures (5) $ (1,279,142 ) $ (60,607 ) $ — $ (1,339,749 ) Gross property and equipment (6) $ 4,841,895 $ 179,355 $ (233 ) $ 5,021,017 _____________________________________________________________________________ (1) General and administrative expense was allocated based on the number of employees in the respective segment as of December 31, 2016 , 2015 and 2014 . Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. (2) Depletion, depreciation and amortization were actual expenses 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 as of December 31, 2016 , 2015 and 2014 . (3) Other operating costs and expenses consist of (i) minimum volumes commitments and accretion of asset retirement obligations for the year ended December 31, 2016 , (ii) minimum volume commitments, restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015 and (iii) minimum volume commitments, drilling rig fees and accretion of asset retirement obligations for the year ended December 31, 2014 . These are actual costs and expenses and were not allocated. (4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of December 31, 2016 , 2015 and 2014 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 as of December 31, 2016 , 2015 and 2014 . (5) Capital expenditures exclude acquisition of oil and natural gas properties for the years ended December 31, 2016 and 2014 and acquisition of mineral interests for the year ended December 31, 2014 . (6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $244.0 million , $192.5 million and $58.3 million as of December 31, 2016 , 2015 and 2014 , respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2016 , 2015 and 2014 . (7) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of 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 as of December 31, 2015 . (8) Income tax expense or benefit for the midstream and marketing segment was calculated by multiplying income or loss before income taxes by 36% for the years ended December 31, 2015 and 2014 . |
Subsidiary guarantors (Tables)
Subsidiary guarantors (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Schedule of condensed consolidating balance sheet | Condensed consolidating balance sheet December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 70,570 $ 16,297 $ — $ 86,867 Other current assets 65,884 2,026 — 67,910 Oil and natural gas properties, net 1,194,801 9,293 (8,240 ) 1,195,854 Midstream service assets, net — 126,240 — 126,240 Other fixed assets, net 44,221 552 — 44,773 Investment in subsidiaries and equity method investee 376,028 243,953 (376,028 ) 243,953 Other long-term assets 13,065 3,684 — 16,749 Total assets $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346 Accounts payable $ 14,427 $ 627 $ — $ 15,054 Other current liabilities 150,531 22,360 — 172,891 Long-term debt, net 1,353,909 — — 1,353,909 Other long-term liabilities 56,889 3,030 — 59,919 Stockholders' equity 188,813 376,028 (384,268 ) 180,573 Total liabilities and stockholders' equity $ 1,764,569 $ 402,045 $ (384,268 ) $ 1,782,346 Condensed consolidating balance sheet December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 74,613 $ 13,086 $ — $ 87,699 Other current assets 244,477 56 — 244,533 Oil and natural gas properties, net 1,017,565 9,350 (1,923 ) 1,024,992 Midstream service assets, net — 131,725 — 131,725 Other fixed assets, net 43,210 328 — 43,538 Investment in subsidiaries and equity method investee 301,891 192,524 (301,891 ) 192,524 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 |
Schedule of condensed consolidating statement of operations | Condensed consolidating statement of operations For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 427,028 $ 213,866 $ (43,516 ) $ 597,378 Total costs and expenses 514,483 208,056 (37,199 ) 685,340 Operating income (loss) (87,455 ) 5,810 (6,317 ) (87,962 ) Interest expense & other, net (93,123 ) — — (93,123 ) Other non-operating income (expense) (73,844 ) 9,381 (15,191 ) (79,654 ) Income (loss) before income tax (254,422 ) 15,191 (21,508 ) (260,739 ) Income tax — — — — Net income (loss) $ (254,422 ) $ 15,191 $ (21,508 ) $ (260,739 ) Condensed consolidating statement of operations For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 432,478 $ 198,248 $ (24,086 ) $ 606,640 Total costs and expenses 2,897,272 203,278 (22,396 ) 3,078,154 Operating loss (2,464,794 ) (5,030 ) (1,690 ) (2,471,514 ) Interest expense & other, net (102,793 ) — — (102,793 ) Other non-operating income 182,396 6,708 (1,678 ) 187,426 Income (loss) before income tax (2,385,191 ) 1,678 (3,368 ) (2,386,881 ) Income tax benefit 176,945 — — 176,945 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 Intercompany Consolidated Total revenues $ 738,446 $ 63,944 $ (8,505 ) $ 793,885 Total costs and expenses 505,455 70,316 (8,272 ) 567,499 Operating income (loss) 232,991 (6,372 ) (233 ) 226,386 Interest expense & other, net (120,879 ) — — (120,879 ) Other non-operating income (expense) 317,980 (339 ) 6,711 324,352 Income (loss) before income tax 430,092 (6,711 ) 6,478 429,859 Income tax expense (164,286 ) — — (164,286 ) Net income (loss) $ 265,806 $ (6,711 ) $ 6,478 $ 265,573 |
Schedule of condensed consolidating statement of cash flows | Condensed consolidating statement of cash flows For the year ended December 31, 2016 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash flows provided by operating activities $ 355,458 $ 16,028 $ (15,191 ) $ 356,295 Change in investments between affiliates (73,988 ) 58,797 15,191 — Capital expenditures and other (489,577 ) (74,825 ) — (564,402 ) Net cash flows provided by financing activities 209,625 — — 209,625 Net increase in cash and cash equivalents 1,518 — — 1,518 Cash and cash equivalents, beginning of period 31,153 1 — 31,154 Cash and cash equivalents, end of period $ 32,671 $ 1 $ — $ 32,672 Condensed consolidating statement of cash flows For the year ended December 31, 2015 (in thousands) Laredo Subsidiary Intercompany Consolidated 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, beginning of period 29,320 1 — 29,321 Cash and cash equivalents, 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 Intercompany Consolidated Net cash flows provided by (used in) 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, beginning of period 198,153 — — 198,153 Cash and cash equivalents, end of period $ 29,320 $ 1 $ — $ 29,321 |
Supplemental oil, NGL and nat42
Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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) 2016 2015 2014 Property acquisition costs: Evaluated (1) $ 5,905 $ — $ 3,873 Unevaluated 119,923 — 9,925 Exploration costs (2) 41,333 20,697 242,284 Development costs (3) 298,942 500,577 1,049,317 Total costs incurred $ 466,103 $ 521,274 $ 1,305,399 _____________________________________________________________________________ (1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the year ended December 31, 2016. See Note 4.a for additional discussion. (2) The Company acquired significant leasehold interests during the year ended December 31, 2014. See Note 4.c for additional discussion. (3) Development costs include $ 2.5 million , $ 13.4 million and $ 6.9 million in asset retirement obligations for the years ended December 31, 2016 , 2015 and 2014 , 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) 2016 2015 2014 Capitalized costs: Evaluated properties $ 5,488,756 $ 5,103,635 $ 4,446,781 Unevaluated properties not being depleted 221,281 140,299 342,731 5,710,037 5,243,934 4,789,512 Less accumulated depletion and impairment (4,514,183 ) (4,218,942 ) (1,586,237 ) Net capitalized costs $ 1,195,854 $ 1,024,992 $ 3,203,275 |
Summary of oil and natural gas property costs not being amortized by year | The following table shows a summary of the unevaluated property costs not being depleted as of December 31, 2016 , by year in which such costs were incurred: (in thousands) 2016 2015 2014 2013 and prior Total Unevaluated properties not being depleted (1) $ 148,647 $ 1,839 $ 67,467 $ 3,328 $ 221,281 _____________________________________________________________________________ (1) Acquisition costs comprise 95% of the $221.3 million in unevaluated properties not being depleted. |
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) 2016 2015 2014 Revenues: Oil, NGL and natural gas sales $ 426,485 $ 431,734 $ 737,203 Production costs: Lease operating expenses 75,327 108,341 96,503 Production and ad valorem taxes 28,586 32,892 50,312 103,913 141,233 146,815 Other costs: Depletion 134,105 263,666 237,067 Accretion of asset retirement obligations 3,274 2,236 1,721 Impairment expense 161,064 2,369,477 — Income tax (benefit) expense (1) — (164,141 ) 126,576 Results of operations $ 24,129 $ (2,180,737 ) $ 225,024 _____________________________________________________________________________ (1) During the years ended December 31, 2016 and 2015, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the years ended December 31, 2016 and 2015, income tax benefit is computed utilizing the Company's effective rates of 0% and 7% , respectively, 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 year ended December 31, 2014, 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 years ended December 31, 2016 and 2015 and of oil and liquids-rich natural gas for the year ended December 31, 2014 , all of which are located within the U.S. Year ended December 31, 2016 Oil NGL (MBbl) Gas MBOE Proved developed and undeveloped reserves: Beginning of year 52,639 36,067 221,952 125,698 Revisions of previous estimates 8,726 12,021 80,004 34,082 Extensions, discoveries and other additions 10,741 6,930 43,614 24,940 Purchases of reserves in place 276 116 822 529 Production (8,442 ) (4,784 ) (29,535 ) (18,149 ) End of year 63,940 50,350 316,857 167,100 Proved developed reserves: Beginning of year 40,944 29,349 180,613 100,395 End of year 53,156 42,950 270,291 141,155 Proved undeveloped reserves: Beginning of year 11,695 6,718 41,339 25,303 End of year 10,784 7,400 46,566 25,945 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 reporting. For period 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 of 2016 and 2015 with 2014. 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 |
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) 2016 2015 2014 Future cash inflows $ 3,548,567 $ 3,269,184 $ 16,663,685 Future production costs (1,238,369 ) (1,321,471 ) (3,616,775 ) Future development costs (290,505 ) (376,701 ) (2,471,985 ) Future income tax expenses — — (2,827,763 ) Future net cash flows 2,019,693 1,571,012 7,747,162 10% discount for estimated timing of cash flows (1,041,199 ) (740,265 ) (4,500,434 ) Standardized measure of discounted future net cash flows $ 978,494 $ 830,747 $ 3,246,728 |
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) 2016 2015 2014 Standardized measure of discounted future net cash flows, beginning of year $ 830,747 $ 3,246,728 $ 2,322,204 Changes in the year resulting from: Sales, less production costs (322,573 ) (290,501 ) (590,388 ) Revisions of previous quantity estimates 179,297 (2,444,322 ) (320,275 ) Extensions, discoveries and other additions 133,472 192,979 1,340,022 Net change in prices and production costs (80,102 ) (1,495,144 ) 145,740 Changes in estimated future development costs 22,153 (2,974 ) (22,961 ) Previously estimated development costs incurred during the period 189,085 162,237 92,135 Purchases of reserves in place 3,422 — 6,100 Divestitures of reserves in place — (29,149 ) — Accretion of discount 83,075 424,453 305,325 Net change in income taxes — 997,805 (266,757 ) Timing differences and other (60,082 ) 68,635 235,583 Standardized measure of discounted future net cash flows, end of year $ 978,494 $ 830,747 $ 3,246,728 |
Supplemental quarterly financ43
Supplemental quarterly financial data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of results of operations by quarter | The Company's results by quarter for the periods presented are as follows: Year ended December 31, 2016 (in thousands, except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 106,557 $ 146,773 $ 159,734 $ 184,314 Operating income (loss) (176,788 ) 17,874 25,492 45,460 Net income (loss) (180,371 ) (71,432 ) 9,485 (18,421 ) Net income (loss) per common share: Basic $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 ) Diluted $ (0.85 ) $ (0.33 ) $ 0.04 $ (0.08 ) 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 ) |
Organization (Details)
Organization (Details) | 12 Months Ended |
Dec. 31, 2016segment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of segments | 2 |
Basis of presentation and sig45
Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Accounts receivable | |||
Term of past due balances to be reviewed individually for collectability (in days) | 90 days | ||
Oil, NGL and natural gas sales | $ 46,999 | $ 25,582 | |
Sales of purchased oil and other products | 16,213 | 11,775 | |
Joint operations, net | [1] | 12,175 | 21,375 |
Matured derivatives | 11,059 | 27,469 | |
Other | 421 | 1,498 | |
Total | 86,867 | 87,699 | |
Allowance for doubtful accounts of accounts receivable for joint operations | $ 200 | $ 200 | |
[1] | Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of December 31, 2016 and 2015. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of production revenues. |
Basis of presentation and sig46
Basis of presentation and significant accounting policies - Oil and natural gas properties (Details) | Dec. 31, 2016USD ($)$ / bbl$ / MMcf$ / MMBTU | Dec. 31, 2015USD ($)$ / bbl$ / MMcf$ / MMBTU | Dec. 31, 2014USD ($)$ / bbl$ / MMcf$ / MMBTU | Dec. 31, 2016USD ($)$ / Boe | Dec. 31, 2015USD ($)$ / Boe | Dec. 31, 2014USD ($)$ / Boe | |||
Property, Plant and Equipment [Line Items] | |||||||||
Unevaluated properties not being depleted | $ 221,281,000 | [1] | $ 140,299,000 | $ 342,731,000 | $ 221,281,000 | [1] | $ 140,299,000 | $ 342,731,000 | |
Accumulated depletion and impairment | $ 4,500,000,000 | $ 4,200,000,000 | 4,500,000,000 | 4,200,000,000 | |||||
Depletion expense | $ 134,100,000 | $ 263,700,000 | $ 237,100,000 | ||||||
Depletion expense per physical unit of production (in USD per BOE) | $ / Boe | 7.39 | 16.13 | 20.21 | ||||||
Capitalized employee-related costs | $ 19,222,000 | $ 10,688,000 | $ 16,345,000 | ||||||
Discount rate used in calculating full cost ceiling (as a percent) | 10.00% | ||||||||
Non-cash full cost ceiling impairment (in thousands) | $ 161,100,000 | $ 2,400,000,000 | $ 0 | ||||||
Crude Oil | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl | 39.25 | 46.79 | 91.48 | ||||||
Realized prices (in USD per barrel or Mcf) | $ / bbl | 37.44 | 45.58 | 89.57 | [2] | |||||
Natural Gas Liquids | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Benchmark prices (in USD per barrel or MMBtu) | $ / bbl | 18.24 | 18.75 | 0 | ||||||
Realized prices (in USD per barrel or Mcf) | $ / bbl | 11.72 | 12.50 | 0 | ||||||
Natural Gas | |||||||||
Property, Plant and Equipment [Line Items] | |||||||||
Benchmark prices (in USD per barrel or MMBtu) | $ / MMBTU | 2.33 | 2.47 | 4.25 | ||||||
Realized prices (in USD per barrel or Mcf) | $ / MMcf | 1.78 | 1.89 | 6.39 | [2] | |||||
[1] | (1)Acquisition costs comprise 95% of the $221.3 million in unevaluated properties not being depleted. | ||||||||
[2] | For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2016 and 2015 with prior periods. |
Basis of presentation and sig47
Basis of presentation and significant accounting policies - Midstream service assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Property, Plant and Equipment [Line Items] | ||||
Depletion, depreciation and amortization | [1] | $ 148,339 | $ 277,724 | $ 246,474 |
Property and equipment, net | 1,366,867 | 1,200,255 | ||
Midstream service assets | ||||
Property, Plant and Equipment [Line Items] | ||||
Depletion, depreciation and amortization | 8,300 | 7,500 | $ 4,300 | |
Midstream service assets | 150,629 | 147,811 | ||
Less accumulated depreciation and impairment | (24,389) | (16,086) | ||
Property and equipment, net | $ 126,240 | $ 131,725 | ||
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 actual expenses 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 as of December 31, 2016, 2015 and 2014. |
Basis of presentation and sig48
Basis of presentation and significant accounting policies - Other fixed assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Other fixed assets | ||||
Depreciation, depletion and amortization | [1] | $ 148,339 | $ 277,724 | $ 246,474 |
Property and equipment, net | 1,366,867 | 1,200,255 | ||
Other fixed assets | ||||
Other fixed assets | ||||
Depreciation, depletion and amortization | 5,900 | 6,500 | $ 5,100 | |
Property and equipment, net | 44,773 | 43,538 | ||
Computer hardware and software | ||||
Other fixed assets | ||||
Other fixed assets, net | 12,710 | 12,148 | ||
Aircraft | ||||
Other fixed assets | ||||
Other fixed assets, net | 11,352 | 4,952 | ||
Real estate and buildings | ||||
Other fixed assets | ||||
Other fixed assets, net | 7,618 | 7,618 | ||
Leasehold improvements | ||||
Other fixed assets | ||||
Other fixed assets, net | 7,549 | 7,710 | ||
Vehicles | ||||
Other fixed assets | ||||
Other fixed assets, net | 7,413 | 9,266 | ||
Other | ||||
Other fixed assets | ||||
Other fixed assets, net | 5,849 | 5,105 | ||
Depreciable total, net | ||||
Other fixed assets | ||||
Other fixed assets, net | 52,491 | 46,799 | ||
Less accumulated depreciation and impairment | (22,632) | (18,169) | ||
Property and equipment, net | 29,859 | 28,630 | ||
Land | ||||
Other fixed assets | ||||
Other fixed assets, net | $ 14,914 | $ 14,908 | ||
Minimum | Other fixed assets | ||||
Other fixed assets | ||||
Useful life (in years) | 3 years | |||
Maximum | Other fixed assets | ||||
Other fixed assets | ||||
Useful life (in years) | 10 years | |||
[1] | Depletion, depreciation and amortization were actual expenses 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 as of December 31, 2016, 2015 and 2014. |
Basis of presentation and sig49
Basis of presentation and significant accounting policies - Income tax, Long-lived assets and Cash flow disclosure (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Materials and supplies | ||||
Impairment expense | $ 162,027,000 | $ 2,374,888,000 | $ 3,904,000 | |
Unrecognized tax benefits | 0 | 0 | ||
Accrual for environmental loss contingencies | 0 | 0 | ||
Nonrecurring | Level 2 | ||||
Materials and supplies | ||||
Impairment expense | 963,000 | 4,133,000 | 3,904,000 | |
Materials and Supplies | Nonrecurring | Level 2 | ||||
Materials and supplies | ||||
Impairment expense | [1] | 963,000 | 2,819,000 | 1,802,000 |
Line-fill | Nonrecurring | Level 2 | ||||
Materials and supplies | ||||
Impairment expense | [2] | 0 | 1,314,000 | 2,102,000 |
Compressed Natural Gas station | Nonrecurring | Level 2 | ||||
Materials and supplies | ||||
Impairment expense | $ 0 | $ 1,300,000 | $ 0 | |
[1] | Included in "Impairment expense" in the consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16. | |||
[2] | Included in "Impairment expense" in the consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16. |
Basis of presentation and sig50
Basis of presentation and significant accounting policies - Debt issuance costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Debt Instrument [Line Items] | ||||
Payments of debt issuance costs | $ 0 | $ 6,759 | $ 7,791 | |
Debt issuance cost, net | 18,811 | 23,900 | ||
Accumulated amortization | 21,300 | 17,000 | ||
Write-off of debt issuance costs | 842 | 0 | 124 | |
Deferred finance costs reclassified (from) into | 16,091 | 18,774 | ||
Future amortization expense of deferred loan costs | ||||
2,017 | 4,238 | |||
2,018 | 4,068 | |||
2,019 | 2,915 | |||
2,020 | 3,005 | |||
2,021 | 3,102 | |||
Thereafter | 1,483 | |||
Total | 18,811 | 23,900 | ||
January 2011 | Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Write-off of debt issuance costs | 6,600 | |||
Line of Credit | Secured Debt | ||||
Debt Instrument [Line Items] | ||||
Write-off of debt issuance costs | 800 | $ 100 | ||
Deferred finance costs reclassified (from) into | [1] | $ 0 | $ 0 | |
[1] | Debt issuance costs related to our Senior Secured Credit Facility of $2.7 million and $5.2 million as of December 31, 2016 and 2015, respectively, are recorded net in "Other assets, net" on the consolidated balance sheets. |
Basis of presentation and sig51
Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Inventory | [1] | $ 8,063 | $ 6,974 |
Prepaid expenses and other | 6,228 | 7,600 | |
Other current assets | $ 14,291 | $ 14,574 | |
[1] | See Note 2.j for discussion of inventory held by the Company. |
Basis of presentation and sig52
Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Accrued compensation and benefits | $ 25,947 | $ 14,342 | |
Accrued interest payable | 24,152 | 24,208 | |
Purchased oil payable | 17,213 | 12,189 | |
Lease operating expense payable | 10,572 | 13,205 | |
Capital contribution payable to equity method investee | [1] | 0 | 27,583 |
Other accrued liabilities | 16,331 | 14,695 | |
Total other current liabilities | $ 94,215 | $ 106,222 | |
[1] | See Notes 14 and 15.a for additional discussion regarding the Company's equity method investee. |
Basis of presentation and sig53
Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Liability at beginning of year | $ 46,306 | $ 32,198 | ||
Liabilities added due to acquisitions, drilling, midstream service asset construction and other | 1,528 | 2,236 | ||
Accretion expense | 3,483 | 2,423 | $ 1,787 | |
Liabilities settled upon plugging and abandonment | (1,242) | (146) | ||
Liabilities removed due to sale of property | 0 | (2,005) | ||
Revision of estimates | [1] | 2,132 | 11,600 | |
Liability at end of year | $ 52,207 | $ 46,306 | $ 32,198 | |
[1] | The revision of estimates that occurred during the year ended December 31, 2015 was mainly related to a change in the estimated remaining life per well due to declining commodity prices. |
Basis of presentation and sig54
Basis of presentation and significant accounting policies - Revenue recognition and General and administrative expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
General and administrative expense | |||
Fees received for the operation of jointly-owned oil and natural gas properties | $ 2,477 | $ 3,125 | $ 3,265 |
Basis of presentation and sig55
Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Non-cash investing information: | |||
Change in accrued capital expenditures | $ (31,027) | $ (86,369) | $ 31,913 |
Change in accrued capital contribution to equity method investee | (27,583) | 27,583 | (2,597) |
Capitalized asset retirement cost | 3,660 | 13,836 | 9,118 |
Supplemental cash flow information: | |||
Cash paid for interest, net of $294, $236 and $150 of capitalized interest, respectively | 89,432 | 112,457 | 104,936 |
Capitalized interest | $ 294 | $ 236 | $ 150 |
Equity offerings (Details)
Equity offerings (Details) - USD ($) $ in Thousands | Aug. 09, 2016 | Jul. 19, 2016 | May 16, 2016 | Mar. 05, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Class of Stock [Line Items] | |||||||
Proceeds from issuance of common stock, net of offering costs | $ 276,052 | $ 754,163 | $ 0 | ||||
Common Stock | |||||||
Class of Stock [Line Items] | |||||||
Stock issued during the period (in shares) | 13,000,000 | 10,925,000 | 69,000,000 | 0 | |||
Proceeds from issuance of common stock, net of offering costs | $ 136,300 | $ 119,300 | $ 754,200 | ||||
Common Stock | Warburg Pincus LLC | |||||||
Class of Stock [Line Items] | |||||||
Stock issued during the period (in shares) | 29,800,000 | ||||||
Over-Allotment Option | Common Stock | |||||||
Class of Stock [Line Items] | |||||||
Stock issued during the period (in shares) | 1,950,000 | ||||||
Proceeds from issuance of common stock, net of offering costs | $ 20,500 |
Acquisitions and divestiture -
Acquisitions and divestiture - 2016 Acquisition (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)aBoeproperty | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Business Acquisition [Line Items] | |||
Cash consideration | $ 124,660 | $ 0 | $ 6,493 |
Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Total assets acquired | 125,828 | ||
Asset retirement obligations | (1,105) | ||
Net assets acquired | 124,723 | ||
Cash consideration | $ 124,723 | ||
Area of land (in acres) | a | 9,200 | ||
Number of real estate properties | property | 81 | ||
Production, barrels of oil equivalents | Boe | 300 | ||
Sale price | $ 124,700 | ||
Evaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Fair value of net assets: | 4,800 | ||
Unevaluated oil and natural gas properties | Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Fair value of net assets: | 119,923 | ||
Asset retirement cost | Leasehold Interests Acquired In Western Glasscock And Reagan Counties | |||
Business Acquisition [Line Items] | |||
Fair value of net assets: | $ 1,105 |
Acquisitions and divestiture 58
Acquisitions and divestiture - 2015 Divestiture of non-strategic assets (Details) $ in Millions | Dec. 31, 2016aproperty | Sep. 15, 2015USD ($)aproperty |
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Non-strategic Assets | ||
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 | |
Proceeds after transaction costs | $ | $ 64.8 | |
Leasehold Interests Acquired In Western Glasscock And Reagan Counties | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Area of land (in acres) | a | 9,200 | |
Number of real estate properties | property | 81 |
Acquisitions and divestiture 59
Acquisitions and divestiture - 2015 Divestiture of non-strategic assets - Revenues and Expenses (Details) - Non-strategic Assets - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
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 | |
Expenses | [1] | $ 5,791 | $ 11,082 |
[1] | Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense. |
Acquisitions and divestiture 60
Acquisitions and divestiture - Summary of 2014 acquisitions (Details) - USD ($) $ in Thousands | Aug. 28, 2014 | Jun. 23, 2014 | Jun. 11, 2014 | Feb. 25, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Business Acquisition [Line Items] | |||||||
Payments to acquire mineral rights | $ 0 | $ 0 | $ 7,305 | ||||
Leasehold Interests | |||||||
Business Acquisition [Line Items] | |||||||
Oil and natural gas properties | $ 192,484 | ||||||
Evaluated and unevaluated oil and natural gas properties | |||||||
Business Acquisition [Line Items] | |||||||
Costs incurred | $ 1,800 | $ 4,693 | |||||
Mineral interests | |||||||
Business Acquisition [Line Items] | |||||||
Payments to acquire mineral rights | $ 7,305 |
Debt - Interest expense (Detail
Debt - Interest expense (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Debt Disclosure [Abstract] | ||||
Cash payments for interest | $ 89,726 | $ 112,693 | $ 105,086 | |
Amortization of debt issuance costs and other adjustments | 3,922 | 4,243 | 4,433 | |
Change in accrued interest | (56) | (13,481) | 11,804 | |
Interest costs incurred | 93,592 | 103,455 | 121,323 | |
Less capitalized interest | (294) | (236) | (150) | |
Total interest expense | [1] | $ 93,298 | $ 103,219 | $ 121,173 |
[1] | Interest expense was allocated to the exploration and production segment based on gross property and equipment as of December 31, 2016, 2015 and 2014 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 as of December 31, 2016, 2015 and 2014. |
Debt - March 2023 Notes (Detail
Debt - March 2023 Notes (Details) - Senior Notes - March 2023 Notes - USD ($) | Mar. 18, 2015 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Face amount of debt | $ 350,000,000 | |
Stated rate (as a percent) | 6.25% | |
Net proceeds from offering | $ 343,600,000 | |
Before March 15, 2018 | ||
Debt Instrument [Line Items] | ||
Percentage of aggregate principal amount, that can be redeemed by equity offering | 35.00% | |
Redemption price (as a percent) | 106.25% | |
Debt Instrument, Redemption, Minimum Principal Amount Outstanding Threshold, Percentage | 65.00% | |
Debt instrument redemption principal amount outstanding threshold (in days) | 180 days |
Debt - January 2022 Notes (Deta
Debt - January 2022 Notes (Details) - Senior Notes - Senior Note 5.625% due 2022 | Jan. 23, 2014USD ($) |
Debt Instrument [Line Items] | |
Face amount of debt | $ 450,000,000 |
Stated rate (as a percent) | 5.625% |
Net proceeds from offering | $ 442,200,000 |
Debt - May 2022 Notes (Details)
Debt - May 2022 Notes (Details) - Senior Notes | Apr. 27, 2012USD ($) |
Senior Notes 7.375 Percent Due 2022 | |
Debt Instrument [Line Items] | |
Face amount of debt | $ 500,000,000 |
Stated rate (as a percent) | 7.375% |
May 2022 Notes | 12-month period beginning on May 1, 2017 | |
Debt Instrument [Line Items] | |
Redemption price (as a percent) | 103.688% |
May 2022 Notes | 12-month period beginning on May 1, 2018 | |
Debt Instrument [Line Items] | |
Redemption price (as a percent) | 102.458% |
May 2022 Notes | 12-month period beginning on May 1, 2019 | |
Debt Instrument [Line Items] | |
Redemption price (as a percent) | 101.229% |
May 2022 Notes | beginning on May 1, 2020 and at any time thereafter | |
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, 2016 | Dec. 31, 2015 | [1] | Dec. 31, 2014 | Oct. 19, 2011 | Jan. 20, 2011 |
Debt Instrument [Line Items] | |||||||
Loss on early redemption of debt | $ 0 | $ 31,537,000 | $ 0 | ||||
Senior Notes | Senior Notes 9.5 Percent 2019 | |||||||
Debt Instrument [Line Items] | |||||||
Repurchased amount | $ 550,000,000 | ||||||
Redemption price (as a percent) | 104.75% | ||||||
Loss on early redemption of debt | $ 31,500,000 | ||||||
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 | ||||||
[1] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of 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 as of December 31, 2015. |
Debt - Senior Secured Credit Fa
Debt - Senior Secured Credit Facility (Details) - Secured Debt | 12 Months Ended | |
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Line of Credit | ||
Debt Instrument [Line Items] | ||
Collateral as a percentage of present value of proved reserves | 80.00% | |
Current ratio requirement (not less than) | 1 | |
Consolidated interest coverage ratio (not less than) | 2.50 | |
Line of Credit | ||
Debt Instrument [Line Items] | ||
Borrowing capacity | $ 2,000,000,000 | |
Current borrowing capacity | 815,000,000 | |
Line of credit | $ 70,000,000 | |
Interest rate (as a percent) | 2.31% | |
Letters of credit | ||
Debt Instrument [Line Items] | ||
Borrowing capacity | $ 20,000,000 | |
Letters of credit outstanding | $ 0 | $ 0 |
Minimum | Base Rate | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate (percent) | 0.50% | |
Minimum | Senior Secured Credit Facility | ||
Debt Instrument [Line Items] | ||
Commitment fee on unused capacity (as a percent) | 0.375% | |
Minimum | Senior Secured Credit Facility | London Interbank Offered Rate (LIBOR) | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate (percent) | 1.50% | |
Maximum | Base Rate | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate (percent) | 1.50% | |
Maximum | Senior Secured Credit Facility | ||
Debt Instrument [Line Items] | ||
Commitment fee on unused capacity (as a percent) | 0.50% | |
Maximum | Senior Secured Credit Facility | London Interbank Offered Rate (LIBOR) | ||
Debt Instrument [Line Items] | ||
Basis spread on variable rate (percent) | 2.50% |
Debt - Fair value of debt (Deta
Debt - Fair value of debt (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Long-term debt | ||
Debt Instrument [Line Items] | ||
Debt | $ 1,370,000 | $ 1,435,000 |
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 | 350,000 |
Long-term debt | Line of Credit | Secured Debt | ||
Debt Instrument [Line Items] | ||
Debt | 70,000 | 135,000 |
Fair value | ||
Debt Instrument [Line Items] | ||
Debt | 1,413,419 | 1,284,294 |
Fair value | Senior Notes | Senior Note 5.625% due 2022 | ||
Debt Instrument [Line Items] | ||
Debt | 456,382 | 388,301 |
Fair value | Senior Notes | Senior Notes 7.375 Percent Due 2022 | ||
Debt Instrument [Line Items] | ||
Debt | 521,413 | 460,000 |
Fair value | Senior Notes | March 2023 Notes | ||
Debt Instrument [Line Items] | ||
Debt | 365,649 | 301,000 |
Fair value | Line of Credit | Secured Debt | ||
Debt Instrument [Line Items] | ||
Debt | $ 69,975 | $ 134,993 |
Debt - Debt issuance costs (Det
Debt - Debt issuance costs (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | $ 1,370,000 | $ 1,435,000 | |
Debt issuance costs, net | 16,091 | 18,774 | |
Long-term debt, net | 1,353,909 | 1,416,226 | |
Senior Notes | Senior Note 5.625% due 2022 | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 450,000 | 450,000 | |
Debt issuance costs, net | 4,963 | 5,939 | |
Long-term debt, net | 445,037 | 444,061 | |
Senior Notes | Senior Notes 7.375 Percent Due 2022 | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 500,000 | 500,000 | |
Debt issuance costs, net | 6,164 | 7,066 | |
Long-term debt, net | 493,836 | 492,934 | |
Senior Notes | March 2023 Notes | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | 350,000 | 350,000 | |
Debt issuance costs, net | 4,964 | 5,769 | |
Long-term debt, net | 345,036 | 344,231 | |
Line of Credit | Secured Debt | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Gross | [1] | 70,000 | 135,000 |
Debt issuance costs, net | [1] | 0 | 0 |
Long-term debt, net | [1] | 70,000 | 135,000 |
Other Assets | Line of Credit | Secured Debt | |||
Debt Instrument [Line Items] | |||
Debt issuance costs, net | $ 2,700 | $ 5,200 | |
[1] | Debt issuance costs related to our Senior Secured Credit Facility of $2.7 million and $5.2 million as of December 31, 2016 and 2015, respectively, are recorded net in "Other assets, net" on the consolidated balance sheets. |
Employee compensation - Additio
Employee compensation - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Mar. 31, 2017 | Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
401(k) Plan | |||||||
Equity and stock-based compensation | |||||||
Tax-deferred contributions of eligible employees as a percentage of their annual compensation | 100.00% | ||||||
Employer matching contribution (as a percent) | 6.00% | ||||||
Percentage of employer contributions vested upon receipt | 100.00% | ||||||
Restricted stock awards | |||||||
Equity and stock-based compensation | |||||||
Forfeited (in shares) | (457,000) | (553,000) | (148,000) | ||||
Unrecognized equity and stock-based compensation expense | $ 29.7 | ||||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 10 months 18 days | ||||||
Options outstanding (in shares) | 3,878,000 | 2,539,000 | 2,205,000 | 1,799,000 | |||
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 awards | Non-employee Director | Vesting one year from grant date | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 100.00% | ||||||
Stock option awards | |||||||
Equity and stock-based compensation | |||||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 2 years 9 months 3 days | ||||||
Intrinsic value, options exercisable | $ 0.3 | ||||||
Aggregate intrinsic value, vested and expected to vest | $ 10 | ||||||
Requisite service period (in years) | 4 years | ||||||
Unrecognized stock-based compensation expense | $ 9.8 | ||||||
Options, life of award (in years) | 10 years | ||||||
Post employment, vested awards expiration period (in years) | 1 year | ||||||
Post employment, vested awards expiration period (in days) | 90 days | ||||||
Performance unit awards | |||||||
Equity and stock-based compensation | |||||||
Forfeited (in shares) | (350,000) | 0 | 0 | ||||
Options outstanding (in shares) | 2,325,000 | 874,000 | 272,000 | 0 | |||
Performance Unit Awards | |||||||
Equity and stock-based compensation | |||||||
Cash paid for performance units (in dollars per share) | $ 143.75 | $ 100 | |||||
Performance Unit Awards | February 15, 2013 | |||||||
Equity and stock-based compensation | |||||||
Liability related to performance unit awards | $ 6.4 | ||||||
Long Term Incentive Plan | |||||||
Equity and stock-based compensation | |||||||
Number of shares authorized | 24,350,000 | 10,000,000 | |||||
February 2014, February 2015, May 25, and April 1 Performance Share Awards | Performance unit awards | February 2014, February 2015, May 25, and April 1 | |||||||
Equity and stock-based compensation | |||||||
Unrecognized equity and stock-based compensation expense | $ 26.2 | ||||||
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years) | 1 year 12 months 12 days | ||||||
Requisite service period (in years) | 3 years | ||||||
February 2015 Performance Share Awards | Performance unit awards | February 27, 2015 | |||||||
Equity and stock-based compensation | |||||||
Options outstanding (in shares) | 454,164 | ||||||
February 2014 Performance Share Awards | Performance unit awards | February 27, 2014 | |||||||
Equity and stock-based compensation | |||||||
Forfeited (in shares) | 0 | ||||||
Options outstanding (in shares) | 200,516 | ||||||
February 2013 Awards | Performance Unit Awards | |||||||
Equity and stock-based compensation | |||||||
Exercised (in shares) | 44,481 | ||||||
February 2012 Awards | Performance Unit Awards | |||||||
Equity and stock-based compensation | |||||||
Exercised (in shares) | 27,381 | ||||||
Scenario, Forecast | February 2014 Performance Share Awards | Performance unit awards | February 27, 2014 | |||||||
Equity and stock-based compensation | |||||||
Vesting rights (as a percent) | 75.00% |
Employee compensation - Restric
Employee compensation - Restricted stock awards activity (Details) - Restricted stock awards - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Restricted stock awards | ||||
Outstanding at the beginning of the period (in shares) | 2,539 | 2,205 | 1,799 | |
Granted (in shares) | 2,982 | 1,902 | 1,234 | |
Forfeited (in shares) | (457) | (553) | (148) | |
Vested (in shares) | (1,186) | [1] | (1,015) | (680) |
Outstanding at the end of the period (in shares) | 3,878 | 2,539 | 2,205 | |
Weighted-average grant date fair value (per award) | ||||
Outstanding at the beginning of the period (in dollars per share) | $ 15.26 | $ 22.63 | $ 19.17 | |
Fair value per performance share (in dollars per share) | 12.28 | 11.98 | 25.68 | |
Forfeited (in dollars per share) | 13.95 | 20.48 | 22.56 | |
Vested (in dollars per share) | 16.07 | [1] | 22.32 | 19.13 |
Outstanding at the end of the period (in dollars per share) | $ 12.88 | $ 15.26 | $ 22.63 | |
Intrinsic value of vested restricted stock awards | $ 7.3 | |||
[1] | The total intrinsic value of vested restricted stock awards for the year ended December 31, 2016 was $7.3 million. |
Employee compensation - Restr71
Employee compensation - Restricted stock option awards activity (Details) - Stock option awards - $ / shares shares in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Stock option awards | |||||
Outstanding at the beginning of the period (in shares) | 1,778 | 1,367 | 1,229 | ||
Granted (in shares) | 1,016 | 632 | 336 | ||
Exercised (in shares) | (17) | 0 | (95) | ||
Expired or canceled (in shares) | (109) | (82) | (30) | ||
Forfeited (in shares) | (298) | (139) | (73) | ||
Outstanding at the end of the period (in shares) | 2,370 | 1,778 | 1,367 | 1,229 | |
Vested (in shares) | [1] | 831 | |||
Vested, exercisable, and expected to vest at end of period (in shares) | [2] | 1,536 | |||
Weighted-average price (per option) | |||||
Outstanding at the end of the period (in dollars per share) | $ 17.86 | $ 20.76 | $ 19.32 | ||
Granted (in dollars per share) | 4.18 | 11.93 | 25.60 | ||
Exercised (in dollars per share) | 11.93 | 0 | 19.93 | ||
Expired or canceled (in dollars per share) | 21.71 | 19.92 | 21.15 | ||
Forfeited (in dollars per share) | 12.49 | 18.17 | 19.68 | ||
Outstanding at end of the period (in dollars per share) | 12.54 | $ 17.86 | $ 20.76 | $ 19.32 | |
Vested and exercisable at end of period (in dollars per share) | [1] | 19.43 | |||
Vested, exercisable, and expected to vest at end of period (in dollars per share) | [2] | $ 8.78 | |||
Weighted-average remaining contractual term (years) | |||||
Outstanding at the end of the period | 7 years 8 months 16 days | 7 years 10 months 28 days | 8 years 2 months 1 day | 8 years 9 months 26 days | |
Vested and exercisable at the end of the period | [1] | 6 years 3 months | |||
Vested, exercisable, and expected to vest at end of period | [2] | 8 years 6 months 4 days | |||
[1] | The vested and exercisable stock option awards as of December 31, 2016 had $0.3 million aggregate intrinsic value. | ||||
[2] | The stock option awards expected to vest as of December 31, 2016 had $10.0 million aggregate intrinsic value. |
Employee compensation - Restr72
Employee compensation - Restricted stock option awards assumptions used to estimate the fair value (Details) - Stock option awards | 12 Months Ended | |
Dec. 31, 2016$ / shares | ||
May 25, 2016 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate (as a percent) | 1.58% | [1] |
Expected option life (in years) | 6 years 3 months | [2] |
Expected volatility (as a percent) | 61.94% | [3] |
Fair value per option (in dollars per share) | $ 9.75 | |
April 1, 2016 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Risk-free interest rate (as a percent) | 1.44% | [1] |
Expected option life (in years) | 6 years 3 months | [2] |
Expected volatility (as a percent) | 61.34% | [3] |
Fair value per option (in dollars per share) | $ 4.44 | |
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 | |
[1] | U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award. | |
[2] | As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP. | |
[3] | The Company utilized its own volatility in order to develop the expected volatility for the May 25, 2016, April 1, 2016 and February 27, 2015 grants. The February 27, 2014 grant utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility. |
Employee compensation - Restr73
Employee compensation - Restricted stock option awards full years of continuous employment (Details) - Stock option awards | 12 Months Ended |
Dec. 31, 2016 | |
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 shares award activity (Details) - Performance unit awards - $ / shares shares in Thousands | May 25, 2016 | Apr. 01, 2016 | Feb. 27, 2015 | Feb. 27, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Performance share awards | |||||||
Outstanding at the beginning of the period (in shares) | 874 | 272 | 0 | ||||
Granted (in shares) | 1,801 | 602 | 272 | ||||
Forfeited (in shares) | (350) | 0 | 0 | ||||
Vested (in shares) | 0 | 0 | 0 | ||||
Outstanding at the end of the period (in shares) | 2,325 | 874 | 272 | ||||
Weighted-average grant date fair value (per award) | |||||||
Outstanding at the beginning of the period (in dollars per share) | $ 20.06 | $ 28.56 | $ 0 | ||||
Granted (in dollars per share) | $ 17.86 | $ 9.83 | $ 16.23 | $ 28.56 | 17.71 | 16.23 | 28.56 |
Forfeited (in dollars per share) | 19.34 | 0 | 0 | ||||
Vested (in dollars per share) | 0 | 0 | 0 | ||||
Outstanding at the end of the period (in dollars per share) | $ 18.35 | $ 20.06 | $ 28.56 |
Employee compensation - Perfo75
Employee compensation - Performance share awards assumptions used to estimate the fair value (Details) - Performance unit awards - $ / shares | May 25, 2016 | Apr. 01, 2016 | Feb. 27, 2015 | Feb. 27, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Risk-free interest rate (as a percent) | [1] | 1.02% | 0.87% | 0.95% | 0.63% | |||
Dividend yield (as a percent) | 0.00% | 0.00% | 0.00% | 0.00% | ||||
Expected volatility (as a percent) | [2] | 74.73% | 71.54% | 53.78% | 38.21% | |||
Laredo stock closing price as of the grant date (in dollars per share) | $ 12.36 | $ 7.71 | $ 11.93 | $ 25.60 | ||||
Fair value per performance share (in dollars per share) | $ 17.86 | $ 9.83 | $ 16.23 | $ 28.56 | $ 17.71 | $ 16.23 | $ 28.56 | |
[1] | The risk-free rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. | |||||||
[2] | The Company utilized its own historical volatility over a look-back period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility for these grants. |
Employee compensation - Stock-b
Employee compensation - Stock-based compensation award expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Equity and stock-based compensation | |||
Total stock-based compensation, gross | $ 35,240 | $ 26,830 | $ 27,729 |
Less amounts capitalized in oil and natural gas properties | (6,011) | (2,321) | (4,650) |
Total stock-based compensation, net of amounts capitalized | 29,229 | 24,509 | 23,079 |
Restricted stock awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | 21,609 | 17,534 | 21,982 |
Stock option awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | 4,519 | 4,074 | 3,639 |
Performance unit awards | |||
Equity and stock-based compensation | |||
Total stock-based compensation, gross | $ 9,112 | $ 5,222 | $ 2,108 |
Employee compensation - Perfo77
Employee compensation - Performance unit awards outstanding (Details) - $ / shares | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Performance unit awards | |||||
Restricted stock awards | |||||
Outstanding at the beginning of the period (in shares) | 874,000 | 272,000 | 874,000 | 272,000 | 0 |
Granted (in shares) | 1,801,000 | 602,000 | 272,000 | ||
Forfeited (in shares) | (350,000) | 0 | 0 | ||
Vested (in shares) | 0 | 0 | 0 | ||
Outstanding at the end of the period (in shares) | 2,325,000 | 874,000 | 272,000 | ||
Performance Unit Awards | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Cash paid for performance units (in dollars per share) | $ 143.75 | $ 100 | |||
2016 Performance Share Awards | May 25 and April 1 2016 awards | Performance unit awards | |||||
Restricted stock awards | |||||
Outstanding at the end of the period (in shares) | 1,670,577 |
Employee compensation - Perfo78
Employee compensation - Performance unit award compensation expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | $ 29,229 | $ 24,509 | $ 23,079 |
Performance Unit Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | 4,081 | 601 | |
2013 Performance Unit Award compensation expense | Performance Unit Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | 4,081 | 409 | |
2012 Performance Unit Award compensation expense | Performance Unit Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net stock-based compensation expense | $ 0 | $ 192 |
Employee compensation - Cost re
Employee compensation - Cost recognized for the Company's defined contribution plan (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
401(k) Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Contributions | $ 1,789 | $ 1,847 | $ 2,202 |
Income taxes - Income tax benef
Income taxes - Income tax benefit (expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Current taxes: | |||||
Federal | $ 0 | $ 0 | $ 0 | ||
State | 0 | 0 | 0 | ||
Deferred taxes: | |||||
Federal | 0 | 152,590 | (147,445) | ||
State | 0 | 24,355 | (16,841) | ||
Total income tax benefit (expense) | $ 0 | $ 176,945 | [1] | $ (164,286) | [1] |
[1] | Income tax expense or benefit for the midstream and marketing segment was calculated by multiplying income or loss before income taxes by 36% for the years ended December 31, 2015 and 2014. |
Income taxes - Income tax recon
Income taxes - Income tax reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Income Tax Disclosure [Abstract] | |||||
Income tax benefit (expense) computed by applying the statutory rate | $ 91,259 | $ 835,408 | $ (150,450) | ||
Increase in deferred tax valuation allowance | (86,569) | (668,702) | (1,139) | ||
Stock-based compensation tax deficiency | (4,144) | (3,274) | (266) | ||
State income tax and increase in valuation allowance | (370) | 13,975 | (11,099) | ||
Non-deductible stock-based compensation | 0 | (256) | (509) | ||
Other items | (176) | (206) | (823) | ||
Total income tax benefit (expense) | $ 0 | $ 176,945 | [1] | $ (164,286) | [1] |
[1] | Income tax expense or benefit for the midstream and marketing segment was calculated by multiplying income or loss before income taxes by 36% for the years ended December 31, 2015 and 2014. |
Income taxes - Assets and liabi
Income taxes - Assets and liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Significant components of deferred tax assets | ||
Net operating loss carry-forward | $ 573,521 | $ 479,022 |
Oil and natural gas properties, midstream service assets and other fixed assets | 186,473 | 306,997 |
Equity method investee | (24,293) | (31,711) |
Stock-based compensation | 15,639 | 11,597 |
Accrued bonus | 8,834 | 4,763 |
Materials and supplies impairment | 1,982 | 1,647 |
Capitalized interest | 1,767 | 2,525 |
Derivatives | 150 | (98,675) |
Other | 743 | 1,173 |
Net deferred tax asset before valuation allowance | 764,816 | 677,338 |
Valuation allowance | (764,816) | (677,338) |
Net deferred tax asset | $ 0 | $ 0 |
Income taxes - Operating losses
Income taxes - Operating losses (Details) - Federal $ in Thousands | Dec. 31, 2016USD ($) |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 1,633,885 |
2,026 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 2,741 |
2,027 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 38,651 |
2,028 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 228,661 |
2,029 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 101,932 |
2,030 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | 80,963 |
Thereafter | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carry-forwards | $ 1,180,937 |
Income taxes - Additional Infor
Income taxes - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Examination [Line Items] | |||
Unrecognized tax benefits | $ 0 | $ 0 | |
Federal statutory rate (as a percent) | 35.00% | 35.00% | 35.00% |
Effective tax rate (as a percent) | 0.00% | 7.00% | 38.00% |
Valuation allowance | $ 87,500,000 | $ 676,000,000 | |
Valuation allowance | 764,816,000 | $ 677,338,000 | |
Federal | |||
Income Tax Examination [Line Items] | |||
Net operating loss carry-forwards | 1,633,885,000 | ||
OKLAHOMA | State | |||
Income Tax Examination [Line Items] | |||
Net operating loss carry-forwards | $ 42,600,000 |
Derivatives - Commodity Derivat
Derivatives - Commodity Derivatives (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016USD ($)contract | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Derivative [Line Items] | ||||
Cash settlements received for early terminations of derivatives, net | $ | $ 80,000 | $ 0 | $ 76,660 | |
Derivatives not designated as hedges | ||||
Derivative [Line Items] | ||||
Number of instruments held | contract | 20 | |||
Cash settlements received for early terminations of derivatives, net | $ | [1] | $ 80,000 | $ 0 | $ 76,660 |
Derivatives not designated as hedges | Crude Oil | ||||
Derivative [Line Items] | ||||
Number of restructuring derivatives entered | contract | 2 | |||
[1] | The settlement amount for the year ended December 31, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they derive. |
Derivatives - Commodity deriv86
Derivatives - Commodity derivative contracts' collar floors terminated (Details) - Early Contract Termination - Crude Oil - January 2017 - December 2017 | Dec. 31, 2016bbl$ / bbl |
Derivative [Line Items] | |
Aggregate volumes (in Bbls/MMBtu) | bbl | 2,263,000 |
Floor price (in dollars per unit) | $ / bbl | 80 |
Derivatives - Commodity deriva
Derivatives - Commodity derivative contracts' collar floors entered into (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016USD ($)bblMMBTU$ / bbl$ / MMBTU | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Derivative [Line Items] | ||||
Cash premiums paid for derivatives | $ | $ 89,669 | $ 5,167 | $ 7,419 | |
Put Option May 2016 to December 2016 | Crude Oil | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [1],[2],[3] | 600,000 | ||
Floor price (dollars per Bbl and MMBtu) | [1],[3],[4] | 40 | ||
Put Option January 2017 to December 2017 | Crude Oil | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [2],[3],[5] | 2,263,000 | ||
Floor price (dollars per Bbl and MMBtu) | [3],[4],[5] | 60 | ||
Cash premiums paid for derivatives | $ | $ 40,000 | |||
Put Option January 2017 to December 2017 | Natural Gas | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | MMBTU | [2],[6] | 8,040,000 | ||
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU | [4],[6] | 2.50 | ||
Swap January 2017 to December 2017 | Crude Oil | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [2],[3] | 1,003,750 | ||
Floor price (dollars per Bbl and MMBtu) | [3],[4] | 51.90 | ||
Ceiling price (dollars per MMBtu) | [3],[4] | 51.90 | ||
Swap January 2017 to December 2017 | Crude Oil | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [2],[3] | 1,003,750 | ||
Floor price (dollars per Bbl and MMBtu) | [3],[4] | 51.17 | ||
Ceiling price (dollars per MMBtu) | [3],[4] | 51.17 | ||
Collar January 2017 - December 2017 | Crude Oil | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [2],[3] | 1,168,000 | ||
Floor price (dollars per Bbl and MMBtu) | [3],[4] | 50 | ||
Ceiling price (dollars per MMBtu) | [3],[4] | 60.75 | ||
Collar January 2017 - December 2017 | Natural Gas | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | MMBTU | [2],[6] | 5,256,000 | ||
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU | [4],[6] | 2.50 | ||
Ceiling price (dollars per MMBtu) | $ / MMBTU | [4],[6] | 3.05 | ||
Put Option January 2017 to December 2018 | Crude Oil | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [1],[2],[3] | 2,098,750 | ||
Floor price (dollars per Bbl and MMBtu) | [1],[3],[4] | 60 | ||
Cash premiums paid for derivatives | $ | $ 40,000 | |||
Swap January 2018 to December 2018 | Crude Oil | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [2],[3] | 1,095,000 | ||
Floor price (dollars per Bbl and MMBtu) | [3],[4] | 52.12 | ||
Ceiling price (dollars per MMBtu) | [3],[4] | 52.12 | ||
Collar Two January 2017 - December 2017 | Natural Gas | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | MMBTU | [2],[6] | 3,723,000 | ||
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU | [4],[6] | 3 | ||
Ceiling price (dollars per MMBtu) | $ / MMBTU | [4],[6] | 3.54 | ||
Collar Three January 2017 - December 2017 | Natural Gas | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | MMBTU | [2],[6] | 4,562,500 | ||
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU | [4],[6] | 3 | ||
Ceiling price (dollars per MMBtu) | $ / MMBTU | [4],[6] | 3.55 | ||
Put Option January 2018 to December 2018 | Natural Gas | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | MMBTU | [2],[6] | 8,220,000 | ||
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU | [4],[6] | 2.50 | ||
Collar January 2018 - December 2018 | Natural Gas | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | MMBTU | [2],[6] | 4,635,500 | ||
Floor price (dollars per Bbl and MMBtu) | $ / MMBTU | [4],[6] | 2.50 | ||
Ceiling price (dollars per MMBtu) | $ / MMBTU | [4],[6] | 3.60 | ||
Put Option and Collars January 2017 and 2018 to December 2017 and 2018 | Crude Oil | ||||
Derivative [Line Items] | ||||
Derivative, deferred premium | $ | $ 2,900 | |||
Put Option and Collars January 2017 and 2018 to December 2017 and 2018 | Natural Gas | ||||
Derivative [Line Items] | ||||
Derivative, deferred premium | $ | $ 5,100 | |||
Ethane | Swap January 2017 to December 2017 | Natural Gas Liquids | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [2] | 444,000 | ||
Floor price (dollars per Bbl and MMBtu) | [4] | 11.24 | ||
Ceiling price (dollars per MMBtu) | [4] | 11.24 | ||
Propane | Swap January 2017 to December 2017 | Natural Gas Liquids | ||||
Derivative [Line Items] | ||||
Aggregate volumes (in Bbls/MMBtu) | bbl | [2] | 375,000 | ||
Floor price (dollars per Bbl and MMBtu) | [4] | 22.26 | ||
Ceiling price (dollars per MMBtu) | [4] | 22.26 | ||
[1] | As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception. | |||
[2] | Oil and NGL are in Bbl and natural gas is in MMBtu. | |||
[3] | There were $2.9 million in deferred premiums associated with these contracts upon inception. | |||
[4] | Oil and NGL are in $/Bbl and natural gas is in $/MMBtu. | |||
[5] | As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception. | |||
[6] | There were $5.1 million in deferred premiums associated with these contracts upon inception. |
Derivatives - Additional Inform
Derivatives - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Derivative [Line Items] | ||||
Net proceeds | $ 80,000 | $ 0 | $ 76,660 | |
Derivatives not designated as hedges | ||||
Derivative [Line Items] | ||||
Net proceeds | [1] | $ 80,000 | $ 0 | $ 76,660 |
[1] | The settlement amount for the year ended December 31, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they derive. |
Derivatives - Gain (loss) on d
Derivatives - Gain (loss) on derivatives (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Derivative financial instruments | ||||
Cash settlements received for matured derivatives, net | $ 195,281 | $ 255,281 | $ 28,241 | |
Cash settlements received for early terminations of derivatives, net | 80,000 | 0 | 76,660 | |
Derivatives not designated as hedges | ||||
Derivative financial instruments | ||||
Cash settlements received for matured derivatives, net | [1] | 195,281 | 255,281 | 28,241 |
Cash settlements received for early terminations of derivatives, net | [2] | 80,000 | 0 | 76,660 |
Cash settlements received for derivatives, net | 275,281 | $ 255,281 | $ 104,901 | |
Derivatives not designated as hedges | Commodity derivatives | ||||
Derivative financial instruments | ||||
Deferred premium | $ 4,000 | |||
[1] | The settlement amount does not include premiums paid attributable to contracts that matured during the respective period. | |||
[2] | The settlement amount for the year ended December 31, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they derive. |
Derivatives - Derivative positi
Derivatives - Derivative positions (Details) - Derivatives not designated as hedges | 12 Months Ended |
Dec. 31, 2016MMBTU$ / bbl$ / MMBTUbbl | |
Puts 2017 | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 1,049,375 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 60 |
Puts 2017 | Natural Gas | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 2.50 |
Hedged volume (MMbtu) | MMBTU | 8,040,000 |
Puts 2018 | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 1,049,375 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 60 |
Puts 2018 | Natural Gas | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 2.50 |
Hedged volume (MMbtu) | MMBTU | 8,220,000 |
Swaps 2017 | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 2,007,500 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 51.54 |
Swaps 2018 | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 1,095,000 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 52.12 |
Collars 2017 | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 3,796,000 |
Collars 2017 | Natural Gas | |
Derivative [Line Items] | |
Hedged volume (MMbtu) | MMBTU | 19,016,500 |
Collars 2017 | Floor | Crude Oil | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 56.92 |
Collars 2017 | Floor | Natural Gas | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 2.86 |
Collars 2017 | Ceiling | Crude Oil | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 86 |
Collars 2017 | Ceiling | Natural Gas | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 3.54 |
Collars 2018 | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 0 |
Collars 2018 | Natural Gas | |
Derivative [Line Items] | |
Hedged volume (MMbtu) | MMBTU | 4,635,500 |
Collars 2018 | Floor | Crude Oil | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 0 |
Collars 2018 | Floor | Natural Gas | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 2.50 |
Collars 2018 | Ceiling | Crude Oil | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 0 |
Collars 2018 | Ceiling | Natural Gas | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 3.60 |
Total Commodity Derivatives 2017 | Floor | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 2.75 |
Hedged volume (MMbtu) | MMBTU | 27,056,500 |
Total Commodity Derivatives 2017 | Floor | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 6,852,875 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 55.82 |
Total Commodity Derivatives 2017 | Floor | Natural Gas Liquids | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 819,000 |
Total Commodity Derivatives 2017 | Ceiling | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 3.54 |
Hedged volume (MMbtu) | MMBTU | 19,016,500 |
Total Commodity Derivatives 2017 | Ceiling | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 5,803,500 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 74.08 |
Total Commodity Derivatives 2017 | Ceiling | Natural Gas Liquids | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 819,000 |
Total Commodity Derivatives 2018 | Floor | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 2.50 |
Hedged volume (MMbtu) | MMBTU | 12,855,500 |
Total Commodity Derivatives 2018 | Floor | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 2,144,375 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 55.98 |
Total Commodity Derivatives 2018 | Floor | Natural Gas Liquids | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 0 |
Total Commodity Derivatives 2018 | Ceiling | |
Derivative [Line Items] | |
Weighted-average price (Bbl/MMbtu) | $ / MMBTU | 3.60 |
Hedged volume (MMbtu) | MMBTU | 4,635,500 |
Total Commodity Derivatives 2018 | Ceiling | Crude Oil | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 1,095,000 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 52.12 |
Total Commodity Derivatives 2018 | Ceiling | Natural Gas Liquids | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 0 |
Propane | Swaps 2017 | Natural Gas Liquids | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 375,000 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 22.26 |
Ethane | Swaps 2017 | Natural Gas Liquids | |
Derivative [Line Items] | |
Hedged volume (Bbl) | 444,000 |
Weighted-average price (Bbl/MMbtu) | $ / bbl | 11.24 |
Fair value measurements - Fair
Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Assets | ||
Net fair value presented on the consolidated balance sheets | $ 20,947 | $ 198,805 |
Net fair value presented on the consolidated balance sheets | 8,718 | 77,443 |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (20,993) | 0 |
Net fair value presented on the consolidated balance sheets | (5,694) | 0 |
Recurring | ||
Liabilities | ||
Net derivative position | 2,978 | 276,248 |
Recurring | Level 1 | ||
Liabilities | ||
Net derivative position | 0 | 0 |
Recurring | Level 2 | ||
Liabilities | ||
Net derivative position | 11,976 | 290,867 |
Recurring | Level 3 | ||
Liabilities | ||
Net derivative position | (8,998) | (14,619) |
Fair value | Recurring | ||
Liabilities | ||
Net derivative position | 2,978 | 276,248 |
Crude Oil | Recurring | Commodity derivatives | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 22,527 | 194,940 |
Net fair value presented on the consolidated balance sheets | 8,718 | 80,302 |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (9,789) | 0 |
Net fair value presented on the consolidated balance sheets | (4,552) | 0 |
Crude Oil | Recurring | Deferred Premiums | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | (1,580) | (9,301) |
Net fair value presented on the consolidated balance sheets | 0 | (4,877) |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (1,989) | 0 |
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Natural Gas Liquids | Recurring | Commodity derivatives | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 0 | |
Net fair value presented on the consolidated balance sheets | 0 | |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (2,803) | |
Net fair value presented on the consolidated balance sheets | 0 | |
Natural Gas | Recurring | Commodity derivatives | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 0 | 13,166 |
Net fair value presented on the consolidated balance sheets | 0 | 2,459 |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (3,369) | 0 |
Net fair value presented on the consolidated balance sheets | 1,244 | 0 |
Natural Gas | Recurring | Deferred Premiums | ||
Assets | ||
Net fair value presented on the consolidated balance sheets | 0 | 0 |
Net fair value presented on the consolidated balance sheets | 0 | (441) |
Liabilities | ||
Net fair value presented on the consolidated balance sheets | (3,043) | 0 |
Net fair value presented on the consolidated balance sheets | (2,386) | 0 |
Current: | Crude Oil | Recurring | Commodity derivatives | ||
Assets | ||
Amounts offset | 0 | 0 |
Current: | Crude Oil | Recurring | Deferred Premiums | ||
Assets | ||
Amounts offset | (1,580) | (9,301) |
Current: | Crude Oil | Recurring | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 22,527 | 194,940 |
Current: | Crude Oil | Recurring | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Fair value | Recurring | Commodity derivatives | ||
Assets | ||
Total gross fair value | 22,527 | 194,940 |
Current: | Crude Oil | Fair value | Recurring | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas Liquids | Recurring | Commodity derivatives | ||
Assets | ||
Amounts offset | 0 | |
Current: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Current: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Current: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Current: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Current: | Natural Gas | Recurring | Commodity derivatives | ||
Assets | ||
Amounts offset | (270) | 0 |
Current: | Natural Gas | Recurring | Deferred Premiums | ||
Assets | ||
Amounts offset | 0 | 0 |
Current: | Natural Gas | Recurring | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 270 | 13,166 |
Current: | Natural Gas | Recurring | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Fair value | Recurring | Commodity derivatives | ||
Assets | ||
Total gross fair value | 270 | 13,166 |
Current: | Natural Gas | Fair value | Recurring | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Commodity derivatives | ||
Assets | ||
Amounts offset | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Deferred Premiums | ||
Assets | ||
Amounts offset | 0 | (4,877) |
Noncurrent: | Crude Oil | Recurring | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 8,718 | 80,302 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Fair value | Recurring | Commodity derivatives | ||
Assets | ||
Total gross fair value | 8,718 | 80,302 |
Noncurrent: | Crude Oil | Fair value | Recurring | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas Liquids | Recurring | Commodity derivatives | ||
Assets | ||
Amounts offset | 0 | |
Noncurrent: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas | Recurring | Commodity derivatives | ||
Assets | ||
Amounts offset | (1,377) | 0 |
Noncurrent: | Natural Gas | Recurring | Deferred Premiums | ||
Assets | ||
Amounts offset | 0 | (441) |
Noncurrent: | Natural Gas | Recurring | Level 1 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 1 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 1,377 | 2,459 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Commodity derivatives | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Fair value | Recurring | Commodity derivatives | ||
Assets | ||
Total gross fair value | 1,377 | 2,459 |
Noncurrent: | Natural Gas | Fair value | Recurring | Deferred Premiums | ||
Assets | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Commodity derivatives | ||
Liabilities | ||
Amounts offset | 0 | 0 |
Current: | Crude Oil | Recurring | Deferred Premiums | ||
Liabilities | ||
Amounts offset | 1,580 | 9,301 |
Current: | Crude Oil | Recurring | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (9,789) | 0 |
Current: | Crude Oil | Recurring | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Crude Oil | Recurring | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | (3,569) | (9,301) |
Current: | Crude Oil | Fair value | Recurring | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (9,789) | 0 |
Current: | Crude Oil | Fair value | Recurring | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | (3,569) | (9,301) |
Current: | Natural Gas Liquids | Recurring | Commodity derivatives | ||
Liabilities | ||
Amounts offset | 0 | |
Current: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | |
Current: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (2,803) | |
Current: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | |
Current: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (2,803) | |
Current: | Natural Gas | Recurring | Commodity derivatives | ||
Liabilities | ||
Amounts offset | 270 | 0 |
Current: | Natural Gas | Recurring | Deferred Premiums | ||
Liabilities | ||
Amounts offset | 0 | 0 |
Current: | Natural Gas | Recurring | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (3,639) | 0 |
Current: | Natural Gas | Recurring | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Current: | Natural Gas | Recurring | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | (3,043) | 0 |
Current: | Natural Gas | Fair value | Recurring | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (3,639) | 0 |
Current: | Natural Gas | Fair value | Recurring | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | (3,043) | 0 |
Noncurrent: | Crude Oil | Recurring | Commodity derivatives | ||
Liabilities | ||
Amounts offset | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Deferred Premiums | ||
Liabilities | ||
Amounts offset | 0 | 4,877 |
Noncurrent: | Crude Oil | Recurring | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (4,552) | 0 |
Noncurrent: | Crude Oil | Recurring | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Crude Oil | Recurring | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | (4,877) |
Noncurrent: | Crude Oil | Fair value | Recurring | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (4,552) | 0 |
Noncurrent: | Crude Oil | Fair value | Recurring | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | (4,877) |
Noncurrent: | Natural Gas Liquids | Recurring | Commodity derivatives | ||
Liabilities | ||
Amounts offset | 0 | |
Noncurrent: | Natural Gas Liquids | Recurring | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas Liquids | Recurring | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas Liquids | Recurring | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas Liquids | Fair value | Recurring | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | |
Noncurrent: | Natural Gas | Recurring | Commodity derivatives | ||
Liabilities | ||
Amounts offset | 1,377 | 0 |
Noncurrent: | Natural Gas | Recurring | Deferred Premiums | ||
Liabilities | ||
Amounts offset | 0 | 441 |
Noncurrent: | Natural Gas | Recurring | Level 1 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 1 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (133) | 0 |
Noncurrent: | Natural Gas | Recurring | Level 2 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | 0 | 0 |
Noncurrent: | Natural Gas | Recurring | Level 3 | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | (2,386) | (441) |
Noncurrent: | Natural Gas | Fair value | Recurring | Commodity derivatives | ||
Liabilities | ||
Total gross fair value | (133) | 0 |
Noncurrent: | Natural Gas | Fair value | Recurring | Deferred Premiums | ||
Liabilities | ||
Total gross fair value | $ (2,386) | $ (441) |
Fair value measurements - Narra
Fair value measurements - Narrative (Details) - Deferred Premiums $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Derivatives, deferred premium paid | $ 3.9 |
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, 2016USD ($) |
Fair Value Disclosures [Abstract] | |
2,017 | $ 6,442 |
2,018 | 2,683 |
Total | $ 9,125 |
Fair value measurements - Roll
Fair value measurements - Roll forward (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Changes in assets classified as Level 3 measurements | ||||
Change in net present value of derivative deferred premiums | $ 232 | $ 203 | $ 220 | |
Deferred Premiums | ||||
Changes in assets classified as Level 3 measurements | ||||
Balance of Level 3 at beginning of period | (14,619) | (9,285) | (12,684) | |
Change in net present value of derivative deferred premiums | (232) | (203) | (220) | |
Total purchases and settlements: | ||||
Purchases | (7,715) | (10,298) | (3,800) | |
Settlements | [1] | 13,568 | 5,167 | 7,419 |
Balance of Level 3 at end of period | $ (8,998) | $ (14,619) | $ (9,285) | |
[1] | The amount for the year ended December 31, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's restructuring upon their early termination. |
Net income (loss) per common 95
Net income (loss) per common share - Calculation of net income per share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Net income (numerator): | ||||||||||||
Net income (loss) | $ (18,421) | $ 9,485 | $ (71,432) | $ (180,371) | $ (964,647) | $ (847,783) | $ (397,034) | $ (472) | $ (260,739) | $ (2,209,936) | $ 265,573 | |
Weighted-average common shares outstanding (denominator):(1) | ||||||||||||
Weighted-average common shares outstanding—basic (in shares) | [1] | 225,512 | 199,158 | 141,312 | ||||||||
Weighted-average common shares outstanding—diluted (in shares) | [1] | 225,512 | 199,158 | 143,554 | ||||||||
Net income (loss) per common share: | ||||||||||||
Basic (in dollars per share) | $ (0.08) | $ 0.04 | $ (0.33) | $ (0.85) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ (1.16) | $ (11.10) | $ 1.88 | |
Diluted (in dollars per share) | $ (0.08) | $ 0.04 | $ (0.33) | $ (0.85) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ (1.16) | $ (11.10) | $ 1.85 | |
Restricted stock awards | ||||||||||||
Weighted-average common shares outstanding (denominator):(1) | ||||||||||||
Non-vested restricted stock awards (in shares) | 0 | 0 | 2,242 | |||||||||
[1] | Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the years ended December 31, 2016 and 2015. There were no comparable equity offerings during the year ended December 31, 2014. See Note 3 for additional discussion of the Company's equity offerings. |
Credit risk (Details)
Credit risk (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)customerpartner | Dec. 31, 2015customerpartner | Dec. 31, 2014customer | |
Concentration Risk [Line Items] | |||
Cash balances exceeded by balance insured by FDIC | $ | $ 40.1 | ||
Customers | Total revenues | |||
Concentration Risk [Line Items] | |||
Number of major customers | 3 | ||
Customers | Total revenues | Customer one and two | |||
Concentration Risk [Line Items] | |||
Number of major customers | 2 | 2 | |
Customers | Total revenues | Customer one | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 48.50% | 37.50% | 36.00% |
Customers | Total revenues | Customer two | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 23.00% | 20.30% | 13.70% |
Customers | Total revenues | Customer three | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 17.00% | ||
Customers | Trade Accounts Receivable | |||
Concentration Risk [Line Items] | |||
Number of major customers | 2 | 3 | |
Customers | Purchased Oil Sales | |||
Concentration Risk [Line Items] | |||
Number of major customers | 1 | 1 | 1 |
Concentration risk (as a percent) | 100.00% | 100.00% | 100.00% |
Customers | Purchased Oil and Other Products Sales | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 99.70% | 99.60% | 97.30% |
Credit Concentration Risk | Trade Accounts Receivable | Customer one | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 45.70% | 35.30% | 16.40% |
Credit Concentration Risk | Trade Accounts Receivable | Customer two | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 24.70% | 23.70% | 22.50% |
Credit Concentration Risk | Trade Accounts Receivable | Customer three | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 22.60% | 18.50% | 13.50% |
Credit Concentration Risk | Trade Accounts Receivable | Customer four | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 10.70% | 12.50% | |
Credit Concentration Risk | Trade Accounts Receivable | Customer five | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 11.60% | ||
Credit Concentration Risk | Partner one and two | Joint operations accounts receivable | |||
Concentration Risk [Line Items] | |||
Number of joint interest partners | partner | 1 | 2 | |
Credit Concentration Risk | Partner One | Joint operations accounts receivable | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 19.30% | 18.90% | |
Credit Concentration Risk | Partner Two | Joint operations accounts receivable | |||
Concentration Risk [Line Items] | |||
Concentration risk (as a percent) | 17.10% |
Commitments and contingencies97
Commitments and contingencies (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Lease commitments | |||
2,017 | $ 3,127,000 | ||
2,018 | 3,177,000 | ||
2,019 | 3,121,000 | ||
2,020 | 2,031,000 | ||
2,021 | 1,826,000 | ||
Thereafter | 7,022,000 | ||
Total | 20,304,000 | ||
Rent expense | |||
Rent expense | 2,664,000 | $ 2,880,000 | $ 3,042,000 |
Drilling rig fees | 0 | 0 | 527,000 |
Minimum volume commitments | 2,209,000 | $ 5,235,000 | $ 2,552,000 |
Drilling Contracts | |||
Rent expense | |||
Future commitments | 7,900,000 | ||
Firm Sale And Transportation Commitments | |||
Rent expense | |||
Future commitments | $ 441,000,000 |
2015 Restructuring (Details)
2015 Restructuring (Details) | Jan. 20, 2015employee | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Restructuring Cost and Reserve [Line Items] | ||||
Restructuring expenses | $ | $ 0 | $ 6,042,000 | $ 0 | |
Reduction in Force | ||||
Restructuring Cost and Reserve [Line Items] | ||||
Restructuring expenses | $ | $ 0 | $ 6,000,000 | $ 0 | |
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 |
Variable interest entity (Detai
Variable interest entity (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Equity Method Investments [Line Items] | |||
Contributions to equity method investee | $ 69,609,000 | $ 99,855,000 | $ 55,164,000 |
Minimum volume commitments | 2,209,000 | 5,235,000 | 2,552,000 |
Variable Interest Entity, Not Primary Beneficiary | Medallion Gathering And Processing LLC | |||
Schedule of Equity Method Investments [Line Items] | |||
Contributions to equity method investee | $ 69,600,000 | 99,900,000 | |
Ownership percentage | 49.00% | ||
Ownership percentage held by investment partner | 51.00% | ||
Percentage required for key decisions | 75.00% | ||
Minimum volume commitments | $ 3,000,000 | ||
Cost of goods sold | $ 0 |
Variable interest entity - Summ
Variable interest entity - Summarized financial information (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Statement of Operations | ||||||
Total revenues | $ 56,075 | [1] | $ 38,306 | [2] | $ 4,623 | |
Gross profit | [3] | 55,821 | [1] | 30,869 | [2] | 4,623 |
Net income (loss) | [4] | 19,601 | [1] | 13,409 | [2] | $ (333) |
Assets: | ||||||
Current assets | 51,390 | [5] | 82,145 | [6] | ||
Noncurrent assets | 460,995 | [5] | 352,121 | [6] | ||
Total assets | 512,385 | [5] | 434,266 | [6] | ||
Liabilities: | ||||||
Current liabilities | 14,523 | [5] | 41,772 | [6] | ||
Noncurrent liabilities | 0 | [5] | 0 | [6] | ||
Total liabilities | $ 14,523 | [5] | $ 41,772 | [6] | ||
[1] | Medallion's consolidated statement of operations for the year ended December 31, 2016 was unaudited as of February 16, 2017. | |||||
[2] | Medallion's audited consolidated statement of operations for the year ended December 31, 2015 was finalized after the filing of the Company's Annual Report on Form 10-K for the year ended December 31, 2015. | |||||
[3] | Medallion's pipeline did not become operational until 2015, accordingly no costs of goods sold were recorded for the year ended December 31, 2014. | |||||
[4] | 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 Company's consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 includes immaterial prior period Medallion audit adjustments. | |||||
[5] | Medallion's consolidated balance sheet as of December 31, 2016 was unaudited as of February 16, 2017. | |||||
[6] | Medallion's audited consolidated balance sheet as of December 31, 2015 was finalized after the filing of the Company's Annual Report on Form 10-K for the year ended December 31, 2015. |
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Midstream service revenues | |||
Related Party Transaction [Line Items] | |||
Related party revenues | $ 0 | $ 487 | $ 0 |
Minimum volume commitments | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Expenses from Transactions with Related Party | 0 | 5,235 | 2,552 |
Interest and other income | |||
Related Party Transaction [Line Items] | |||
Related party revenues | $ 0 | $ 158 | $ 0 |
Related Parties - Consolidat102
Related Parties - Consolidated balance sheets related to Medallion (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Accounts receivable, net | $ 86,867 | $ 87,699 | |
Accrued capital expenditures | [1] | 0 | 27,583 |
Accounts Receivable | Medallion Gathering And Processing LLC | Equity Method Investee | |||
Related Party Transaction [Line Items] | |||
Accounts receivable, net | 0 | 1,163 | |
Accrued Capital Expenditures | Medallion Gathering And Processing LLC | Equity Method Investee | |||
Related Party Transaction [Line Items] | |||
Accrued capital expenditures | 586 | 0 | |
Other Current Liabilities | Medallion Gathering And Processing LLC | Equity Method Investee | |||
Related Party Transaction [Line Items] | |||
Other current liabilities | [2] | $ 118 | $ 27,583 |
[1] | See Notes 14 and 15.a for additional discussion regarding the Company's equity method investee. | ||
[2] | Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline, accrued third-party fees due to Medallion as of December 31, 2016 and capital contribution payable to Medallion as of December 31, 2015. |
Related Parties - Lease operati
Related Parties - Lease operating expenses related to Archrock Partners (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Archrock Partners, L.P. | Affiliated Entity | Lease Operating Expenses | |||
Related Party Transaction [Line Items] | |||
Lease operating expenses | $ 1,975 | $ 1,477 | $ 975 |
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Midstream service assets | $ 5,240 | $ 35,459 | $ 60,548 |
Archrock Partners, L.P. | Affiliated Entity | Oil and natural gas properties | |||
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | 0 | 0 | 57 |
Archrock Partners, L.P. | Affiliated Entity | Midstream service assets | |||
Related Party Transaction [Line Items] | |||
Midstream service assets | $ 20 | $ 64 | $ 833 |
Related Parties - Accounts paya
Related Parties - Accounts payable from Archrock Partners (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Accounts Payable | Archrock Partners, L.P. | Affiliated Entity | ||
Related Party Transaction [Line Items] | ||
Accounts payable | $ 177 | $ 13 |
Related Parties - Capitalize106
Related Parties - Capitalized oil and natural gas properties related to H&P (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Helmerich & Payne, Inc. | Affiliated Entity | |||
Related Party Transaction [Line Items] | |||
Oil and natural gas properties | $ 0 | $ 2,434 | $ 9,518 |
Segments - Selected financial i
Segments - Selected financial information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | $ 426,485 | $ 431,734 | $ 737,203 | ||||||||||||
Midstream service revenues | 8,342 | 6,548 | 2,245 | ||||||||||||
Sales of purchased oil | 162,551 | 168,358 | 54,437 | ||||||||||||
Total revenues | $ 184,314 | $ 159,734 | $ 146,773 | $ 106,557 | $ 123,275 | $ 150,340 | $ 182,331 | $ 150,694 | 597,378 | 606,640 | 793,885 | ||||
Lease operating expenses, including production and ad valorem tax | 103,913 | 141,233 | 146,815 | ||||||||||||
Midstream service expenses | 4,077 | 5,846 | 5,429 | ||||||||||||
Costs of purchased oil | 169,536 | 174,338 | 53,967 | ||||||||||||
General and administrative | [1] | 91,756 | 90,425 | 106,044 | |||||||||||
Depletion, depreciation and amortization | [2] | 148,339 | 277,724 | 246,474 | |||||||||||
Impairment expense | 162,027 | 2,374,888 | 3,904 | ||||||||||||
Other operating costs and expenses | [3] | 5,692 | 13,700 | 4,866 | |||||||||||
Operating income (loss) | 45,460 | $ 25,492 | $ 17,874 | $ (176,788) | (1,015,677) | $ (927,859) | $ (501,480) | $ (26,498) | (87,962) | (2,471,514) | 226,386 | ||||
Income (loss) from equity method investee | 9,403 | 6,799 | (192) | ||||||||||||
Interest expense | [4] | (93,298) | (103,219) | (121,173) | |||||||||||
Loss on early redemption of debt | 0 | (31,537) | [5] | 0 | |||||||||||
Income tax (expense) benefit | 0 | 176,945 | [6] | (164,286) | [6] | ||||||||||
Capital expenditures | (373,530) | [7] | (632,601) | (1,339,749) | [7] | ||||||||||
Gross property and equipment | [8] | 6,172,024 | 5,645,976 | 6,172,024 | 5,645,976 | 5,021,017 | |||||||||
Operating Segments | Exploration and production | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | 427,231 | 432,711 | 738,455 | ||||||||||||
Midstream service revenues | 0 | 0 | 0 | ||||||||||||
Sales of purchased oil | 0 | 0 | 0 | ||||||||||||
Total revenues | 427,231 | 432,711 | 738,455 | ||||||||||||
Lease operating expenses, including production and ad valorem tax | 115,496 | 151,918 | 153,427 | ||||||||||||
Midstream service expenses | 0 | 0 | 0 | ||||||||||||
Costs of purchased oil | 0 | 0 | 0 | ||||||||||||
General and administrative | [1] | 83,901 | 82,251 | 99,075 | |||||||||||
Depletion, depreciation and amortization | [2] | 139,407 | 269,631 | 241,834 | |||||||||||
Impairment expense | 162,027 | 2,372,296 | 1,802 | ||||||||||||
Other operating costs and expenses | [3] | 5,483 | 12,522 | 2,248 | |||||||||||
Operating income (loss) | (79,083) | (2,455,907) | 240,069 | ||||||||||||
Income (loss) from equity method investee | 0 | 0 | 0 | ||||||||||||
Interest expense | [4] | (87,485) | (98,040) | (117,560) | |||||||||||
Loss on early redemption of debt | [5] | (30,056) | |||||||||||||
Income tax (expense) benefit | [6] | 171,952 | (170,551) | ||||||||||||
Capital expenditures | (368,290) | [7] | (597,086) | (1,279,142) | [7] | ||||||||||
Gross property and equipment | [8] | 5,780,137 | 5,302,716 | 5,780,137 | 5,302,716 | 4,841,895 | |||||||||
Operating Segments | Midstream and marketing | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | 1,141 | 1,692 | 1,660 | ||||||||||||
Midstream service revenues | 49,971 | 27,965 | 7,838 | ||||||||||||
Sales of purchased oil | 162,551 | 168,358 | 54,437 | ||||||||||||
Total revenues | 213,663 | 198,015 | 63,935 | ||||||||||||
Lease operating expenses, including production and ad valorem tax | 0 | 0 | 0 | ||||||||||||
Midstream service expenses | 29,693 | 17,557 | 7,089 | ||||||||||||
Costs of purchased oil | 169,536 | 174,338 | 53,967 | ||||||||||||
General and administrative | [1] | 7,855 | 8,174 | 6,969 | |||||||||||
Depletion, depreciation and amortization | [2] | 8,932 | 8,093 | 4,640 | |||||||||||
Impairment expense | 0 | 2,592 | 2,102 | ||||||||||||
Other operating costs and expenses | [3] | 209 | 1,178 | 2,618 | |||||||||||
Operating income (loss) | (2,562) | (13,917) | (13,450) | ||||||||||||
Income (loss) from equity method investee | 9,403 | 6,799 | (192) | ||||||||||||
Interest expense | [4] | (5,813) | (5,179) | (3,613) | |||||||||||
Loss on early redemption of debt | [5] | (1,481) | |||||||||||||
Income tax (expense) benefit | [6] | 4,993 | 6,265 | ||||||||||||
Capital expenditures | (5,240) | [7] | (35,515) | (60,607) | [7] | ||||||||||
Gross property and equipment | [8] | 400,127 | 345,183 | 400,127 | 345,183 | 179,355 | |||||||||
Eliminations | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Oil, NGL and natural gas sales | (1,887) | (2,669) | (2,912) | ||||||||||||
Midstream service revenues | (41,629) | (21,417) | (5,593) | ||||||||||||
Sales of purchased oil | 0 | 0 | 0 | ||||||||||||
Total revenues | (43,516) | (24,086) | (8,505) | ||||||||||||
Lease operating expenses, including production and ad valorem tax | (11,583) | (10,685) | (6,612) | ||||||||||||
Midstream service expenses | (25,616) | (11,711) | (1,660) | ||||||||||||
Costs of purchased oil | 0 | 0 | 0 | ||||||||||||
General and administrative | [1] | 0 | 0 | 0 | |||||||||||
Depletion, depreciation and amortization | [2] | 0 | 0 | 0 | |||||||||||
Impairment expense | 0 | 0 | 0 | ||||||||||||
Other operating costs and expenses | [3] | 0 | 0 | 0 | |||||||||||
Operating income (loss) | (6,317) | (1,690) | (233) | ||||||||||||
Income (loss) from equity method investee | 0 | 0 | 0 | ||||||||||||
Interest expense | [4] | 0 | 0 | 0 | |||||||||||
Loss on early redemption of debt | [5] | 0 | |||||||||||||
Income tax (expense) benefit | [6] | 0 | 0 | ||||||||||||
Capital expenditures | 0 | [7] | 0 | 0 | [7] | ||||||||||
Gross property and equipment | [8] | $ (8,240) | $ (1,923) | $ (8,240) | $ (1,923) | $ (233) | |||||||||
[1] | General and administrative expense was allocated based on the number of employees in the respective segment as of December 31, 2016, 2015 and 2014. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment. | ||||||||||||||
[2] | Depletion, depreciation and amortization were actual expenses 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 as of December 31, 2016, 2015 and 2014. | ||||||||||||||
[3] | Other operating costs and expenses consist of (i) minimum volumes commitments and accretion of asset retirement obligations for the year ended December 31, 2016, (ii) minimum volume commitments, restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015 and (iii) minimum volume commitments, drilling rig fees and accretion of asset retirement obligations for the year ended December 31, 2014. These are actual costs and expenses and were not allocated. | ||||||||||||||
[4] | Interest expense was allocated to the exploration and production segment based on gross property and equipment as of December 31, 2016, 2015 and 2014 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 as of December 31, 2016, 2015 and 2014. | ||||||||||||||
[5] | Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of 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 as of December 31, 2015. | ||||||||||||||
[6] | Income tax expense or benefit for the midstream and marketing segment was calculated by multiplying income or loss before income taxes by 36% for the years ended December 31, 2015 and 2014. | ||||||||||||||
[7] | Capital expenditures exclude acquisition of oil and natural gas properties for the years ended December 31, 2016 and 2014 and acquisition of mineral interests for the year ended December 31, 2014. | ||||||||||||||
[8] | Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $244.0 million, $192.5 million and $58.3 million as of December 31, 2016, 2015 and 2014, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2016, 2015 and 2014. |
Segments - Additional informati
Segments - Additional information (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2015 | Dec. 31, 2016USD ($)segment | Dec. 31, 2014USD ($) | Dec. 31, 2015USD ($) | |
Segment Reporting Information [Line Items] | ||||
Number of segments | segment | 2 | |||
Investment in equity method investee | $ 243,953 | $ 192,524 | ||
Midstream and marketing | ||||
Segment Reporting Information [Line Items] | ||||
Investment in equity method investee | $ 244,000 | $ 58,300 | $ 192,500 | |
Operating Segments | Midstream Segment | ||||
Segment Reporting Information [Line Items] | ||||
Effective tax rate (as a percent) | 36.00% | 36.00% |
Subsidiary guarantors - Condens
Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Subsidiary guarantees | ||||
Accounts receivable, net | $ 86,867 | $ 87,699 | ||
Other current assets | 67,910 | 244,533 | ||
Oil and natural gas properties, net | 1,195,854 | 1,024,992 | ||
Midstream service assets, net | 126,240 | 131,725 | ||
Other fixed assets, net | 44,773 | 43,538 | ||
Investment in subsidiaries and equity method investee | 243,953 | 192,524 | ||
Other long-term assets | 16,749 | 88,276 | ||
Total assets | 1,782,346 | 1,813,287 | ||
Accounts payable | 15,054 | 14,181 | ||
Other current liabilities | 172,891 | 202,634 | ||
Long-term debt, net | 1,353,909 | 1,416,226 | ||
Other long-term liabilities | 59,919 | 48,799 | ||
Stockholders' equity | 180,573 | 131,447 | $ 1,563,201 | $ 1,272,256 |
Total liabilities and stockholders' equity | 1,782,346 | 1,813,287 | ||
Reportable Legal Entities | Laredo | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 70,570 | 74,613 | ||
Other current assets | 65,884 | 244,477 | ||
Oil and natural gas properties, net | 1,194,801 | 1,017,565 | ||
Midstream service assets, net | 0 | 0 | ||
Other fixed assets, net | 44,221 | 43,210 | ||
Investment in subsidiaries and equity method investee | 376,028 | 301,891 | ||
Other long-term assets | 13,065 | 84,360 | ||
Total assets | 1,764,569 | 1,766,116 | ||
Accounts payable | 14,427 | 12,203 | ||
Other current liabilities | 150,531 | 158,283 | ||
Long-term debt, net | 1,353,909 | 1,416,226 | ||
Other long-term liabilities | 56,889 | 46,034 | ||
Stockholders' equity | 188,813 | 133,370 | ||
Total liabilities and stockholders' equity | 1,764,569 | 1,766,116 | ||
Reportable Legal Entities | Subsidiary Guarantors | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 16,297 | 13,086 | ||
Other current assets | 2,026 | 56 | ||
Oil and natural gas properties, net | 9,293 | 9,350 | ||
Midstream service assets, net | 126,240 | 131,725 | ||
Other fixed assets, net | 552 | 328 | ||
Investment in subsidiaries and equity method investee | 243,953 | 192,524 | ||
Other long-term assets | 3,684 | 3,916 | ||
Total assets | 402,045 | 350,985 | ||
Accounts payable | 627 | 1,978 | ||
Other current liabilities | 22,360 | 44,351 | ||
Long-term debt, net | 0 | 0 | ||
Other long-term liabilities | 3,030 | 2,765 | ||
Stockholders' equity | 376,028 | 301,891 | ||
Total liabilities and stockholders' equity | 402,045 | 350,985 | ||
Intercompany eliminations | ||||
Subsidiary guarantees | ||||
Accounts receivable, net | 0 | 0 | ||
Other current assets | 0 | 0 | ||
Oil and natural gas properties, net | (8,240) | (1,923) | ||
Midstream service assets, net | 0 | 0 | ||
Other fixed assets, net | 0 | 0 | ||
Investment in subsidiaries and equity method investee | (376,028) | (301,891) | ||
Other long-term assets | 0 | 0 | ||
Total assets | (384,268) | (303,814) | ||
Accounts payable | 0 | 0 | ||
Other current liabilities | 0 | 0 | ||
Long-term debt, net | 0 | 0 | ||
Other long-term liabilities | 0 | 0 | ||
Stockholders' equity | (384,268) | (303,814) | ||
Total liabilities and stockholders' equity | $ (384,268) | $ (303,814) |
Subsidiary guarantors - Cond110
Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Subsidiary guarantees | |||||||||||||
Total revenues | $ 184,314 | $ 159,734 | $ 146,773 | $ 106,557 | $ 123,275 | $ 150,340 | $ 182,331 | $ 150,694 | $ 597,378 | $ 606,640 | $ 793,885 | ||
Total costs and expenses | 685,340 | 3,078,154 | 567,499 | ||||||||||
Operating loss | 45,460 | 25,492 | 17,874 | (176,788) | (1,015,677) | (927,859) | (501,480) | (26,498) | (87,962) | (2,471,514) | 226,386 | ||
Interest expense & other, net | (93,123) | (102,793) | (120,879) | ||||||||||
Other non-operating income | (79,654) | 187,426 | 324,352 | ||||||||||
Income (loss) before income taxes | (260,739) | (2,386,881) | 429,859 | ||||||||||
Income tax (expense) benefit | 0 | 176,945 | [1] | (164,286) | [1] | ||||||||
Net income (loss) | $ (18,421) | $ 9,485 | $ (71,432) | $ (180,371) | $ (964,647) | $ (847,783) | $ (397,034) | $ (472) | (260,739) | (2,209,936) | 265,573 | ||
Reportable Legal Entities | Laredo | |||||||||||||
Subsidiary guarantees | |||||||||||||
Total revenues | 427,028 | 432,478 | 738,446 | ||||||||||
Total costs and expenses | 514,483 | 2,897,272 | 505,455 | ||||||||||
Operating loss | (87,455) | (2,464,794) | 232,991 | ||||||||||
Interest expense & other, net | (93,123) | (102,793) | (120,879) | ||||||||||
Other non-operating income | (73,844) | 182,396 | 317,980 | ||||||||||
Income (loss) before income taxes | (254,422) | (2,385,191) | 430,092 | ||||||||||
Income tax (expense) benefit | 0 | 176,945 | (164,286) | ||||||||||
Net income (loss) | (254,422) | (2,208,246) | 265,806 | ||||||||||
Reportable Legal Entities | Subsidiary Guarantors | |||||||||||||
Subsidiary guarantees | |||||||||||||
Total revenues | 213,866 | 198,248 | 63,944 | ||||||||||
Total costs and expenses | 208,056 | 203,278 | 70,316 | ||||||||||
Operating loss | 5,810 | (5,030) | (6,372) | ||||||||||
Interest expense & other, net | 0 | 0 | 0 | ||||||||||
Other non-operating income | 9,381 | 6,708 | (339) | ||||||||||
Income (loss) before income taxes | 15,191 | 1,678 | (6,711) | ||||||||||
Income tax (expense) benefit | 0 | 0 | 0 | ||||||||||
Net income (loss) | 15,191 | 1,678 | (6,711) | ||||||||||
Intercompany eliminations | |||||||||||||
Subsidiary guarantees | |||||||||||||
Total revenues | (43,516) | (24,086) | (8,505) | ||||||||||
Total costs and expenses | (37,199) | (22,396) | (8,272) | ||||||||||
Operating loss | (6,317) | (1,690) | (233) | ||||||||||
Interest expense & other, net | 0 | 0 | 0 | ||||||||||
Other non-operating income | (15,191) | (1,678) | 6,711 | ||||||||||
Income (loss) before income taxes | (21,508) | (3,368) | 6,478 | ||||||||||
Income tax (expense) benefit | 0 | 0 | 0 | ||||||||||
Net income (loss) | $ (21,508) | $ (3,368) | $ 6,478 | ||||||||||
[1] | Income tax expense or benefit for the midstream and marketing segment was calculated by multiplying income or loss before income taxes by 36% for the years ended December 31, 2015 and 2014. |
Subsidiary guarantors - Cond111
Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Subsidiary guarantees | |||
Net cash flows provided by operating activities | $ 356,295 | $ 315,947 | $ 498,277 |
Change in investments between affiliates | 0 | 0 | 0 |
Capital expenditures and other | (564,402) | (667,507) | (1,406,961) |
Net cash flows provided by financing activities | 209,625 | 353,393 | 739,852 |
Net increase (decrease) in cash and cash equivalents | 1,518 | 1,833 | (168,832) |
Cash and cash equivalents, beginning of period | 31,154 | 29,321 | 198,153 |
Cash and cash equivalents, end of period | 32,672 | 31,154 | 29,321 |
Reportable Legal Entities | Laredo | |||
Subsidiary guarantees | |||
Net cash flows provided by operating activities | 355,458 | 316,838 | 496,955 |
Change in investments between affiliates | (73,988) | (136,252) | (113,449) |
Capital expenditures and other | (489,577) | (532,146) | (1,292,191) |
Net cash flows provided by financing activities | 209,625 | 353,393 | 739,852 |
Net increase (decrease) in cash and cash equivalents | 1,518 | 1,833 | (168,833) |
Cash and cash equivalents, beginning of period | 31,153 | 29,320 | 198,153 |
Cash and cash equivalents, end of period | 32,671 | 31,153 | 29,320 |
Reportable Legal Entities | Subsidiary Guarantors | |||
Subsidiary guarantees | |||
Net cash flows provided by operating activities | 16,028 | 787 | (5,389) |
Change in investments between affiliates | 58,797 | 134,574 | 120,160 |
Capital expenditures and other | (74,825) | (135,361) | (114,770) |
Net cash flows provided by financing activities | 0 | 0 | 0 |
Net increase (decrease) in cash and cash equivalents | 0 | 0 | 1 |
Cash and cash equivalents, beginning of period | 1 | 1 | 0 |
Cash and cash equivalents, end of period | 1 | 1 | 1 |
Intercompany eliminations | |||
Subsidiary guarantees | |||
Net cash flows provided by operating activities | (15,191) | (1,678) | 6,711 |
Change in investments between affiliates | 15,191 | 1,678 | (6,711) |
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) $ in Thousands | Jan. 17, 2017USD ($)aproperty | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Feb. 16, 2017USD ($) |
Subsequent Event [Line Items] | |||||
Borrowing capacity | $ 304,682 | $ 475,000 | $ 0 | ||
Senior Secured Credit Facility | Subsequent events | |||||
Subsequent Event [Line Items] | |||||
Borrowing capacity | $ 55,000 | ||||
Line of credit | $ 15,000 | ||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Midland Basin | Subsequent events | |||||
Subsequent Event [Line Items] | |||||
Area of land (in acres) | a | 2,900 | ||||
Number of real estate properties | property | 16 | ||||
Sales Price | $ 59,600 | ||||
Proceeds after transaction costs | $ 59,400 |
Supplemental oil, NGL and na113
Supplemental oil, NGL and natural gas disclosures (unaudited) - Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Property acquisition costs: | ||||
Evaluated | [1] | $ 5,905 | $ 0 | $ 3,873 |
Unevaluated | 119,923 | 0 | 9,925 | |
Exploration costs | [2] | 41,333 | 20,697 | 242,284 |
Development costs | [3] | 298,942 | 500,577 | 1,049,317 |
Total costs incurred | 466,103 | 521,274 | 1,305,399 | |
Asset Retirement Obligation Costs | ||||
Property acquisition costs: | ||||
Evaluated | 1,100 | |||
Total costs incurred | $ 2,500 | $ 13,400 | $ 6,900 | |
[1] | Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the year ended December 31, 2016. See Note 4.a for additional discussion. | |||
[2] | The Company acquired significant leasehold interests during the year ended December 31, 2014. See Note 4.c for additional discussion. | |||
[3] | Development costs include $2.5 million, $13.4 million and $6.9 million in asset retirement obligations for the years ended December 31, 2016, 2015 and 2014, respectively. |
Supplemental oil, NGL and na114
Supplemental oil, NGL and natural gas disclosures (unaudited) - Capitalized oil, NGL and natural gas costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||||
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative,Percent Of Acquisition Costs To Total | 95.00% | |||||
Aggregate capitalized costs related to oil and natural gas production activities | ||||||
Evaluated properties | $ 5,488,756 | $ 5,103,635 | $ 4,446,781 | |||
Unevaluated properties not being depleted | 221,281 | [1] | 140,299 | 342,731 | ||
Capitalized costs | 5,710,037 | 5,243,934 | 4,789,512 | |||
Less accumulated depletion and impairment | (4,514,183) | (4,218,942) | (1,586,237) | |||
Net capitalized costs | 1,195,854 | 1,024,992 | 3,203,275 | |||
Oil and natural gas property costs not being amortized | ||||||
Unevaluated properties not being depleted | [1] | 148,647 | 1,839 | 67,467 | $ 3,328 | |
Unevaluated properties not being depleted | $ 221,281 | [1] | $ 140,299 | $ 342,731 | ||
[1] | (1)Acquisition costs comprise 95% of the $221.3 million in unevaluated properties not being depleted. |
Supplemental oil, NGL and na115
Supplemental oil, NGL and natural gas disclosures (unaudited) - Results of oil, NGL and natural gas producing activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Revenues: | ||||
Oil, NGL and natural gas sales | $ 426,485 | $ 431,734 | $ 737,203 | |
Production costs: | ||||
Lease operating expenses | 75,327 | 108,341 | 96,503 | |
Production and ad valorem taxes | 28,586 | 32,892 | 50,312 | |
Total production costs | 103,913 | 141,233 | 146,815 | |
Other costs: | ||||
Depletion | 134,105 | 263,666 | 237,067 | |
Accretion of asset retirement obligations | 3,274 | 2,236 | 1,721 | |
Impairment expense | 161,064 | 2,369,477 | 0 | |
Income tax (benefit) expense | [1] | 0 | (164,141) | 126,576 |
Results of operations | $ 24,129 | $ (2,180,737) | $ 225,024 | |
Effective tax rate (as a percent) | 0.00% | 7.00% | 38.00% | |
[1] | During the years ended December 31, 2016 and 2015, the Company recorded valuation allowances against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the years ended December 31, 2016 and 2015, income tax benefit is computed utilizing the Company's effective rates of 0% and 7%, respectively, 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 year ended December 31, 2014, income tax expense is computed utilizing the statutory rate. |
Supplemental oil, NGL and na116
Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) | 12 Months Ended | |||
Dec. 31, 2016MBoeMMcfMBbls | Dec. 31, 2015MBoeMMcfMBbls | Dec. 31, 2014MBoeMMcfMBbls | ||
Proved developed and undeveloped reserves: | ||||
Beginning of year (MBOE) | MBoe | 125,698 | 247,322 | 203,615 | |
Revisions (negative revisions) of previous estimates (MBOE) | MBoe | 34,082 | (124,180) | [1] | (21,359) |
Extensions, discoveries and other additions (MBOE) | MBoe | 24,940 | 22,388 | 76,539 | |
Purchases of reserves in place (MBOE) | MBoe | 529 | 256 | ||
Sales of reserves in place (MBOE) | MBoe | (3,486) | |||
Production (MBOE) | MBoe | (18,149) | (16,346) | (11,729) | |
End of year (MBOE) | MBoe | 167,100 | 125,698 | 247,322 | |
Proved developed reserves: | ||||
Beginning of year (energy) | MBoe | 100,395 | 105,557 | 71,725 | |
End of year (energy) | MBoe | 141,155 | 100,395 | 105,557 | |
Proved undeveloped reserves: | ||||
Beginning of year (energy) | MBoe | 25,303 | 141,765 | 131,890 | |
End of year (energy) | MBoe | 25,945 | 25,303 | 141,765 | |
Oil (MBbls) | ||||
Proved developed and undeveloped reserves: | ||||
Beginning of year | 52,639 | 140,190 | 111,498 | |
Revisions of previous estimates | 8,726 | (88,900) | [1] | (10,134) |
Extensions, discoveries and other additions | 10,741 | 10,511 | 45,554 | |
Purchases of reserves in place | 276 | 173 | ||
Sales of reserves in place | (1,552) | |||
Production | (8,442) | (7,610) | (6,901) | |
End of year | 63,940 | 52,639 | 140,190 | |
Proved developed reserves: | ||||
Beginning of year (volume) | 40,944 | 56,975 | 37,878 | |
End of year (volume) | 53,156 | 40,944 | 56,975 | |
Proved undeveloped reserves: | ||||
Beginning of year (volume) | 11,695 | 83,215 | 73,620 | |
End of year (volume) | 10,784 | 11,695 | 83,215 | |
Natural Gas Liquids | ||||
Proved developed and undeveloped reserves: | ||||
Beginning of year | 36,067 | 0 | ||
Revisions of previous estimates | 12,021 | 35,477 | [1] | |
Extensions, discoveries and other additions | 6,930 | 5,865 | ||
Purchases of reserves in place | 116 | |||
Sales of reserves in place | (1,008) | |||
Production | (4,784) | (4,267) | ||
End of year | 50,350 | 36,067 | 0 | |
Proved developed reserves: | ||||
Beginning of year (volume) | 29,349 | 0 | ||
End of year (volume) | 42,950 | 29,349 | 0 | |
Proved undeveloped reserves: | ||||
Beginning of year (volume) | 6,718 | 0 | ||
End of year (volume) | 7,400 | 6,718 | 0 | |
Natural Gas | ||||
Proved developed and undeveloped reserves: | ||||
Beginning of year | MMcf | 221,952 | 642,794 | 552,702 | |
Revisions of previous estimates | MMcf | 80,004 | (424,546) | [1] | (67,350) |
Extensions, discoveries and other additions | MMcf | 43,614 | 36,074 | 185,909 | |
Purchases of reserves in place | MMcf | 822 | 498 | ||
Sales of reserves in place | MMcf | (5,554) | |||
Production | MMcf | (29,535) | (26,816) | (28,965) | |
End of year | MMcf | 316,857 | 221,952 | 642,794 | |
Proved developed reserves: | ||||
Beginning of year (volume) | MMcf | 180,613 | 291,493 | 203,082 | |
End of year (volume) | MMcf | 270,291 | 180,613 | 291,493 | |
Proved undeveloped reserves: | ||||
Beginning of year (volume) | MMcf | 41,339 | 351,301 | 349,620 | |
End of year (volume) | MMcf | 46,566 | 41,339 | 351,301 | |
[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 reporting. For period 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 of 2016 and 2015 with 2014. |
Supplemental oil, NGL and na117
Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) - Narrative (Details) | 12 Months Ended | |||
Dec. 31, 2016MBoereserves_streamlocation | Dec. 31, 2015MBoereserves_streamlocation | Dec. 31, 2014MBoereserves_streamlocation | ||
Net proved oil and natural gas reserves | ||||
Percentage of proved reserves estimated by independent reserve engineers (percent) | 100.00% | 100.00% | 100.00% | |
Number of reportable reserves streams | reserves_stream | 3 | 3 | 2 | |
Revisions (negative revisions) of previous estimates (MBOE) | 34,082 | (124,180) | [1] | (21,359) |
Extensions, discoveries and other additions (MBOE) | 24,940 | 22,388 | 76,539 | |
Number of proved and undeveloped locations removed | location | 378 | 226 | ||
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 | ||
Number of locations in new proved undeveloped locations | location | 4 | 113 | ||
Exploratory wells drilled, net productive | location | 4 | |||
Development wells, scheduled to be drilled in the next twelve months | location | 7 | |||
Purchases of reserves in place (MBOE) | 529 | 256 | ||
Performance, Pricing and Other Changes | ||||
Net proved oil and natural gas reserves | ||||
Revisions (negative revisions) of previous estimates (MBOE) | (26,049) | 17,297 | 4,658 | |
Removal Of Proved And Undeveloped Locations and Reinterpretation of Undeveloped Locations | ||||
Net proved oil and natural gas reserves | ||||
Revisions (negative revisions) of previous estimates (MBOE) | (2,292) | (106,883) | (26,017) | |
Additional Due To Returning Locations | ||||
Net proved oil and natural gas reserves | ||||
Revisions (negative revisions) of previous estimates (MBOE) | 10,325 | |||
Drilling of New Wells | ||||
Net proved oil and natural gas reserves | ||||
Extensions, discoveries and other additions (MBOE) | 13,302 | 19,719 | 34,782 | |
Proved Undeveloped Properties | ||||
Net proved oil and natural gas reserves | ||||
Extensions, discoveries and other additions (MBOE) | 11,638 | 2,669 | 41,757 | |
[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 reporting. For period 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 of 2016 and 2015 with 2014. |
Supplemental oil, NGL and na118
Supplemental oil, NGL and natural gas disclosures (unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Future cash inflows | $ 3,548,567 | $ 3,269,184 | $ 16,663,685 | |
Future production costs | (1,238,369) | (1,321,471) | (3,616,775) | |
Future development costs | (290,505) | (376,701) | (2,471,985) | |
Future income tax expenses | 0 | 0 | (2,827,763) | |
Future net cash flows | 2,019,693 | 1,571,012 | 7,747,162 | |
10% discount for estimated timing of cash flows | (1,041,199) | (740,265) | (4,500,434) | |
Standardized measure of discounted future net cash flows | $ 978,494 | $ 830,747 | $ 3,246,728 | $ 2,322,204 |
Supplemental oil, NGL and na119
Supplemental oil, NGL and natural gas disclosures (unaudited) - Changes in the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
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 | $ 830,747 | $ 3,246,728 | $ 2,322,204 |
Changes in the year resulting from: | |||
Sales, less production costs | (322,573) | (290,501) | (590,388) |
Revisions of previous quantity estimates | 179,297 | (2,444,322) | (320,275) |
Extensions, discoveries and other additions | 133,472 | 192,979 | 1,340,022 |
Net change in prices and production costs | (80,102) | (1,495,144) | 145,740 |
Changes in estimated future development costs | 22,153 | (2,974) | (22,961) |
Previously estimated development costs incurred during the period | 189,085 | 162,237 | 92,135 |
Purchases of reserves in place | 3,422 | 0 | 6,100 |
Divestitures of reserves in place | 0 | (29,149) | 0 |
Accretion of discount | 83,075 | 424,453 | 305,325 |
Net change in income taxes | 0 | 997,805 | (266,757) |
Timing differences and other | (60,082) | 68,635 | 235,583 |
Standardized measure of discounted future net cash flows, end of year | $ 978,494 | $ 830,747 | $ 3,246,728 |
Supplemental quarterly finan120
Supplemental quarterly financial data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $ 184,314 | $ 159,734 | $ 146,773 | $ 106,557 | $ 123,275 | $ 150,340 | $ 182,331 | $ 150,694 | $ 597,378 | $ 606,640 | $ 793,885 |
Operating income (loss) | 45,460 | 25,492 | 17,874 | (176,788) | (1,015,677) | (927,859) | (501,480) | (26,498) | (87,962) | (2,471,514) | 226,386 |
Net income (loss) | $ (18,421) | $ 9,485 | $ (71,432) | $ (180,371) | $ (964,647) | $ (847,783) | $ (397,034) | $ (472) | $ (260,739) | $ (2,209,936) | $ 265,573 |
Net income (loss) per common share: | |||||||||||
Basic (in dollars per share) | $ (0.08) | $ 0.04 | $ (0.33) | $ (0.85) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ (1.16) | $ (11.10) | $ 1.88 |
Diluted (in dollars per share) | $ (0.08) | $ 0.04 | $ (0.33) | $ (0.85) | $ (4.57) | $ (4.01) | $ (1.88) | $ 0 | $ (1.16) | $ (11.10) | $ 1.85 |