Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2018 | Nov. 01, 2018 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Laredo Petroleum, Inc. | |
Entity Central Index Key | 1,528,129 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 233,882,020 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 | |
Entity Emerging Growth Company | false | |
Entity Small Business | false |
Consolidated balance sheets
Consolidated balance sheets - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 50,407 | $ 112,159 |
Accounts receivable, net | 117,581 | 100,645 |
Derivatives | 3,074 | 6,892 |
Other current assets | 18,465 | 15,686 |
Total current assets | 189,527 | 235,382 |
Oil and natural gas properties, full cost method: | ||
Evaluated properties | 6,589,327 | 6,070,940 |
Unevaluated properties not being depleted | 147,690 | 175,865 |
Less accumulated depletion and impairment | (4,798,527) | (4,657,466) |
Oil and natural gas properties, net | 1,938,490 | 1,589,339 |
Midstream service assets, net | 132,415 | 138,325 |
Other fixed assets, net | 42,264 | 40,721 |
Property and equipment, net | 2,113,169 | 1,768,385 |
Derivatives | 0 | 3,413 |
Other noncurrent assets, net | 17,078 | 16,109 |
Total assets | 2,319,774 | 2,023,289 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 86,637 | 58,341 |
Accrued capital expenditures | 38,188 | 82,721 |
Undistributed revenue and royalties | 53,239 | 37,852 |
Derivatives | 44,060 | 22,950 |
Other current liabilities | 37,145 | 75,555 |
Total current liabilities | 259,269 | 277,419 |
Long-term debt, net | 963,191 | 791,855 |
Derivatives | 20,945 | 384 |
Asset retirement obligations | 55,684 | 53,962 |
Other noncurrent liabilities | 5,573 | 134,090 |
Total liabilities | 1,304,662 | 1,257,710 |
Commitments and contingencies | ||
Stockholders' equity: | ||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2018 and December 31, 2017 | 0 | 0 |
Common stock, $0.01 par value, 450,000,000 shares authorized and 233,957,811 and 242,521,143 issued and outstanding as of September 30, 2018 and December 31, 2017, respectively | 2,340 | 2,425 |
Additional paid-in capital | 2,365,740 | 2,432,262 |
Accumulated deficit | (1,352,968) | (1,669,108) |
Total stockholders' equity | 1,015,112 | 765,579 |
Total liabilities and stockholders' equity | $ 2,319,774 | $ 2,023,289 |
Consolidated balance sheets (Pa
Consolidated balance sheets (Parenthetical) - $ / shares | Sep. 30, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Preferred stock par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock authorized (in shares) | 50,000,000 | 50,000,000 |
Preferred stock issued (in shares) | 0 | 0 |
Common stock par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock authorized (in shares) | 450,000,000 | 450,000,000 |
Common stock issued (in shares) | 233,957,811 | 242,521,143 |
Common stock outstanding (in shares) | 233,957,811 | 242,521,143 |
Consolidated statements of oper
Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues: | ||||
Total revenues | $ 279,746 | $ 205,818 | $ 890,488 | $ 581,825 |
Costs and expenses: | ||||
Lease operating expenses | 23,873 | 19,594 | 68,466 | 56,690 |
Production and ad valorem taxes | 14,015 | 9,558 | 38,232 | 26,811 |
General and administrative | 23,397 | 25,000 | 74,956 | 72,605 |
Depletion, depreciation and amortization | 55,963 | 41,212 | 152,278 | 113,327 |
Other operating expenses | 1,114 | 1,443 | 3,341 | 3,906 |
Total costs and expenses | 175,336 | 145,366 | 598,119 | 417,986 |
Operating income | 104,410 | 60,452 | 292,369 | 163,839 |
Non-operating income (expense): | ||||
Gain (loss) on derivatives, net | (32,245) | (27,441) | (69,211) | 38,127 |
Income from equity method investee (see Note 3.c) | 0 | 2,371 | 0 | 7,910 |
Interest expense | (14,845) | (23,697) | (42,787) | (69,590) |
Other (expense) income | (267) | 333 | 629 | 527 |
Loss on disposal of assets, net | (616) | (991) | (4,591) | (400) |
Non-operating expense, net | (47,973) | (49,425) | (115,960) | (23,426) |
Income before income taxes | 56,437 | 11,027 | 176,409 | 140,413 |
Income tax benefit (expense): | ||||
Current | 381 | 0 | 381 | 0 |
Deferred | (1,768) | 0 | (1,768) | 0 |
Total income tax expense: | (1,387) | 0 | (1,387) | 0 |
Net income | $ 55,050 | $ 11,027 | $ 175,022 | $ 140,413 |
Net income per common share: | ||||
Basic (in dollars per share) | $ 0.24 | $ 0.05 | $ 0.75 | $ 0.59 |
Diluted (in dollars per share) | $ 0.24 | $ 0.05 | $ 0.75 | $ 0.57 |
Weighted-average common shares outstanding: | ||||
Basic (in shares) | 230,605 | 239,306 | 233,228 | 239,017 |
Diluted (in shares) | 231,639 | 244,887 | 234,207 | 244,693 |
Oil sales | ||||
Revenues: | ||||
Total revenues | $ 160,007 | $ 110,194 | $ 469,972 | $ 313,875 |
NGL sales | ||||
Revenues: | ||||
Total revenues | 50,814 | 27,700 | 115,979 | 68,329 |
Natural gas sales | ||||
Revenues: | ||||
Total revenues | 15,043 | 19,664 | 45,908 | 55,927 |
Transportation and marketing expenses | ||||
Costs and expenses: | ||||
Cost of goods and services sold | 5,036 | 0 | 6,570 | 0 |
Midstream service revenues | ||||
Revenues: | ||||
Total revenues | 2,255 | 2,446 | 6,590 | 8,148 |
Costs and expenses: | ||||
Cost of goods and services sold | 728 | 1,174 | 1,824 | 2,986 |
Sales of purchased oil | ||||
Revenues: | ||||
Total revenues | 51,627 | 45,814 | 252,039 | 135,546 |
Costs and expenses: | ||||
Cost of goods and services sold | $ 51,210 | $ 47,385 | $ 252,452 | $ 141,661 |
Consolidated statement of stock
Consolidated statement of stockholders' equity - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Additional paid-in capital | Treasury Stock (at cost) | Accumulated deficit |
Increase (Decrease) in Stockholders' Equity | |||||
Adjustment to the beginning balance of accumulated deficit upon adoption of ASC 606 (see Note 4.a) | Accounting Standards Update 2014-09 | $ 141,118 | $ 141,118 | |||
Balance, beginning of period (in shares) at Dec. 31, 2017 | 242,521 | 0 | |||
Balance, beginning of period at Dec. 31, 2017 | 765,579 | $ 2,425 | $ 2,432,262 | $ 0 | (1,669,108) |
Increase (Decrease) in Stockholders' Equity | |||||
Restricted stock awards (in shares) | 3,248 | ||||
Restricted stock awards | 0 | $ 33 | (33) | ||
Restricted stock forfeitures (in shares) | (266) | ||||
Restricted stock forfeitures | 0 | $ (3) | 3 | ||
Share repurchases (in shares) | 11,049 | ||||
Share repurchases | (97,055) | $ (97,055) | |||
Vested stock exchanged for tax withholding (in shares) | 517 | ||||
Vested stock exchanged for tax withholding | (4,411) | $ (4,411) | |||
Retirement of treasury stock (in shares) | (11,566) | (11,566) | |||
Retirement of treasury stock | 0 | $ (115) | (101,351) | $ 101,466 | |
Exercise of stock options (in shares) | 21 | ||||
Exercise of stock options | 86 | 86 | |||
Stock-based compensation | 34,773 | 34,773 | |||
Net income | 175,022 | 175,022 | |||
Balance, end of period (in shares) at Sep. 30, 2018 | 233,958 | 0 | |||
Balance, end of period at Sep. 30, 2018 | $ 1,015,112 | $ 2,340 | $ 2,365,740 | $ 0 | $ (1,352,968) |
Consolidated statements of cash
Consolidated statements of cash flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Cash flows from operating activities: | ||
Net income | $ 175,022 | $ 140,413 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Deferred income tax expense | 1,768 | 0 |
Depletion, depreciation and amortization | 152,278 | 113,327 |
Non-cash stock-based compensation, net | 28,748 | 26,877 |
Mark-to-market on derivatives: | ||
(Gain) loss on derivatives, net | 69,211 | (38,127) |
Settlements (paid) received for matured derivatives, net | (5,943) | 34,791 |
Settlements received for early terminations of derivatives, net | 0 | 4,234 |
Change in net present value of derivative deferred premiums | 564 | 199 |
Premiums paid for derivatives | (14,930) | (13,542) |
Amortization of debt issuance costs | 2,484 | 3,132 |
Income from equity method investee (see Note 3.c) | 0 | (7,910) |
Other, net | 9,290 | 3,445 |
Increase in accounts receivable | (18,591) | (2,973) |
Increase in other current assets | (6,479) | (3,143) |
Decrease (increase) in other noncurrent assets | 346 | (77) |
Increase in accounts payable and accrued liabilities | 28,296 | 11,575 |
Increase in undistributed revenues and royalties | 15,387 | 6,384 |
Decrease in other current liabilities | (28,298) | (6,264) |
Decrease in other noncurrent liabilities | (625) | (290) |
Net cash provided by operating activities | 408,528 | 272,051 |
Cash flows from investing activities: | ||
Acquisitions of oil and natural gas properties | (16,340) | 0 |
Capital expenditures: | ||
Oil and natural gas properties | (522,470) | (381,165) |
Midstream service assets | (5,764) | (11,680) |
Other fixed assets | (5,945) | (3,604) |
Investment in equity method investee (see Note 3.c) | 0 | (24,572) |
Proceeds from disposition of equity method investee, net of selling costs (see Note 3.c) | 1,655 | 0 |
Proceeds from dispositions of capital assets, net of selling costs | 12,433 | 64,128 |
Net cash used in investing activities | (536,431) | (356,893) |
Cash flows from financing activities: | ||
Borrowings on Senior Secured Credit Facility | 190,000 | 155,000 |
Payments on Senior Secured Credit Facility | (20,000) | (70,000) |
Share repurchases | (97,055) | 0 |
Vested stock exchanged for tax withholding | (4,411) | (7,638) |
Proceeds from exercise of stock options | 86 | 358 |
Payments for debt issuance costs | (2,469) | (4,732) |
Net cash provided by financing activities | 66,151 | 72,988 |
Net decrease in cash and cash equivalents | (61,752) | (11,854) |
Cash and cash equivalents, beginning of period | 112,159 | 32,672 |
Cash and cash equivalents, end of period | $ 50,407 | $ 20,818 |
Organization and basis of prese
Organization and basis of presentation | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Organization and basis of presentation | Organization and basis of presentation a. Organization Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and midstream and marketing services, primarily in the Permian Basin of West Texas . LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and, therefore, approximate. b. Basis of presentation The accompanying unaudited 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 unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The accompanying unaudited consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 2017 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of September 30, 2018 , results of operations for the three and nine months ended September 30, 2018 and 2017 and cash flows for the nine months ended September 30, 2018 and 2017 . Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2017 Annual Report. Significant accounting policies See Note 2 "Basis of presentation and significant accounting policies" in the 2017 Annual Report for discussion of significant accounting policies. Use of estimates in the preparation of interim unaudited consolidated financial statements The preparation of the accompanying unaudited 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. For further information regarding the estimates and assumptions, see Note 2.b "Use of estimates in the preparation of consolidated financial statements" in the 2017 Annual Report. Furthermore, see Note 7.c for a discussion of estimates pertaining to the Company's 2018 performance share awards. Reclassifications Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income, stockholders' equity or total operating, investing or financing cash flows. |
Recently issued or adopted acco
Recently issued or adopted accounting pronouncements | 9 Months Ended |
Sep. 30, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recently issued or adopted accounting pronouncements | Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs and a final rule issued by the SEC listed below were determined to be meaningful to the Company's unaudited consolidated financial statements and/or footnotes during the nine months ended September 30, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 4 for further discussion of the ASC 606 adoption impact on the Company's unaudited consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The primary effect on the Company's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has a team, including third-party consultants, to implement the standard and is implementing the software that will be used to track and account for lease activity. The Company anticipates that the adoption and implementation of ASC 842 will result in a material increase in assets and liabilities on the consolidated balance sheet but will not result in a material impact to the consolidated statement of operations. The estimate of the dollar value impact of the adoption is on-going. The Company has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. The transition will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted (January 1, 2019). The Company will utilize the transition package of expedients to leases that commenced before the effective date. The Company expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. See Note 3.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU. d. Fair value measurements In August 2018, the FASB issued new guidance in ASC 820, Fair Value Measurement , to modify disclosure requirements. Of the amendments in the ASU, the below items affected the Company's fair value measurement disclosures in Note 9 . Removed disclosure requirements that should be applied retrospectively to all periods presented are: (i) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the policy for timing of transfers between levels and (iii) the valuation processes for Level 3 fair value measurements. A modified disclosure requirement that should be applied prospectively is to clarify that the measurement uncertainty disclosure communicates information about the uncertainty in measurement as of the reporting date. A new disclosure requirement that should be applied prospectively is to disclose the range and weighted-average of significant unobservable inputs used to develop Level 3 fair value measurements. The Company has elected to early adopt this guidance upon the issuance of the ASU and has modified its disclosures accordingly in this Quarterly Report. e. SEC disclosure update and simplification In August 2018, the SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification , which amends various SEC disclosure requirements that they have determined to be redundant, duplicative, overlapping, outdated or superseded. The amendments also extend the annual disclosure requirement of presenting the changes in stockholders' equity to interim periods. An analysis of changes in stockholders’ equity will now be required for the current and comparative year-to-date interim periods. The Company has incorporated certain aspects of the final rule in this Quarterly Report and will complete the implementation of the final rule in the fourth quarter of 2018. |
Acquisitions and divestitures
Acquisitions and divestitures | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations And Disposal Groups [Abstract] | |
Acquisitions and divestitures | Acquisitions and divestitures a. 2018 Acquisitions of evaluated and unevaluated oil and natural gas properties During the nine months ended September 30, 2018, through multiple transactions, the Company acquired 895 net acres of additional leasehold interests and working interests in 47 producing horizontal and vertical wells in Glasscock County, Texas for an aggregate purchase price of $16.3 million , net of post-closing adjustments. These acquisitions were accounted for as asset acquisitions. b. 2018 Divestitures of evaluated and unevaluated oil and natural gas properties and midstream service assets During the nine months ended September 30, 2018, through multiple transactions, the Company completed the sale of 3,070 net acres and working interests in 24 producing vertical and horizontal wells and associated midstream service assets in Glasscock County and Howard County in Texas to third-party buyers for an aggregate sales price of $12.0 million , net of post-closing adjustments. Of this amount, $ 11.5 million, net of post-closing adjustments, was recorded as adjustments to oil and natural gas properties pursuant to the rules governing full cost accounting. A loss of $ 1.0 million from the sale of the associated midstream service assets was included in the line item "Loss on disposal of assets, net" in the unaudited consolidated statements of operations. Effective at the closings, the operations and cash flows of these oil and natural gas properties and midstream service assets were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. These divestitures did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. c. 2017 Medallion sale Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market from the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the unaudited consolidated statements of operations on the "Income from equity method investee" line item. On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP") for cash consideration of $ 1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $ 829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $ 1.7 million for total net cash proceeds before taxes of $ 831.3 million. The proceeds were used to pay borrowings on the Senior Secured Credit Facility in full, to redeem the May 2022 Notes (as defined below) and for working capital purposes. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid. The Medallion Sale did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion under which LMS receives firm transportation of the Company's crude oil production from Reagan County and Glasscock County in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018. The deferred gain is included in the unaudited consolidated balance sheets in each of the "Other current liabilities" and "Other noncurrent liabilities" line items as of December 31, 2017. See Note 4.a for discussion of the impact to the deferred gain upon the adoption of ASC 606. d. 2017 Divestiture of evaluated and unevaluated oil and natural gas properties In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million . After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million , net of working capital and post-closing adjustments. A significant portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. e. Exchange of unevaluated oil and natural gas properties From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. |
Revenue recognition
Revenue recognition | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue recognition | Revenue recognition a. Impact of ASC 606 adoption Upon adoption of ASC 606 on January 1, 2018, for the three and nine months ended September 30, 2018 , the Company reclassified certain firm transportation payments on excess pipeline capacity and other contractual penalties due to customers, historically included in the "Other operating expenses" line item in the unaudited consolidated statements of operations, and netted them with the revenue stream from which they derive as these payments to customers do not relate to the provision of a distinct good or service to the customer. In addition, there was an impact upon adoption related to the treatment of the gain on the Medallion Sale. The impact of the adoption of ASC 606 on the results of operations for the periods presented is as follows: Three months ended September 30, 2018 Nine months ended September 30, 2018 (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 160,246 $ 160,007 $ (239 ) $ 472,496 $ 469,972 $ (2,524 ) NGL sales $ 50,814 $ 50,814 $ — $ 115,979 $ 115,979 $ — Natural gas sales $ 15,043 $ 15,043 $ — $ 45,908 $ 45,908 $ — Costs and expenses: Other operating expenses $ 1,353 $ 1,114 $ (239 ) $ 5,865 $ 3,341 $ (2,524 ) Net income $ 55,050 $ 55,050 $ — $ 175,022 $ 175,022 $ — At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's unaudited consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. See Note 3.c for further discussion of the Medallion Sale and the TA. Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to GIP, (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the beginning balance of accumulated deficit, presented in the unaudited consolidated statements of stockholders' equity, in accordance with the modified retrospective approach of adoption. b. Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying unaudited consolidated statements of operations. Under certain of its customer contracts, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that we have transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream Services Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of September 30, 2018 or December 31, 2017. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less . For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the three and nine months ended September 30, 2018 , revenue recognized related to performance obligations satisfied in prior reporting periods was not material. |
Property and equipment
Property and equipment | 9 Months Ended |
Sep. 30, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property and equipment | Property and equipment The following table presents the Company's property and equipment as of the dates presented: (in thousands) September 30, 2018 December 31, 2017 Evaluated oil and natural gas properties $ 6,589,327 $ 6,070,940 Less accumulated depletion and impairment (4,798,527 ) (4,657,466 ) Evaluated oil and natural gas properties, net 1,790,800 1,413,474 Unevaluated oil and natural gas properties not being depleted 147,690 175,865 Midstream service assets 171,740 171,427 Less accumulated depreciation and impairment (39,325 ) (33,102 ) Midstream service assets, net 132,415 138,325 Depreciable other fixed assets 50,420 48,957 Less accumulated depreciation and amortization (26,415 ) (23,150 ) Depreciable other fixed assets, net 24,005 25,807 Land 18,259 14,914 Total property and equipment, net $ 2,113,169 $ 1,768,385 For the three months ended September 30, 2018 and 2017 , depletion expense for the Company's evaluated oil and natural gas properties was $7.94 per barrel of oil equivalent ("BOE") sold and $6.80 per BOE sold, respectively. For the nine months ended September 30, 2018 and 2017 , depletion expense for the Company's evaluated oil and natural gas properties was $7.67 per BOE sold and $6.57 per BOE sold, respectively. 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 employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities, are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. The following table presents capitalized employee-related costs for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Capitalized employee-related costs $ 5,837 $ 6,938 $ 19,101 $ 17,911 The Company excludes the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. 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 following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Property acquisition costs (see Note 3.a): — Evaluated $ — $ — $ 13,847 $ — Unevaluated — — 2,790 — Exploration costs 7,502 7,136 18,747 28,337 Development costs 139,748 160,359 467,582 397,255 Total costs incurred $ 147,250 $ 167,495 $ 502,966 $ 425,592 |
Debt
Debt | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Debt a. March 2023 Notes On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM 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 applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The Company may redeem, at its option, all or part of the March 2023 Notes at any time after March 15, 2018, at a price of 104.688% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption. b. January 2022 Notes On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The Company may redeem, at its option, all or part of the January 2022 Notes at any time after January 15, 2018, at a price of 102.813% of face value with call premiums declining annually to 100% of face value on January 15, 2020 and thereafter plus accrued and unpaid interest to, but not including, the date of redemption. c. May 2022 Notes On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes were due to mature on May 1, 2022 and bore an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. On November 29, 2017 (the "May 2022 Notes Redemption Date"), utilizing a portion of the proceeds from the Medallion Sale, the entire $500.0 million outstanding principal amount of the May 2022 Notes was redeemed at a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest up to, but not including, the May 2022 Notes Redemption Date. The Company recognized a loss on extinguishment of $23.8 million related to the difference between the redemption price and the net carrying amount of the extinguished May 2022 Notes. d. Senior Secured Credit Facility The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of September 30, 2018 , the Senior Secured Credit Facility had a maximum credit amount of $2.0 billion , a borrowing base of $1.3 billion and an aggregate elected commitment of $1.2 billion , with $170.0 million outstanding and was subject to an interest rate of 3.44% . The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 30, 2018 . Laredo is required to pay a commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5% , based on the ratio of outstanding revolving credit to the aggregate elected commitment under the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million . No letters of credit were outstanding as of September 30, 2018 or December 31, 2017 . See Note 16 for discussion of items affecting the Senior Secured Credit Facility subsequent to September 30, 2018 . e. Long-term debt, net The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented: September 30, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,254 ) $ 446,746 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,555 ) 346,445 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 170,000 — 170,000 — — — Total $ 970,000 $ (6,809 ) $ 963,191 $ 800,000 $ (8,145 ) $ 791,855 ______________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.4 million and $6.0 million as of September 30, 2018 and December 31, 2017 , respectively, are reported in "Other assets, net" on the unaudited consolidated balance sheets. |
Stockholders' equity and stock-
Stockholders' equity and stock-based compensation | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Stockholders' equity and stock-based compensation | Stockholders' equity and stock-based compensation a. Share repurchase program In February 2018, the Company's board of directors authorized a $ 200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. During the three months ended September 30, 2018 , the Company repurchased 1,170,190 shares of common stock at a weighted-average price of $8.41 per common share for a total of $9.9 million under this program. During the nine months ended September 30, 2018 , the Company repurchased 11,048,742 shares of common stock at a weighted-average price of $ 8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. b. Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock-based awards at the employees' election. c. Stock-based compensation The Company's Long-Term Incentive Plan (the "LTIP") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the unaudited consolidated balance sheets. Restricted stock awards All service vesting restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules that mainly include (i) 33% , 33% and 34% per year beginning on the first anniversary of the grant date and (ii) fully on the first anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately on the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vested on the first anniversary of the grant date. The following table reflects the restricted stock award activity for the nine months ended September 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average (per award) Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,248 $ 8.42 Forfeited (266 ) $ 10.35 Vested (1) (1,851 ) $ 12.21 Outstanding as of September 30, 2018 4,300 $ 9.90 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the nine months ended September 30, 2018 was $16.1 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 September 30, 2018 , unrecognized stock-based compensation related to the restricted stock awards expected to vest was $26.5 million . Such cost is expected to be recognized over a weighted-average period of 1.87 years . Stock option awards Stock option awards granted under the LTIP vest and become exercisable in four equal installments on each of the four anniversaries of the grant date. As of September 30, 2018 , the 2,577,205 outstanding stock option awards have a weighted-average exercise price of $ 12.66 and a weighted-average remaining contractual term of 6.37 years . There were de minimis exercises, forfeitures and cancellations of stock option awards during the nine months ended September 30, 2018 . There were no grants of stock option awards during the nine months ended September 30, 2018 . The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four -year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated expected volatility. As of September 30, 2018 , unrecognized stock-based compensation related to stock option awards expected to vest was $5.0 million . Such cost is expected to be recognized over a weighted-average period of 1.67 years . Performance share awards Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include the RTSR Performance Percentage (as defined below), the ATSR Appreciation (as defined below) and the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and the associated expense is recognized on a straight-line basis over the three -year requisite service period of the awards. For portions of awards with performance criteria, which is the ROACE Percentage (as defined below), the grant-date fair value is equal to the Company's stock price on the grant date, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the three -year performance period. Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain market and performance criteria. The following table reflects the performance share award activity for the nine months ended September 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share awards Weighted-average (per award) Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (1) 1,389 $ 9.22 Forfeited (149 ) $ 14.83 Vested (2) (454 ) $ 16.23 Outstanding as of September 30, 2018 3,531 $ 14.55 ______________________________________________________________________________ (1) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $ 9.22 per unit grant-date fair value consists of a (i) $ 10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $ 8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. (2) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their performance criteria were not satisfied, resulted in a TSR modifier of 0 % based on the Company finishing in the 36th percentile of its peer group for relative TSR. As such, the units were not converted into the Company's common stock during the first quarter of 2018. As of September 30, 2018 , unrecognized stock-based compensation related to the performance share awards expected to vest was $18.6 million . Such cost is expected to be recognized over a weighted-average period of 1.72 years . The assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted on the date presented are as follows: February 16, 2018 Risk-free interest rate (1) 2.34 % Dividend yield — % Expected volatility (2) 65.49 % Laredo stock closing price on grant date $ 8.36 Combined fair value per performance share award for the (.25) RTSR Factor and the (.25) ATSR Factor (3) $ 10.08 ______________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) The market criteria portion of the performance share award represents 50% of each of the amount of stock potentially payable, if any, and the grant-date fair value of the award. Stock-based compensation expense The following has been recorded to stock-based compensation expense for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Restricted stock award compensation $ 6,001 $ 5,422 $ 19,332 $ 16,856 Stock option award compensation 970 1,159 3,010 3,600 Performance share award compensation 3,689 4,255 12,431 12,063 Total stock-based compensation, gross 10,660 10,836 34,773 32,519 Less amounts capitalized in oil and natural gas properties (1,927 ) (1,870 ) (6,025 ) (5,642 ) Total stock-based compensation, net $ 8,733 $ 8,966 $ 28,748 $ 26,877 |
Derivatives
Derivatives | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives Due to the inherent volatility in oil, NGL and natural gas prices, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in derivative transactions, such as puts, swaps, collars, basis swaps and, in the past, call spreads to hedge price risk associated with a portion of the Company's anticipated production. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices, commodity transportation costs and differences in commodity prices between where the Company produces and where the Company sells its products . Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be paid at inception or deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual month in the contract period, the put option expires with no settlement for that particular month, except with regard to the deferred premium, if any. Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. Each collar transaction has an established price floor and ceiling. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume. Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price and less than or equal to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any. Other than the oil basis swaps, the Company's oil derivatives are settled based on the month's average daily NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The oil basis swaps are settled based on either (i) the differential between the Argus Americas Crude West Texas Intermediate ("WTI") index prices for WTI Midland-weighted average for the trade month and WTI Cushing-WTI formula basis for the trade month as compared to the basis swaps' fixed differential price or (ii) the differential between the Argus Americas Crude WTI Houston-weighted average price for the trade month and the WTI Midland-weighted average price for the trade month as compared to the basis swaps' fixed differential price. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane, TET and Non-TET Propane, Non-TET Normal Butane, Non-TET Isobutane and Non-TET Natural Gasoline. Other than the natural gas basis swaps, the Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period. The natural gas basis swaps are settled based on the differential between the Inside FERC index price for West Texas WAHA for the calculation period and the NYMEX Henry Hub index price for the calculation period as compared to the basis swaps' fixed differential price. During the nine months ended September 30, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the restructuring. The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 The following table summarizes open positions as of September 30, 2018 , and represents, as of such date, derivatives in place through December 2021 on annual production volumes: Remaining year 2018 Year Year Year Oil: Puts: Hedged volume (Bbl) 1,367,775 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 51.93 $ 47.45 $ 45.00 $ — Swaps: Hedged volume (Bbl) — 657,000 695,400 — Weighted-average price ($/Bbl) $ — $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) 1,030,400 — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ 41.43 $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ 60.00 $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 2,398,175 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.42 $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 1,030,400 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 60.00 $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI Cushing: Hedged volume (Bbl) 920,000 552,000 — — Weighted-average price ($/Bbl) $ (0.56 ) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 920,000 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 156,400 — — — Weighted-average price ($/Bbl) $ 11.66 $ — $ — $ — Swaps - Non-TET Propane: Hedged volume (Bbl) 128,800 — — — Weighted-average price ($/Bbl) $ 33.92 $ — $ — $ — Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 46,000 — — — Weighted-average price ($/Bbl) $ 38.22 $ — $ — $ — Swaps - Non-TET Isobutane: Hedged volume (Bbl) 18,400 — — — Weighted-average price ($/Bbl) $ 38.33 $ — $ — $ — Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 46,000 — — — Weighted-average price ($/Bbl) $ 57.02 $ — $ — $ — Total NGL volume hedged (Bbl) 395,600 — — — TABLE CONTINUES ON NEXT PAGE Remaining year 2018 Year Year Year Natural gas: Puts: Hedged volume (MMBtu) 2,055,000 — — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — $ — Collars: Hedged volume (MMBtu) 3,928,400 — — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — $ — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — $ — Totals: Total volume hedged with floor price (MMBtu) 5,983,400 — — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — $ — Total volume hedged with ceiling price (MMBtu) 3,928,400 — — — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — $ — Basis Swaps: Hedged volume (MMBtu) 2,300,000 20,075,000 25,254,000 — Weighted-average price ($/MMBtu) $ (0.62 ) $ (1.05 ) $ (0.76 ) $ — At each period end, the Company nets the fair value of derivatives by counterparty where the right of offset exists and reports this net basis on the "Derivatives" line items on the unaudited consolidated balance sheets as assets and/or liabilities. See Note 9.a for a summary of the fair value of derivatives on a gross basis. The Company's derivatives were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the "Gain (loss) on derivatives, net" line item. Gains and losses on derivatives are included in cash flows from operating activities. |
Fair value measurements
Fair value measurements | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair value measurements | Fair value measurements See Note 10 "Fair value measurements" in the 2017 Annual Report for discussion on the Company's accounting policies for fair value measurements. a. Fair value measurement on a recurring basis The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in the "Derivatives" line items on the unaudited consolidated balance sheets as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets As of September 30, 2018: Assets: Current: Oil derivatives $ — $ 10,390 $ — $ 10,390 $ (10,390 ) $ — NGL derivatives — — — — — — Natural gas derivatives — 13,002 — 13,002 (9,309 ) 3,693 Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — (619 ) (619 ) Noncurrent: Oil derivatives $ — $ 2,056 $ — $ 2,056 $ (2,056 ) $ — NGL derivatives — — — — — — Natural gas derivatives — 474 — 474 (474 ) — Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (41,692 ) $ — $ (41,692 ) $ 10,390 $ (31,302 ) NGL derivatives — (4,807 ) — (4,807 ) — (4,807 ) Natural gas derivatives — 233 — 233 9,309 9,542 Oil derivative deferred premiums — — (17,265 ) (17,265 ) — (17,265 ) Natural gas derivative deferred premiums — — (847 ) (847 ) 619 (228 ) Noncurrent: Oil derivatives $ — $ (17,279 ) $ — $ (17,279 ) $ 2,056 $ (15,223 ) NGL derivatives — — — — — — Natural gas derivatives — (2,468 ) — (2,468 ) 474 (1,994 ) Oil derivative deferred premiums — — (3,728 ) (3,728 ) — (3,728 ) Natural gas derivative deferred premiums — — — — — — Net derivative liability positions $ — $ (40,091 ) $ (21,840 ) $ (61,931 ) $ — $ (61,931 ) (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets As of December 31, 2017: Assets: Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price(s), appropriate risk-adjusted discount rates and forward price curve models for substantially similar instruments generated from a compilation of data gathered from third parties. The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date and then records the change in net present value to interest expense over the period from the trade date until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates. The deferred premiums are included in the "Derivatives" line items on the unaudited consolidated balance sheets, and as of September 30, 2018 , their input rates range from 1.91% to 3.32% with a net fair value weighted-average rate of 2.78% . The following table presents payments required for derivative deferred premiums as of September 30, 2018 for the periods presented: (in thousands) September 30, 2018 Remaining 2018 $ 5,405 2019 15,502 2020 1,295 Total $ 22,202 A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Balance of Level 3 at beginning of period $ (25,026 ) $ (12,554 ) $ (28,683 ) $ (8,998 ) Change in net present value of derivative deferred premiums (1) (168 ) (88 ) (564 ) (199 ) Total purchases and settlements of derivative deferred premiums: Purchases (2,101 ) (15,996 ) (7,523 ) (22,994 ) Settlements 5,455 1,448 14,930 5,001 Balance of Level 3 at end of period $ (21,840 ) $ (27,190 ) $ (21,840 ) $ (27,190 ) ____________________________________________________________________________ (1) These amounts are included in the "Interest expense" line item in the unaudited consolidated statements of operations. b. Fair value measurement on a nonrecurring basis See Note 10.b "Fair value measurement on a nonrecurring basis" and Note 4.c "2016 acquisitions of evaluated and unevaluated oil and natural gas properties" in the 2017 Annual Report for the Company's accounting policies and assumptions in estimating the fair values of assets acquired and liabilities assumed for acquisitions of evaluated and unevaluated oil and natural gas properties. See Note 3.a for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties for the nine months ended September 30, 2018 . Items not accounted for at fair value The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: September 30, 2018 December 31, 2017 (in thousands) Long-term Fair value (1) Long-term Fair value (1) January 2022 Notes $ 450,000 $ 448,875 $ 450,000 $ 454,500 March 2023 Notes 350,000 352,730 350,000 364,105 Senior Secured Credit Facility 170,000 170,084 — — Total $ 970,000 $ 971,689 $ 800,000 $ 818,605 ______________________________________________________________________________ (1) The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the September 30, 2018 and December 31, 2017 quoted market price (Level 1) for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of September 30, 2018 was estimated utilizing a pricing model for similar instruments (Level 2). |
Net income per common share
Net income per common share | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Net income per common share | Net income per common share Basic net income per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. The dilutive effects of these awards were calculated utilizing the treasury stock method. See Note 7.c for additional discussion on these awards. The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income per common share for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands, except for per share data) 2018 2017 2018 2017 Net income (numerator): Net income—basic and diluted $ 55,050 $ 11,027 $ 175,022 $ 140,413 Weighted-average common shares outstanding (denominator): Basic (1) 230,605 239,306 233,228 239,017 Non-vested restricted stock awards (2) 935 650 911 845 Outstanding stock option awards (3) 99 130 68 129 Non-vested performance share awards (4) — 4,801 — 4,702 Diluted 231,639 244,887 234,207 244,693 Net income per common share: Basic $ 0.24 $ 0.05 $ 0.75 $ 0.59 Diluted $ 0.24 $ 0.05 $ 0.75 $ 0.57 _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income per common share was computed taking into account share repurchases that occurred during the three and nine months ended September 30, 2018 . See Note 7.a for additional discussion of the Company's share repurchase program. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2018 . The inclusion of these non-vested restricted stock awards would be anti-dilutive due to the sum of the assumed proceeds exceeding the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2018 . The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 7.c : (i) the RTSR Performance Percentage, (ii) the ATSR Appreciation and (iii) the ROACE Percentage from the beginning of the performance period to September 30, 2018 for each of the criteria to identify the RTSR Factor, the ATSR Factor and the ROACE Factor, respectively, which were used to compute the Performance Multiple to determine the number of shares for the dilutive effect. The effects of the non-vested performance share awards granted in 2016 and 2017 were calculated utilizing the Company's TSR from the beginning of each performance share awards' respective performance period to September 30, 2018 in comparison to the TSR of the peers specified in each respective performance share awards' agreement. |
Commitments and contingencies
Commitments and contingencies | 9 Months Ended |
Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and contingencies | Commitments and contingencies a. Litigation From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, except with regard to the specific litigation noted below, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity. On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 through June 30, 2020 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the crude oil purchase agreement, court costs and attorneys' fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement, which covered the sale to Shell of 19,000 barrels of crude oil per day of the Company's gross production as well as the purchase by the Company of like-quantity crude oil from Shell. On December 11, 2017, Shell filed its First Amended Petition, in which it asserted nine causes of action, including multiple new claims for breach of contract and fraud. Effective May 1, 2018, Shell terminated the crude oil purchase agreement and ceased purchasing the Company's crude oil and selling crude oil to the Company under the terms of such agreement. As a result, the Company filed its Second Amended Answer and Original Counterclaim against Shell on June 15, 2018, in which the Company denies all allegations by Shell and seeks damages in excess of $150.0 million resulting from Shell's breach and wrongful termination of the crude oil purchase agreement. Shell filed a Second Amended Petition on June 1, 2018, in which it asserted a new cause of action against the Company for alleged repudiation of Shell's proposed reformed version of the crude oil purchase agreement, a version never signed or agreed to by the Company. Through April 30, 2018, the date on which Shell wrongfully terminated the crude oil purchase agreement, the Company had accounted for the costs and crude oil price realization as reflected in the terms of the crude oil purchase agreement. The accompanying unaudited consolidated balance sheets do not include any amounts for damage claims or attorneys' fees sought by Shell. As of September 30, 2018 , the Company had estimated an aggregate amount of $37.4 million that is the subject of Shell's claims, which is generally based on the contractual amount in dispute under the pricing election that is the subject of Shell's claims applied to the barrels of crude oil purchased and sold through the date on which Shell wrongfully terminated the crude oil purchase agreement. As a result of such termination, the Company's estimate of this unrecorded amount is not anticipated to materially increase in the future. This estimate does not include damages sought by Shell pursuant to its latest repudiation claim asserted in its Second Amended Petition or amounts sought by Shell for recovery of attorneys' fees incurred for the prosecution of its claims. The Company is unable to determine a probability of the outcome of this litigation at this time. The Company believes Shell's claims are meritless and the termination by Shell is improper and a breach of the crude oil purchase agreement. The Company therefore intends to vigorously defend itself against Shell's claims and pursue its rights under the terminated crude oil purchase agreement to seek all appropriate damages from Shell. b. Drilling contracts The Company has committed to several drilling contracts with third parties to facilitate the Company's drilling plans. Certain of these contracts are for a term of multiple months and contain early termination clauses that require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for either of the nine months ended September 30, 2018 or 2017 . The future commitment of $22.9 million as of September 30, 2018 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of these contracts in 2018. c. Firm sale and transportation commitments The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred firm transportation payments on excess pipeline capacity and other contractual penalties of $0.2 million and $0.5 million during the three months ended September 30, 2018 and 2017 , respectively, and $2.5 million and $1.1 million during the nine months ended September 30, 2018 and 2017 , respectively. For the three and nine months ended September 30, 2018 , these firm transportation payments on excess pipeline capacity and other contractual penalties are netted with the respective revenue stream in the unaudited consolidated statements of operations. For the three and nine months ended September 30, 2017 , these firm transportation payments on excess pipeline capacity and other penalties are included in the "Other operating expenses" line item in the unaudited consolidated statements of operations. See Note 4.a for additional information regarding the presentation of firm transportation payments on excess pipeline capacity and other contractual penalties. Future commitments of $367.7 million as of September 30, 2018 are not recorded in the accompanying unaudited consolidated balance sheets. For information regarding the TA related to Medallion, see Note 3.c . d. Sand purchase and supply agreement During the second quarter of 2018, the Company entered into a sand purchase and supply agreement, for a term of one year, whereby it has committed to buy a certain volume of in-basin sand, utilized in the Company's completion activities, for a fixed price. As of September 30, 2018 , under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it would incur a shortfall payment of $5.7 million at the end of the contract period. 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. 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 September 30, 2018 or December 31, 2017 . |
Supplemental cash flow informat
Supplemental cash flow information | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental cash flow information | Supplemental cash flow information The following table presents supplemental cash flow information: Nine months ended September 30, (in thousands) 2018 2017 Non-cash investing activities: (Decrease) increase in accrued capital expenditures $ (44,533 ) $ 39,156 Capitalized stock-based compensation $ 6,025 $ 5,642 Capitalized asset retirement costs $ 719 $ 670 Other supplemental cash flow information: Capitalized interest $ 710 $ 756 |
Asset retirement obligations
Asset retirement obligations | 9 Months Ended |
Sep. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligations | Asset retirement obligations See Note 2.m "Asset retirement obligations" in the 2017 Annual Report for discussion on asset retirement obligations. The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets: Nine months ended September 30, (in thousands) 2018 2017 Liability at beginning of period $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 719 492 Accretion expense 3,341 2,822 Liabilities settled due to plugging and abandonment or sale (2,246 ) (1,228 ) Revision of estimates — 178 Liability at end of period $ 57,320 $ 54,471 |
Income taxes
Income taxes | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income taxes | Income taxes The Company is subject to federal and state income taxes and the Texas franchise tax. The Company had federal net operating loss carry-forwards totaling $1.8 billion and state of Oklahoma net operating loss carry-forwards totaling $36.3 million as of September 30, 2018 , which begin expiring in 2026 and 2032, respectively. Due to the passing of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"), $86.4 million of the federal net operating loss carry-forward will not expire but may be limited in future periods. As of September 30, 2018 , the Company believes it is more likely than not that a portion of the net operating loss carry-forwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 30, 2018 , the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused and future projections of Oklahoma sourced income. As of September 30, 2018 , a full valuation allowance of $298.8 million has been recorded against the Company's federal and state of Oklahoma net deferred tax assets. As of September 30, 2018 , a Texas deferred tax liability of $1.8 million has been recorded along with the corresponding deferred income tax expense. Additionally, a current tax refund of $0.4 million of Texas franchise tax is expected as a result of differences in estimated versus actual taxable income from the gain on the Medallion Sale and is recorded as a current income tax benefit. |
Subsidiary guarantors
Subsidiary guarantors | 9 Months Ended |
Sep. 30, 2018 | |
Condensed Financial Information Disclosure [Abstract] | |
Subsidiary guarantors | Subsidiary guarantors The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the May 2022 Notes until the May 2022 Notes Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating (i) balance sheets as of September 30, 2018 and December 31, 2017 , (ii) statements of operations for the three and nine months ended September 30, 2018 and 2017 and (iii) statements of cash flows for the nine months ended September 30, 2018 and 2017 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. Condensed consolidating balance sheet September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 103,109 $ 14,472 $ — $ 117,581 Other current assets 70,413 1,533 — 71,946 Oil and natural gas properties, net 1,951,518 9,146 (22,174 ) 1,938,490 Midstream service assets, net — 132,415 — 132,415 Other fixed assets, net 42,071 193 — 42,264 Investment in subsidiaries 130,439 — (130,439 ) — Other noncurrent assets, net 13,113 3,965 — 17,078 Total assets $ 2,310,663 $ 161,724 $ (152,613 ) $ 2,319,774 Accounts payable and accrued liabilities $ 68,037 $ 18,600 $ — $ 86,637 Other current liabilities 162,893 9,739 — 172,632 Long-term debt, net 963,191 — — 963,191 Other noncurrent liabilities 79,256 2,946 — 82,202 Stockholders' equity 1,037,286 130,439 (152,613 ) 1,015,112 Total liabilities and stockholders' equity $ 2,310,663 $ 161,724 $ (152,613 ) $ 2,319,774 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Condensed consolidating statement of operations For the three months ended September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 225,970 $ 73,463 $ (19,687 ) $ 279,746 Total costs and expenses 123,942 69,146 (17,752 ) 175,336 Operating income 102,028 4,317 (1,935 ) 104,410 Interest expense (14,845 ) — — (14,845 ) Other non-operating expense (28,811 ) (26 ) (4,291 ) (33,128 ) Income before income taxes 58,372 4,291 (6,226 ) 56,437 Income tax expense (1,387 ) — — (1,387 ) Net income $ 56,985 $ 4,291 $ (6,226 ) $ 55,050 Condensed consolidating statement of operations For the three months ended September 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 157,902 $ 63,686 $ (15,770 ) $ 205,818 Total costs and expenses 97,686 62,245 (14,565 ) 145,366 Operating income 60,216 1,441 (1,205 ) 60,452 Interest expense (23,697 ) — — (23,697 ) Other non-operating income (expense) (24,287 ) 2,290 (3,731 ) (25,728 ) Income before income taxes 12,232 3,731 (4,936 ) 11,027 Income tax — — — — Net income $ 12,232 $ 3,731 $ (4,936 ) $ 11,027 Condensed consolidating statement of operations For the nine months ended September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 632,419 $ 312,784 $ (54,715 ) $ 890,488 Total costs and expenses 345,232 302,143 (49,256 ) 598,119 Operating income 287,187 10,641 (5,459 ) 292,369 Interest expense (42,787 ) — — (42,787 ) Other non-operating expense (62,532 ) (1,307 ) (9,334 ) (73,173 ) Income before income taxes 181,868 9,334 (14,793 ) 176,409 Income tax expense (1,387 ) — — (1,387 ) Net income $ 180,481 $ 9,334 $ (14,793 ) $ 175,022 Condensed consolidating statement of operations For the nine months ended September 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 439,269 $ 190,926 $ (48,370 ) $ 581,825 Total costs and expenses 276,855 183,310 (42,179 ) 417,986 Operating income 162,414 7,616 (6,191 ) 163,839 Interest expense (69,590 ) — — (69,590 ) Other non-operating income 53,780 7,622 (15,238 ) 46,164 Income before income taxes 146,604 15,238 (21,429 ) 140,413 Income tax — — — — Net income $ 146,604 $ 15,238 $ (21,429 ) $ 140,413 Condensed consolidating statement of cash flows For the nine months ended September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 402,065 $ 15,797 $ (9,334 ) $ 408,528 Change in investment between affiliates 3,115 (12,449 ) 9,334 — Capital expenditures and other (533,083 ) (3,348 ) — (536,431 ) Net cash provided by financing activities 66,151 — — 66,151 Net decrease in cash and cash equivalents (61,752 ) — — (61,752 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 50,406 $ 1 $ — $ 50,407 Condensed consolidating statement of cash flows For the nine months ended September 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 273,309 $ 13,980 $ (15,238 ) $ 272,051 Change in investment between affiliates (36,890 ) 21,652 15,238 — Capital expenditures and other (321,261 ) (35,632 ) — (356,893 ) Net cash provided by financing activities 72,988 — — 72,988 Net decrease in cash and cash equivalents (11,854 ) — — (11,854 ) Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 20,817 $ 1 $ — $ 20,818 |
Subsequent events
Subsequent events | 9 Months Ended |
Sep. 30, 2018 | |
Subsequent Events [Abstract] | |
Subsequent events | Subsequent events On October 15, 2018, the Company borrowed $20.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $190.0 million as of November 5, 2018. On October 23, 2018, pursuant to the regular semi-annual redetermination, the lenders reaffirmed the borrowing base of $1.3 billion under the Senior Secured Credit Facility. The Company's aggregate elected commitment of $1.2 billion remains unchanged. As of November 5, 2018, the Company had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility. |
Organization and basis of pre_2
Organization and basis of presentation (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Basis of presentation | Basis of presentation The accompanying unaudited 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 unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The accompanying unaudited consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 2017 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of September 30, 2018 , results of operations for the three and nine months ended September 30, 2018 and 2017 and cash flows for the nine months ended September 30, 2018 and 2017 . Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2017 Annual Report. Significant accounting policies See Note 2 "Basis of presentation and significant accounting policies" in the 2017 Annual Report for discussion of significant accounting policies. |
Use of estimates in the preparation of interim unaudited consolidated financial statements | Use of estimates in the preparation of interim unaudited consolidated financial statements The preparation of the accompanying unaudited 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. For further information regarding the estimates and assumptions, see Note 2.b "Use of estimates in the preparation of consolidated financial statements" in the 2017 Annual Report. Furthermore, see Note 7.c for a discussion of estimates pertaining to the Company's 2018 performance share awards. |
Reclassifications | Reclassifications Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income, stockholders' equity or total operating, investing or financing cash flows. |
Recently issued or adopted accounting pronouncements | Recently issued or adopted accounting pronouncements The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ASUs and a final rule issued by the SEC listed below were determined to be meaningful to the Company's unaudited consolidated financial statements and/or footnotes during the nine months ended September 30, 2018 . a. Revenue recognition On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 4 for further discussion of the ASC 606 adoption impact on the Company's unaudited consolidated financial statements and the Company's revenue recognition policies. b. Leases In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The primary effect on the Company's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. The Company has a team, including third-party consultants, to implement the standard and is implementing the software that will be used to track and account for lease activity. The Company anticipates that the adoption and implementation of ASC 842 will result in a material increase in assets and liabilities on the consolidated balance sheet but will not result in a material impact to the consolidated statement of operations. The estimate of the dollar value impact of the adoption is on-going. The Company has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption, accounting for certain asset classes at a portfolio level, and establishing a balance sheet recognition capitalization threshold. The transition will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted (January 1, 2019). The Company will utilize the transition package of expedients to leases that commenced before the effective date. The Company expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component. c. Business combinations In January 2017, the FASB issued new guidance in ASC 805, Business Combinations , to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output. The primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements. See Note 3.a for discussion of the Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU. d. Fair value measurements In August 2018, the FASB issued new guidance in ASC 820, Fair Value Measurement , to modify disclosure requirements. Of the amendments in the ASU, the below items affected the Company's fair value measurement disclosures in Note 9 . Removed disclosure requirements that should be applied retrospectively to all periods presented are: (i) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the policy for timing of transfers between levels and (iii) the valuation processes for Level 3 fair value measurements. A modified disclosure requirement that should be applied prospectively is to clarify that the measurement uncertainty disclosure communicates information about the uncertainty in measurement as of the reporting date. A new disclosure requirement that should be applied prospectively is to disclose the range and weighted-average of significant unobservable inputs used to develop Level 3 fair value measurements. The Company has elected to early adopt this guidance upon the issuance of the ASU and has modified its disclosures accordingly in this Quarterly Report. e. SEC disclosure update and simplification In August 2018, the SEC issued Final Rule Release No. 33-10532, Disclosure Update and Simplification , which amends various SEC disclosure requirements that they have determined to be redundant, duplicative, overlapping, outdated or superseded. The amendments also extend the annual disclosure requirement of presenting the changes in stockholders' equity to interim periods. An analysis of changes in stockholders’ equity will now be required for the current and comparative year-to-date interim periods. The Company has incorporated certain aspects of the final rule in this Quarterly Report and will complete the implementation of the final rule in the fourth quarter of 2018. |
Revenue recognition | Revenue recognition Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition is included below. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying unaudited consolidated statements of operations. Under certain of its customer contracts, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that we have transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Midstream Services Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate. Imbalances The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of September 30, 2018 or December 31, 2017. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less . For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the three and nine months ended September 30, 2018 , revenue recognized related to performance obligations satisfied in prior reporting periods was not material. |
Full cost | The Company excludes the costs directly associated with the acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. 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 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 employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit-of-production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities, are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. |
Treasury stock | Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock-based awards at the employees' election. |
Stock-based compensation | Stock-based compensation The Company's Long-Term Incentive Plan (the "LTIP") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock. The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and are included in the "General and administrative" line item in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the "Evaluated properties" line item on the unaudited consolidated balance sheets |
Net income per common share | Net income per common share Basic net income per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards and non-vested performance share awards. The dilutive effects of these awards were calculated utilizing the treasury stock method. |
Revenue recognition (Tables)
Revenue recognition (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Impact of adoption of ASC 606 | The impact of the adoption of ASC 606 on the results of operations for the periods presented is as follows: Three months ended September 30, 2018 Nine months ended September 30, 2018 (in thousands) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) As computed under ASC 605 As reported under ASC 606 Increase/(decrease) Revenues: Oil sales $ 160,246 $ 160,007 $ (239 ) $ 472,496 $ 469,972 $ (2,524 ) NGL sales $ 50,814 $ 50,814 $ — $ 115,979 $ 115,979 $ — Natural gas sales $ 15,043 $ 15,043 $ — $ 45,908 $ 45,908 $ — Costs and expenses: Other operating expenses $ 1,353 $ 1,114 $ (239 ) $ 5,865 $ 3,341 $ (2,524 ) Net income $ 55,050 $ 55,050 $ — $ 175,022 $ 175,022 $ — |
Property and equipment (Tables)
Property and equipment (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Property, Plant and Equipment [Abstract] | |
Schedule of property and equipment | The following table presents the Company's property and equipment as of the dates presented: (in thousands) September 30, 2018 December 31, 2017 Evaluated oil and natural gas properties $ 6,589,327 $ 6,070,940 Less accumulated depletion and impairment (4,798,527 ) (4,657,466 ) Evaluated oil and natural gas properties, net 1,790,800 1,413,474 Unevaluated oil and natural gas properties not being depleted 147,690 175,865 Midstream service assets 171,740 171,427 Less accumulated depreciation and impairment (39,325 ) (33,102 ) Midstream service assets, net 132,415 138,325 Depreciable other fixed assets 50,420 48,957 Less accumulated depreciation and amortization (26,415 ) (23,150 ) Depreciable other fixed assets, net 24,005 25,807 Land 18,259 14,914 Total property and equipment, net $ 2,113,169 $ 1,768,385 |
Schedule of employee-related costs capitalized to oil and natural gas properties | The following table presents capitalized employee-related costs for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Capitalized employee-related costs $ 5,837 $ 6,938 $ 19,101 $ 17,911 |
Costs incurred in the acquisition, exploration and development of oil and natural gas properties | The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Property acquisition costs (see Note 3.a): — Evaluated $ — $ — $ 13,847 $ — Unevaluated — — 2,790 — Exploration costs 7,502 7,136 18,747 28,337 Development costs 139,748 160,359 467,582 397,255 Total costs incurred $ 147,250 $ 167,495 $ 502,966 $ 425,592 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of debt | The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented: September 30, 2018 December 31, 2017 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2022 Notes $ 450,000 $ (3,254 ) $ 446,746 $ 450,000 $ (3,987 ) $ 446,013 March 2023 Notes 350,000 (3,555 ) 346,445 350,000 (4,158 ) 345,842 Senior Secured Credit Facility (1) 170,000 — 170,000 — — — Total $ 970,000 $ (6,809 ) $ 963,191 $ 800,000 $ (8,145 ) $ 791,855 ______________________________________________________________________________ (1) Debt issuance costs, net related to our Senior Secured Credit Facility of $7.4 million and $6.0 million as of September 30, 2018 and December 31, 2017 , respectively, are reported in "Other assets, net" on the unaudited consolidated balance sheets. |
Stockholders' equity and stoc_2
Stockholders' equity and stock-based compensation (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Schedule of restricted stock award activity | The following table reflects the restricted stock award activity for the nine months ended September 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Restricted stock awards Weighted-average (per award) Outstanding as of December 31, 2017 3,169 $ 12.81 Granted 3,248 $ 8.42 Forfeited (266 ) $ 10.35 Vested (1) (1,851 ) $ 12.21 Outstanding as of September 30, 2018 4,300 $ 9.90 _____________________________________________________________________________ (1) The total intrinsic value of vested restricted stock awards for the nine months ended September 30, 2018 was $16.1 million . |
Schedule of performance share award activity | The following table reflects the performance share award activity for the nine months ended September 30, 2018 : (in thousands, except for weighted-average grant-date fair value) Performance share awards Weighted-average (per award) Outstanding as of December 31, 2017 2,745 $ 17.77 Granted (1) 1,389 $ 9.22 Forfeited (149 ) $ 14.83 Vested (2) (454 ) $ 16.23 Outstanding as of September 30, 2018 3,531 $ 14.55 ______________________________________________________________________________ (1) The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $ 9.22 per unit grant-date fair value consists of a (i) $ 10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $ 8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020. (2) The performance share awards granted on February 27, 2015 had a performance period of January 1, 2015 to December 31, 2017 and, as their performance criteria were not satisfied, resulted in a TSR modifier of 0 % based on the Company finishing in the 36th percentile of its peer group for relative TSR. As such, the units were not converted into the Company's common stock during the first quarter of 2018. |
Schedule of share-based payment award, equity instruments other than options, valuation assumptions | The assumptions used to estimate the combined fair value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the performance share awards granted on the date presented are as follows: February 16, 2018 Risk-free interest rate (1) 2.34 % Dividend yield — % Expected volatility (2) 65.49 % Laredo stock closing price on grant date $ 8.36 Combined fair value per performance share award for the (.25) RTSR Factor and the (.25) ATSR Factor (3) $ 10.08 ______________________________________________________________________________ (1) The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date. (2) The Company utilized its own historical volatility in order to develop the expected volatility. (3) The market criteria portion of the performance share award represents 50% of each of the amount of stock potentially payable, if any, and the grant-date fair value of the award. |
Schedule of allocated share-based compensation costs | The following has been recorded to stock-based compensation expense for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Restricted stock award compensation $ 6,001 $ 5,422 $ 19,332 $ 16,856 Stock option award compensation 970 1,159 3,010 3,600 Performance share award compensation 3,689 4,255 12,431 12,063 Total stock-based compensation, gross 10,660 10,836 34,773 32,519 Less amounts capitalized in oil and natural gas properties (1,927 ) (1,870 ) (6,025 ) (5,642 ) Total stock-based compensation, net $ 8,733 $ 8,966 $ 28,748 $ 26,877 |
Derivatives (Tables)
Derivatives (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative instrument terminated | The following details the derivative that was terminated: Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period Oil swap 1,095,000 $ 52.12 $ 52.12 January 2018 - December 2018 |
Summary of open positions and derivatives in place | The following table summarizes open positions as of September 30, 2018 , and represents, as of such date, derivatives in place through December 2021 on annual production volumes: Remaining year 2018 Year Year Year Oil: Puts: Hedged volume (Bbl) 1,367,775 8,030,000 366,000 — Weighted-average floor price ($/Bbl) $ 51.93 $ 47.45 $ 45.00 $ — Swaps: Hedged volume (Bbl) — 657,000 695,400 — Weighted-average price ($/Bbl) $ — $ 53.45 $ 52.18 $ — Collars: Hedged volume (Bbl) 1,030,400 — 1,134,600 912,500 Weighted-average floor price ($/Bbl) $ 41.43 $ — $ 45.00 $ 45.00 Weighted-average ceiling price ($/Bbl) $ 60.00 $ — $ 76.13 $ 71.00 Totals: Total volume hedged with floor price (Bbl) 2,398,175 8,687,000 2,196,000 912,500 Weighted-average floor price ($/Bbl) $ 47.42 $ 47.91 $ 47.27 $ 45.00 Total volume hedged with ceiling price (Bbl) 1,030,400 657,000 1,830,000 912,500 Weighted-average ceiling price ($/Bbl) $ 60.00 $ 53.45 $ 67.03 $ 71.00 Basis Swaps: WTI Midland to WTI Cushing: Hedged volume (Bbl) 920,000 552,000 — — Weighted-average price ($/Bbl) $ (0.56 ) $ (4.37 ) $ — $ — WTI Houston to WTI Midland: Hedged volume (Bbl) 920,000 1,810,000 — — Weighted-average price ($/Bbl) $ 7.30 $ 7.30 $ — $ — NGL: Swaps - Purity Ethane: Hedged volume (Bbl) 156,400 — — — Weighted-average price ($/Bbl) $ 11.66 $ — $ — $ — Swaps - Non-TET Propane: Hedged volume (Bbl) 128,800 — — — Weighted-average price ($/Bbl) $ 33.92 $ — $ — $ — Swaps - Non-TET Normal Butane: Hedged volume (Bbl) 46,000 — — — Weighted-average price ($/Bbl) $ 38.22 $ — $ — $ — Swaps - Non-TET Isobutane: Hedged volume (Bbl) 18,400 — — — Weighted-average price ($/Bbl) $ 38.33 $ — $ — $ — Swaps - Non-TET Natural Gasoline: Hedged volume (Bbl) 46,000 — — — Weighted-average price ($/Bbl) $ 57.02 $ — $ — $ — Total NGL volume hedged (Bbl) 395,600 — — — TABLE CONTINUES ON NEXT PAGE Remaining year 2018 Year Year Year Natural gas: Puts: Hedged volume (MMBtu) 2,055,000 — — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — $ — Collars: Hedged volume (MMBtu) 3,928,400 — — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — $ — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — $ — Totals: Total volume hedged with floor price (MMBtu) 5,983,400 — — — Weighted-average floor price ($/MMBtu) $ 2.50 $ — $ — $ — Total volume hedged with ceiling price (MMBtu) 3,928,400 — — — Weighted-average ceiling price ($/MMBtu) $ 3.35 $ — $ — $ — Basis Swaps: Hedged volume (MMBtu) 2,300,000 20,075,000 25,254,000 — Weighted-average price ($/MMBtu) $ (0.62 ) $ (1.05 ) $ (0.76 ) $ — |
Fair value measurements (Tables
Fair value measurements (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis | The following tables summarize the Company's derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation included in the "Derivatives" line items on the unaudited consolidated balance sheets as of the dates presented: (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets As of September 30, 2018: Assets: Current: Oil derivatives $ — $ 10,390 $ — $ 10,390 $ (10,390 ) $ — NGL derivatives — — — — — — Natural gas derivatives — 13,002 — 13,002 (9,309 ) 3,693 Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — (619 ) (619 ) Noncurrent: Oil derivatives $ — $ 2,056 $ — $ 2,056 $ (2,056 ) $ — NGL derivatives — — — — — — Natural gas derivatives — 474 — 474 (474 ) — Oil derivative deferred premiums — — — — — — Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (41,692 ) $ — $ (41,692 ) $ 10,390 $ (31,302 ) NGL derivatives — (4,807 ) — (4,807 ) — (4,807 ) Natural gas derivatives — 233 — 233 9,309 9,542 Oil derivative deferred premiums — — (17,265 ) (17,265 ) — (17,265 ) Natural gas derivative deferred premiums — — (847 ) (847 ) 619 (228 ) Noncurrent: Oil derivatives $ — $ (17,279 ) $ — $ (17,279 ) $ 2,056 $ (15,223 ) NGL derivatives — — — — — — Natural gas derivatives — (2,468 ) — (2,468 ) 474 (1,994 ) Oil derivative deferred premiums — — (3,728 ) (3,728 ) — (3,728 ) Natural gas derivative deferred premiums — — — — — — Net derivative liability positions $ — $ (40,091 ) $ (21,840 ) $ (61,931 ) $ — $ (61,931 ) (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets As of December 31, 2017: Assets: Current: Oil derivatives $ — $ 7,427 $ — $ 7,427 $ (3,721 ) $ 3,706 NGL derivatives — — — — — — Natural gas derivatives — 10,546 — 10,546 (4,817 ) 5,729 Oil derivative deferred premiums — — — — (87 ) (87 ) Natural gas derivative deferred premiums — — — — (2,456 ) (2,456 ) Noncurrent: Oil derivatives $ — $ 11,613 $ — $ 11,613 $ (6,087 ) $ 5,526 NGL derivatives — — — — — — Natural gas derivatives — 934 — 934 (934 ) — Oil derivative deferred premiums — — — — (2,113 ) (2,113 ) Natural gas derivative deferred premiums — — — — — — Liabilities: Current: Oil derivatives $ — $ (12,477 ) $ — $ (12,477 ) $ 3,721 $ (8,756 ) NGL derivatives — — — — — — Natural gas derivatives — — — — 4,817 4,817 Oil derivative deferred premiums — — (18,202 ) (18,202 ) 87 (18,115 ) Natural gas derivative deferred premiums — — (3,352 ) (3,352 ) 2,456 (896 ) Noncurrent: Oil derivatives $ — $ (2,389 ) $ — $ (2,389 ) $ 6,087 $ 3,698 NGL derivatives — — — — — — Natural gas derivatives — — — — 934 934 Oil derivative deferred premiums — — (7,129 ) (7,129 ) 2,113 (5,016 ) Natural gas derivative deferred premiums — — — — — — Net derivative asset (liability) positions $ — $ 15,654 $ (28,683 ) $ (13,029 ) $ — $ (13,029 ) |
Actual cash payments required for deferred premium contracts | The following table presents payments required for derivative deferred premiums as of September 30, 2018 for the periods presented: (in thousands) September 30, 2018 Remaining 2018 $ 5,405 2019 15,502 2020 1,295 Total $ 22,202 |
Summary of changes in net assets classified as Level 3 measurements | A summary of the changes in net assets and liabilities classified as Level 3 measurements for the periods presented are as follows: Three months ended September 30, Nine months ended September 30, (in thousands) 2018 2017 2018 2017 Balance of Level 3 at beginning of period $ (25,026 ) $ (12,554 ) $ (28,683 ) $ (8,998 ) Change in net present value of derivative deferred premiums (1) (168 ) (88 ) (564 ) (199 ) Total purchases and settlements of derivative deferred premiums: Purchases (2,101 ) (15,996 ) (7,523 ) (22,994 ) Settlements 5,455 1,448 14,930 5,001 Balance of Level 3 at end of period $ (21,840 ) $ (27,190 ) $ (21,840 ) $ (27,190 ) ____________________________________________________________________________ (1) These amounts are included in the "Interest expense" line item in the unaudited consolidated statements of operations. |
Schedule of carrying amount and fair value of debt instruments | The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: September 30, 2018 December 31, 2017 (in thousands) Long-term Fair value (1) Long-term Fair value (1) January 2022 Notes $ 450,000 $ 448,875 $ 450,000 $ 454,500 March 2023 Notes 350,000 352,730 350,000 364,105 Senior Secured Credit Facility 170,000 170,084 — — Total $ 970,000 $ 971,689 $ 800,000 $ 818,605 ______________________________________________________________________________ (1) The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the September 30, 2018 and December 31, 2017 quoted market price (Level 1) for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of September 30, 2018 was estimated utilizing a pricing model for similar instruments (Level 2). |
Net income per common share (T
Net income per common share (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of calculation of basic and diluted weighted-average common shares outstanding and net income per common share | The following table reflects the calculation of basic and diluted weighted-average common shares outstanding and net income per common share for the periods presented: Three months ended September 30, Nine months ended September 30, (in thousands, except for per share data) 2018 2017 2018 2017 Net income (numerator): Net income—basic and diluted $ 55,050 $ 11,027 $ 175,022 $ 140,413 Weighted-average common shares outstanding (denominator): Basic (1) 230,605 239,306 233,228 239,017 Non-vested restricted stock awards (2) 935 650 911 845 Outstanding stock option awards (3) 99 130 68 129 Non-vested performance share awards (4) — 4,801 — 4,702 Diluted 231,639 244,887 234,207 244,693 Net income per common share: Basic $ 0.24 $ 0.05 $ 0.75 $ 0.59 Diluted $ 0.24 $ 0.05 $ 0.75 $ 0.57 _____________________________________________________________________________ (1) Weighted-average common shares outstanding used in the computation of basic and diluted net income per common share was computed taking into account share repurchases that occurred during the three and nine months ended September 30, 2018 . See Note 7.a for additional discussion of the Company's share repurchase program. (2) The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2018 . The inclusion of these non-vested restricted stock awards would be anti-dilutive due to the sum of the assumed proceeds exceeding the average stock price during the period. (3) The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2018 . The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period. (4) The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 7.c : (i) the RTSR Performance Percentage, (ii) the ATSR Appreciation and (iii) the ROACE Percentage from the beginning of the performance period to September 30, 2018 for each of the criteria to identify the RTSR Factor, the ATSR Factor and the ROACE Factor, respectively, which were used to compute the Performance Multiple to determine the number of shares for the dilutive effect. The effects of the non-vested performance share awards granted in 2016 and 2017 were calculated utilizing the Company's TSR from the beginning of each performance share awards' respective performance period to September 30, 2018 in comparison to the TSR of the peers specified in each respective performance share awards' agreement. |
Supplemental cash flow inform_2
Supplemental cash flow information (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule of non-cash investing & financing and supplemental cash flow information | The following table presents supplemental cash flow information: Nine months ended September 30, (in thousands) 2018 2017 Non-cash investing activities: (Decrease) increase in accrued capital expenditures $ (44,533 ) $ 39,156 Capitalized stock-based compensation $ 6,025 $ 5,642 Capitalized asset retirement costs $ 719 $ 670 Other supplemental cash flow information: Capitalized interest $ 710 $ 756 |
Asset retirement obligations (T
Asset retirement obligations (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of asset retirement obligation liability | The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets: Nine months ended September 30, (in thousands) 2018 2017 Liability at beginning of period $ 55,506 $ 52,207 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 719 492 Accretion expense 3,341 2,822 Liabilities settled due to plugging and abandonment or sale (2,246 ) (1,228 ) Revision of estimates — 178 Liability at end of period $ 57,320 $ 54,471 |
Subsidiary guarantors (Tables)
Subsidiary guarantors (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Condensed Financial Information Disclosure [Abstract] | |
Schedule of condensed consolidating balance sheet | Condensed consolidating balance sheet September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 103,109 $ 14,472 $ — $ 117,581 Other current assets 70,413 1,533 — 71,946 Oil and natural gas properties, net 1,951,518 9,146 (22,174 ) 1,938,490 Midstream service assets, net — 132,415 — 132,415 Other fixed assets, net 42,071 193 — 42,264 Investment in subsidiaries 130,439 — (130,439 ) — Other noncurrent assets, net 13,113 3,965 — 17,078 Total assets $ 2,310,663 $ 161,724 $ (152,613 ) $ 2,319,774 Accounts payable and accrued liabilities $ 68,037 $ 18,600 $ — $ 86,637 Other current liabilities 162,893 9,739 — 172,632 Long-term debt, net 963,191 — — 963,191 Other noncurrent liabilities 79,256 2,946 — 82,202 Stockholders' equity 1,037,286 130,439 (152,613 ) 1,015,112 Total liabilities and stockholders' equity $ 2,310,663 $ 161,724 $ (152,613 ) $ 2,319,774 Condensed consolidating balance sheet December 31, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Accounts receivable, net $ 79,413 $ 21,232 $ — $ 100,645 Other current assets 132,219 2,518 — 134,737 Oil and natural gas properties, net 1,596,834 9,220 (16,715 ) 1,589,339 Midstream service assets, net — 138,325 — 138,325 Other fixed assets, net 40,344 377 — 40,721 Investment in subsidiaries (7,566 ) — 7,566 — Other noncurrent assets, net 15,526 3,996 — 19,522 Total assets $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 Accounts payable and accrued liabilities $ 34,550 $ 23,791 $ — $ 58,341 Other current liabilities 193,104 25,974 — 219,078 Long-term debt, net 791,855 — — 791,855 Other noncurrent liabilities 54,967 133,469 — 188,436 Stockholders' equity 782,294 (7,566 ) (9,149 ) 765,579 Total liabilities and stockholders' equity $ 1,856,770 $ 175,668 $ (9,149 ) $ 2,023,289 |
Schedule of condensed consolidating statement of operations | Condensed consolidating statement of operations For the three months ended September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 225,970 $ 73,463 $ (19,687 ) $ 279,746 Total costs and expenses 123,942 69,146 (17,752 ) 175,336 Operating income 102,028 4,317 (1,935 ) 104,410 Interest expense (14,845 ) — — (14,845 ) Other non-operating expense (28,811 ) (26 ) (4,291 ) (33,128 ) Income before income taxes 58,372 4,291 (6,226 ) 56,437 Income tax expense (1,387 ) — — (1,387 ) Net income $ 56,985 $ 4,291 $ (6,226 ) $ 55,050 Condensed consolidating statement of operations For the three months ended September 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 157,902 $ 63,686 $ (15,770 ) $ 205,818 Total costs and expenses 97,686 62,245 (14,565 ) 145,366 Operating income 60,216 1,441 (1,205 ) 60,452 Interest expense (23,697 ) — — (23,697 ) Other non-operating income (expense) (24,287 ) 2,290 (3,731 ) (25,728 ) Income before income taxes 12,232 3,731 (4,936 ) 11,027 Income tax — — — — Net income $ 12,232 $ 3,731 $ (4,936 ) $ 11,027 Condensed consolidating statement of operations For the nine months ended September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 632,419 $ 312,784 $ (54,715 ) $ 890,488 Total costs and expenses 345,232 302,143 (49,256 ) 598,119 Operating income 287,187 10,641 (5,459 ) 292,369 Interest expense (42,787 ) — — (42,787 ) Other non-operating expense (62,532 ) (1,307 ) (9,334 ) (73,173 ) Income before income taxes 181,868 9,334 (14,793 ) 176,409 Income tax expense (1,387 ) — — (1,387 ) Net income $ 180,481 $ 9,334 $ (14,793 ) $ 175,022 Condensed consolidating statement of operations For the nine months ended September 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Total revenues $ 439,269 $ 190,926 $ (48,370 ) $ 581,825 Total costs and expenses 276,855 183,310 (42,179 ) 417,986 Operating income 162,414 7,616 (6,191 ) 163,839 Interest expense (69,590 ) — — (69,590 ) Other non-operating income 53,780 7,622 (15,238 ) 46,164 Income before income taxes 146,604 15,238 (21,429 ) 140,413 Income tax — — — — Net income $ 146,604 $ 15,238 $ (21,429 ) $ 140,413 |
Schedule of condensed consolidating statement of cash flows | Condensed consolidating statement of cash flows For the nine months ended September 30, 2018 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 402,065 $ 15,797 $ (9,334 ) $ 408,528 Change in investment between affiliates 3,115 (12,449 ) 9,334 — Capital expenditures and other (533,083 ) (3,348 ) — (536,431 ) Net cash provided by financing activities 66,151 — — 66,151 Net decrease in cash and cash equivalents (61,752 ) — — (61,752 ) Cash and cash equivalents, beginning of period 112,158 1 — 112,159 Cash and cash equivalents, end of period $ 50,406 $ 1 $ — $ 50,407 Condensed consolidating statement of cash flows For the nine months ended September 30, 2017 (in thousands) Laredo Subsidiary Intercompany Consolidated Net cash provided by operating activities $ 273,309 $ 13,980 $ (15,238 ) $ 272,051 Change in investment between affiliates (36,890 ) 21,652 15,238 — Capital expenditures and other (321,261 ) (35,632 ) — (356,893 ) Net cash provided by financing activities 72,988 — — 72,988 Net decrease in cash and cash equivalents (11,854 ) — — (11,854 ) Cash and cash equivalents, beginning of period 32,671 1 — 32,672 Cash and cash equivalents, end of period $ 20,817 $ 1 $ — $ 20,818 |
Acquisitions and divestitures -
Acquisitions and divestitures - 2018 acquisitions of evaluated and unevaluated oil and natural gas properties (Details) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018USD ($)aproperty | Sep. 30, 2017USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Acquisitions of oil and natural gas properties | $ 16,340 | $ 0 |
Leasehold interests and working interests acquired in glasscock county | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Net acres | a | 895 | |
Number of producing wells | property | 47 | |
Acquisitions of oil and natural gas properties | $ 16,300 |
Acquisitions and divestitures_2
Acquisitions and divestitures - 2018 divestitures of evaluated and unevaluated oil and natural gas properties and midstream assets (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018USD ($)aproperty | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)aproperty | Sep. 30, 2017USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Loss on disposal of assets, net | $ (616) | $ (991) | $ (4,591) | $ (400) |
Glasscock and Howard | Disposal Group, Disposed of by Sale, Not Discontinued Operations | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net acres | a | 3,070 | 3,070 | ||
Number of producing wells | property | 24 | 24 | ||
Proceeds, net of working capital and post-closing adjustments | $ 12,000 | $ 12,000 | ||
Adjustments to oil and natural gas properties | $ 11,500 | 11,500 | ||
Loss on disposal of assets, net | $ (1,000) |
Acquisitions and divestitures_3
Acquisitions and divestitures - 2017 Medallion sale (Details) - USD ($) $ in Thousands | Feb. 01, 2018 | Oct. 30, 2017 | Feb. 01, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Oct. 29, 2017 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Proceeds from disposition of equity method investee, net of selling costs (see Note 3.c) | $ 1,655 | $ 0 | ||||
Variable interest entity, not primary beneficiary | Medallion Gathering And Processing LLC | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Ownership percentage by noncontrolling owners | 49.00% | |||||
Ownership percentage held by investment partner | 51.00% | |||||
Variable interest entity super majority voting percentage required for key decisions | 75.00% | |||||
Percent of ownership interests sold | 100.00% | |||||
Ownership interest | 49.00% | |||||
Proceeds from disposition of equity method investee, net of selling costs (see Note 3.c) | $ 1,700 | $ 829,600 | $ 831,300 | |||
Global infrastructure partners | Variable interest entity, not primary beneficiary | Medallion Gathering And Processing LLC | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Cash consideration for sale | $ 1,825,000 |
Acquisitions and divestitures_4
Acquisitions and divestitures - 2017 divestiture of evaluated and unevaluated oil and natural gas properties (Details) - Disposal Group, Disposed of by Sale, Not Discontinued Operations - Midland Basin $ in Millions | Jan. 31, 2017USD ($)aproperty |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Net acres | a | 2,900 |
Number of producing wells | property | 16 |
Sale price | $ 59.7 |
Proceeds, net of working capital and post-closing adjustments | $ 59.5 |
Revenue recognition - Impact of
Revenue recognition - Impact of ASC 606 adoption (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | $ 279,746 | $ 205,818 | $ 890,488 | $ 581,825 | |
Other operating expenses | 1,114 | 1,443 | 3,341 | 3,906 | |
Net income | 55,050 | 11,027 | 175,022 | 140,413 | |
Retained earnings | (1,352,968) | (1,352,968) | $ (1,669,108) | ||
As computed under ASC 605 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Other operating expenses | 1,353 | 5,865 | |||
Net income | 55,050 | 175,022 | |||
Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Other operating expenses | (239) | (2,524) | |||
Net income | 0 | 0 | |||
Retained earnings | 141,100 | ||||
Oil sales | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | 160,007 | 110,194 | 469,972 | 313,875 | |
Oil sales | As computed under ASC 605 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | 160,246 | 472,496 | |||
Oil sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | (239) | (2,524) | |||
NGL sales | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | 50,814 | 27,700 | 115,979 | 68,329 | |
NGL sales | As computed under ASC 605 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | 50,814 | 115,979 | |||
NGL sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | 0 | 0 | |||
Natural gas sales | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | 15,043 | $ 19,664 | 45,908 | $ 55,927 | |
Natural gas sales | As computed under ASC 605 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | 15,043 | 45,908 | |||
Natural gas sales | Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09 | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Revenues | $ 0 | $ 0 | |||
Variable interest entity, not primary beneficiary | Medallion Gathering And Processing LLC | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Maximum loss exposure | $ 141,100 |
Revenue recognition - Revenue r
Revenue recognition - Revenue recognition (Details) | 9 Months Ended |
Sep. 30, 2018 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Practical expedient in ASC 606-10-50-14 | the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less |
Minimum | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Settlement statements and payments period | 30 days |
Maximum | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Settlement statements and payments period | 90 days |
Property and equipment - Compan
Property and equipment - Company property and equipment (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Property, Plant and Equipment [Line Items] | ||
Evaluated oil and natural gas properties | $ 6,589,327 | $ 6,070,940 |
Less accumulated depletion and impairment | (4,798,527) | (4,657,466) |
Evaluated oil and natural gas properties, net | 1,790,800 | 1,413,474 |
Unevaluated properties not being depleted | 147,690 | 175,865 |
Property and equipment, net | 2,113,169 | 1,768,385 |
Midstream service assets | ||
Property, Plant and Equipment [Line Items] | ||
Midstream service assets | 171,740 | 171,427 |
Less accumulated depreciation and impairment | (39,325) | (33,102) |
Property and equipment, net | 132,415 | 138,325 |
Depreciable other fixed assets | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable other fixed assets | 50,420 | 48,957 |
Less accumulated depreciation and impairment | (26,415) | (23,150) |
Property and equipment, net | 24,005 | 25,807 |
Land | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable other fixed assets | $ 18,259 | $ 14,914 |
Property and equipment - Other
Property and equipment - Other property and equipment information (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018USD ($)$ / Boe | Sep. 30, 2017USD ($)$ / Boe | Sep. 30, 2018USD ($)$ / Boe | Sep. 30, 2017USD ($)$ / Boe | |
Property, Plant and Equipment [Abstract] | ||||
Depletion expense (in dollars per BOE) | $ / Boe | 7.94 | 6.80 | 7.67 | 6.57 |
Capitalized employee-related costs | $ | $ 5,837 | $ 6,938 | $ 19,101 | $ 17,911 |
Property and equipment - Costs
Property and equipment - Costs incurred in the acquisition, exploration and development of oil and natural gas properties (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Property acquisition costs (see Note 3.a): | ||||
Evaluated | $ 0 | $ 0 | $ 13,847 | $ 0 |
Unevaluated | 0 | 0 | 2,790 | 0 |
Exploration costs | 7,502 | 7,136 | 18,747 | 28,337 |
Development costs | 139,748 | 160,359 | 467,582 | 397,255 |
Total costs incurred | $ 147,250 | $ 167,495 | $ 502,966 | $ 425,592 |
Debt - March 2023 Notes (Detail
Debt - March 2023 Notes (Details) - Senior Notes - March 2023 Notes | Mar. 18, 2015USD ($) |
Debt Instrument [Line Items] | |
Face amount of debt | $ 350,000,000 |
Interest rate (as a percent) | 6.25% |
From March 15, 2018 until March 15, 2021 | |
Debt Instrument [Line Items] | |
Debt call price percentage | 104.688% |
On or After March 15, 2021 | |
Debt Instrument [Line Items] | |
Debt call price percentage | 100.00% |
Debt - January 2022 Notes (Deta
Debt - January 2022 Notes (Details) - Senior Notes - January 2022 Notes | Jan. 23, 2014USD ($) |
Debt Instrument [Line Items] | |
Face amount of debt | $ 450,000,000 |
Interest rate (as a percent) | 5.625% |
From January 15, 2017 until January 15, 2020 | |
Debt Instrument [Line Items] | |
Debt call price percentage | 102.813% |
On or After January 15, 2020 | |
Debt Instrument [Line Items] | |
Debt call price percentage | 100.00% |
Debt - May 2022 Notes (Details)
Debt - May 2022 Notes (Details) - Senior Notes - May 2022 Notes - USD ($) | Nov. 29, 2017 | Apr. 27, 2012 |
Debt Instrument [Line Items] | ||
Face amount of debt | $ 500,000,000 | |
Interest rate (as a percent) | 7.375% | |
Repurchased face amount of debt | $ 500,000,000 | |
Debt call price percentage | 103.688% | |
Loss on extinguishment of debt | $ 23,800,000 |
Debt - Senior Secured Credit Fa
Debt - Senior Secured Credit Facility (Details) - Secured debt - USD ($) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | |
Senior Secured Credit Facility | |||
Debt Instrument [Line Items] | |||
Early maturity date description | 90 years | ||
Maximum borrowing capacity | $ 2,000,000,000 | $ 2,000,000,000 | |
Current borrowing capacity | 1,300,000,000 | 1,300,000,000 | |
Aggregate elected commitment | 1,200,000,000 | 1,200,000,000 | |
Amount outstanding | $ 170,000,000 | $ 170,000,000 | |
Credit facility, interest rate at period end (as a percent) | 3.44% | 3.44% | |
Senior Secured Credit Facility | Minimum | |||
Debt Instrument [Line Items] | |||
Line of credit facility, unused capacity, commitment fee percentage | 0.375% | ||
Senior Secured Credit Facility | Maximum | |||
Debt Instrument [Line Items] | |||
Line of credit facility, unused capacity, commitment fee percentage | 0.50% | ||
Letter of Credit | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 80,000,000 | $ 80,000,000 | |
Letters of credit outstanding | $ 0 | $ 0 | $ 0 |
Debt - Long-term debt, net (Det
Debt - Long-term debt, net (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Long-term debt | $ 970,000 | $ 800,000 |
Debt issuance costs, net | (6,809) | (8,145) |
Long-term debt, net | 963,191 | 791,855 |
Senior Notes | January 2022 Notes | ||
Debt Instrument [Line Items] | ||
Long-term debt | 450,000 | 450,000 |
Debt issuance costs, net | (3,254) | (3,987) |
Long-term debt, net | 446,746 | 446,013 |
Senior Notes | March 2023 Notes | ||
Debt Instrument [Line Items] | ||
Long-term debt | 350,000 | 350,000 |
Debt issuance costs, net | (3,555) | (4,158) |
Long-term debt, net | 346,445 | 345,842 |
Secured debt | Senior Secured Credit Facility | ||
Debt Instrument [Line Items] | ||
Long-term debt | 170,000 | 0 |
Debt issuance costs, net | 0 | 0 |
Long-term debt, net | 170,000 | 0 |
Secured debt | Senior Secured Credit Facility | Other Assets | ||
Debt Instrument [Line Items] | ||
Debt issuance costs related to line of credit arrangements | $ 7,400 | $ 6,000 |
Stockholders' equity and stoc_3
Stockholders' equity and stock-based compensation - Share repurchase program - Narrative (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2018 | Feb. 28, 2018 | |
Equity [Abstract] | |||
Share repurchase program, authorized amount | $ 200,000,000 | ||
Shares repurchased (in shares) | 1,170,190 | 11,048,742 | |
Weighted-average price per repurchased share (in dollars per share) | $ 8.41 | $ 8.78 | |
Shares repurchased and retired, value | $ 9,900,000 | $ 97,100,000 |
Stockholders' equity and stoc_4
Stockholders' equity and stock-based compensation - Restricted Stock Awards - Narrative (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($)shares | |
Restricted stock awards | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock-based compensation not yet recognized | $ | $ 26.5 |
Stock-based compensation not yet recognized, period for recognition (in years) | 1 year 10 months 13 days |
Restricted stock awards | Vesting Alternative One, One Year From Grant Date | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting percentage | 33.00% |
Restricted stock awards | Vesting Alternative One, Two Years From Grant Date | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting percentage | 33.00% |
Restricted stock awards | Vesting Alternative One, Three Years From Grant Date | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting percentage | 34.00% |
Restricted stock awards | Vesting Alternative Two, Fully One Year From Grant Date | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting percentage | 100.00% |
Restricted stock awards | Non-employee Director | Vesting Alternative Two, Fully One Year From Grant Date | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting percentage | 100.00% |
Restricted stock awards | Non-employee Director | Vesting Alternative Three, Immediately on Grant Date | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Vesting percentage | 100.00% |
Long-Term Incentive Plan | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares authorized for issuance | shares | 24,350,000 |
Stockholders' equity and stoc_5
Stockholders' equity and stock-based compensation - Restricted Stock Awards - Outstanding restricted stock awards (Details) - Restricted stock awards $ / shares in Units, shares in Thousands, $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($)$ / sharesshares | |
Restricted stock awards | |
Outstanding at the beginning of the period (in shares) | shares | 3,169 |
Granted (in shares) | shares | 3,248 |
Forfeited (in shares) | shares | (266) |
Vested (in shares) | shares | (1,851) |
Outstanding at the end of the period (in shares) | shares | 4,300 |
Weighted-average grant-date fair value (per award) | |
Outstanding at the beginning of the period (in dollars per share) | $ / shares | $ 12.81 |
Granted (in dollars per share) | $ / shares | 8.42 |
Forfeited (in dollars per share) | $ / shares | 10.35 |
Vested (in dollars per share) | $ / shares | 12.21 |
Outstanding at the end of the period (in dollars per share) | $ / shares | $ 9.90 |
Equity instruments other than options, aggregate intrinsic value, vested | $ | $ 16.1 |
Stockholders' equity and stoc_6
Stockholders' equity and stock-based compensation - Stock Option Awards - Narrative (Details) - Stock option awards $ / shares in Units, $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($)anniversaryinstallment$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of installments over which awards vest and are exercisable | installment | 4 |
Number of anniversaries over which awards vest and are exercisable | anniversary | 4 |
Number of options outstanding (in shares) | 2,577,205 |
Options outstanding, weighted average exercise price (in dollars per share) | $ / shares | $ 12.66 |
Options outstanding, weighted-average remaining contractual term | 6 years 4 months 15 days |
Granted (in shares) | 0 |
Exercises (in shares) | 0 |
Forfeitures (in shares) | 0 |
Expired or cancellations (in shares) | 0 |
Requisite service period of the awards | 4 years |
Share-based compensation, not yet recognized, stock options | $ | $ 5 |
Stock-based compensation not yet recognized, period for recognition (in years) | 1 year 8 months 2 days |
Stockholders' equity and stoc_7
Stockholders' equity and stock-based compensation - Performance Share Awards - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 16, 2018 | Sep. 30, 2018 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
RTSR Factor weight | 25.00% | |
ATSR Factor weight | 25.00% | |
Performance share awards | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Requisite service period of the awards | 3 years | |
Grant-date fair value (in dollars per share) | $ 9.22 | |
Stock-based compensation not yet recognized | $ 18.6 | |
Stock-based compensation not yet recognized, period for recognition | 1 year 8 months 19 days | |
Performance share awards with market criteria | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Grant-date fair value (in dollars per share) | $ 10.08 | |
February 16, 2018 | Performance share awards | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Grant-date fair value (in dollars per share) | $ 9.22 | |
February 16, 2018 | Performance share awards with market criteria | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
RTSR Factor weight | 25.00% | |
ATSR Factor weight | 25.00% | |
Grant-date fair value (in dollars per share) | $ 10.08 | |
February 16, 2018 | Performance share awards with performance criteria | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
ROACE Factor weight | 50.00% | |
Grant-date fair value (in dollars per share) | $ 8.36 | |
February 27, 2015 | Performance share awards | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
TSR Modifier | 0 |
Stockholders' equity and stoc_8
Stockholders' equity and stock-based compensation - Performance Share Awards - award activity (Details) - Performance share awards shares in Thousands | 9 Months Ended |
Sep. 30, 2018$ / sharesshares | |
Performance share awards | |
Outstanding at the beginning of the period (in shares) | shares | 2,745 |
Granted (in shares) | shares | 1,389 |
Forfeited (in shares) | shares | (149) |
Vested (in shares) | shares | (454) |
Outstanding at the end of the period (in shares) | shares | 3,531 |
Weighted-average grant-date fair value (per award) | |
Outstanding at the beginning of the period (in dollars per share) | $ / shares | $ 17.77 |
Granted (in dollars per share) | $ / shares | 9.22 |
Forfeited (in dollars per share) | $ / shares | 14.83 |
Vested (in dollars per share) | $ / shares | 16.23 |
Outstanding at the end of the period (in dollars per share) | $ / shares | $ 14.55 |
Stockholders' equity and stoc_9
Stockholders' equity and stock-based compensation - Performance Share Awards - assumptions used to estimate the fair value (Details) | Feb. 16, 2018$ / shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
RTSR Factor weight | 25.00% |
ATSR Factor weight | 25.00% |
Percentage of stock potentially payable | 50.00% |
Performance share awards with market criteria | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Risk-free interest rate | 2.34% |
Dividend yield | 0.00% |
Expected volatility | 65.49% |
Laredo stock closing price on grant date (in dollars per share) | $ 8.36 |
Grant-date fair value (in dollars per share) | $ 10.08 |
Stockholders' equity and sto_10
Stockholders' equity and stock-based compensation - Stock-based compensation expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total stock-based compensation, gross | $ 10,660 | $ 10,836 | $ 34,773 | $ 32,519 |
Less amounts capitalized in oil and natural gas properties | (1,927) | (1,870) | (6,025) | (5,642) |
Total stock-based compensation, net | 8,733 | 8,966 | 28,748 | 26,877 |
Restricted stock award compensation | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total stock-based compensation, gross | 6,001 | 5,422 | 19,332 | 16,856 |
Stock option award compensation | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total stock-based compensation, gross | 970 | 1,159 | 3,010 | 3,600 |
Performance share award compensation | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total stock-based compensation, gross | $ 3,689 | $ 4,255 | $ 12,431 | $ 12,063 |
Derivatives - Commodity derivat
Derivatives - Commodity derivatives (Details) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($)derivative | |
Derivative [Line Items] | ||
Settlements received for early terminations of derivatives, net | $ 0 | $ 4,234 |
Early contract termination | Commodity derivatives | Derivatives not designated as hedges | ||
Derivative [Line Items] | ||
Settlements received for early terminations of derivatives, net | $ 4,200 | |
Number of restructuring derivatives | derivative | 1 |
Derivatives - Commodity deriv_2
Derivatives - Commodity derivative contracts terminated (Details) - Oil derivatives - Early contract termination - Swap January 2018 to December 2018 | Sep. 30, 2017bbl$ / bbl |
Derivative [Line Items] | |
Aggregate volumes (Bbl) | bbl | 1,095,000 |
Floor price ($/Bbl) | 52.12 |
Ceiling price ($/Bbl) | 52.12 |
Derivatives - Derivative positi
Derivatives - Derivative positions (Details) - Not designated as hedges | 9 Months Ended |
Sep. 30, 2018MMBTU$ / bbl$ / MMBTUbbl | |
Puts remainder of year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 1,367,775 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 51.93 |
Puts remainder of year | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 2,055,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 2.50 |
Puts next year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 8,030,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 47.45 |
Puts next year | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Puts year three | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 366,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 45 |
Puts year three | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Puts year four | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Puts year four | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Swaps remainder of year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Swaps remainder of year | Ethane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 156,400 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 11.66 |
Swaps remainder of year | Propane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 128,800 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 33.92 |
Swaps remainder of year | Normal Butane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 46,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 38.22 |
Swaps remainder of year | Isobutane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 18,400 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 38.33 |
Swaps remainder of year | Natural Gasoline | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 46,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 57.02 |
Swaps next year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 657,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 53.45 |
Swaps next year | Ethane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps next year | Propane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps next year | Normal Butane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps next year | Isobutane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps next year | Natural Gasoline | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year three | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 695,400 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 52.18 |
Swaps year three | Ethane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year three | Propane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year three | Normal Butane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year three | Isobutane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year three | Natural Gasoline | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year four | Ethane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year four | Propane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year four | Normal Butane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year four | Isobutane | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Swaps year four | Natural Gasoline | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Collars remainder of year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 1,030,400 |
Collars remainder of year | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 3,928,400 |
Collars remainder of year | Floor | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 41.43 |
Collars remainder of year | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 2.50 |
Collars remainder of year | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 60 |
Collars remainder of year | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 3.35 |
Collars next year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Collars next year | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Collars next year | Floor | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Collars next year | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Collars next year | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Collars next year | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Collars year three | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 1,134,600 |
Collars year three | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Collars year three | Floor | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 45 |
Collars year three | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Collars year three | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 76.13 |
Collars year three | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Collars year four | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 912,500 |
Collars year four | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Collars year four | Floor | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 45 |
Collars year four | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Collars year four | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 71 |
Collars year four | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Total Commodity Derivatives remainder of year | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 395,600 |
Total Commodity Derivatives remainder of year | Floor | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 2,398,175 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 47.42 |
Total Commodity Derivatives remainder of year | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 5,983,400 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 2.50 |
Total Commodity Derivatives remainder of year | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 1,030,400 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 60 |
Total Commodity Derivatives remainder of year | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 3,928,400 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 3.35 |
Total Commodity Derivatives next year | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Total Commodity Derivatives next year | Floor | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 8,687,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 47.91 |
Total Commodity Derivatives next year | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Total Commodity Derivatives next year | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 657,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 53.45 |
Total Commodity Derivatives next year | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Total Commodity Derivatives year three | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Total Commodity Derivatives year three | Floor | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 2,196,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 47.27 |
Total Commodity Derivatives year three | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Total Commodity Derivatives year three | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 1,830,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 67.03 |
Total Commodity Derivatives year three | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Total commodity derivatives year four | NGL derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Total commodity derivatives year four | Floor | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 912,500 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 45 |
Total commodity derivatives year four | Floor | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Total commodity derivatives year four | Ceiling | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 912,500 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 71 |
Total commodity derivatives year four | Ceiling | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Basis swap one, remainder of year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 920,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | (0.56) |
Basis swap one, remainder of year | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 2,300,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | (0.62) |
Basis swap one, next year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 552,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | (4.37) |
Basis swap one, next year | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 20,075,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | (1.05) |
Basis swap one, year three | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Basis swap one, year three | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 25,254,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | (0.76) |
Basis swap one, year four | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Basis swap one, year four | Natural gas derivatives | |
Derivative [Line Items] | |
Hedged Volume (MMbtu) | MMBTU | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / MMBTU | 0 |
Basis swap two, remainder of year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 920,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 7.30 |
Basis swap two, next year | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 1,810,000 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 7.30 |
Basis swap two, year three | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Basis swap two, year four | Oil derivatives | |
Derivative [Line Items] | |
Hedged Volume (Bbl) | 0 |
Weighted-average price (in dollars per Bbl/MMbtu) | $ / bbl | 0 |
Fair value measurements - Fair
Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Assets: | ||
Derivative asset, current | $ 3,074 | $ 6,892 |
Derivative asset, noncurrent | 0 | 3,413 |
Liabilities: | ||
Derivative liability, current | (44,060) | (22,950) |
Derivative liability, noncurrent | (20,945) | (384) |
Recurring | ||
Liabilities: | ||
Net derivative liability positions | (61,931) | (13,029) |
Recurring | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative asset, current | 0 | 3,706 |
Derivative asset, noncurrent | 0 | 5,526 |
Liabilities: | ||
Derivative liability, current | (31,302) | (8,756) |
Derivative liability, noncurrent | (15,223) | 3,698 |
Recurring | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative asset, current | 0 | (87) |
Derivative asset, noncurrent | 0 | (2,113) |
Liabilities: | ||
Derivative liability, current | (17,265) | (18,115) |
Derivative liability, noncurrent | (3,728) | (5,016) |
Recurring | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative asset, current | 0 | 0 |
Derivative asset, noncurrent | 0 | 0 |
Liabilities: | ||
Derivative liability, current | (4,807) | 0 |
Derivative liability, noncurrent | 0 | 0 |
Recurring | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative asset, current | 3,693 | 5,729 |
Derivative asset, noncurrent | 0 | 0 |
Liabilities: | ||
Derivative liability, current | 9,542 | 4,817 |
Derivative liability, noncurrent | (1,994) | 934 |
Recurring | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative asset, current | (619) | (2,456) |
Derivative asset, noncurrent | 0 | 0 |
Liabilities: | ||
Derivative liability, current | (228) | (896) |
Derivative liability, noncurrent | 0 | 0 |
Recurring | Current Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Amounts offset | (10,390) | (3,721) |
Recurring | Current Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Amounts offset | 0 | (87) |
Recurring | Current Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Amounts offset | 0 | 0 |
Recurring | Current Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Amounts offset | (9,309) | (4,817) |
Recurring | Current Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Amounts offset | (619) | (2,456) |
Recurring | Noncurrent Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Amounts offset | (2,056) | (6,087) |
Recurring | Noncurrent Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Amounts offset | 0 | (2,113) |
Recurring | Noncurrent Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Amounts offset | 0 | 0 |
Recurring | Noncurrent Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Amounts offset | (474) | (934) |
Recurring | Noncurrent Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Amounts offset | 0 | 0 |
Recurring | Other current liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Amounts offset | 10,390 | 3,721 |
Recurring | Other current liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Amounts offset | 0 | 87 |
Recurring | Other current liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Amounts offset | 0 | 0 |
Recurring | Other current liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Amounts offset | 9,309 | 4,817 |
Recurring | Other current liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Amounts offset | 619 | 2,456 |
Recurring | Noncurrent Liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Amounts offset | 2,056 | 6,087 |
Recurring | Noncurrent Liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Amounts offset | 0 | 2,113 |
Recurring | Noncurrent Liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Amounts offset | 0 | 0 |
Recurring | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Amounts offset | 474 | 934 |
Recurring | Noncurrent Liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Amounts offset | 0 | 0 |
Recurring | Fair value | ||
Liabilities: | ||
Net derivative liability positions | (61,931) | (13,029) |
Recurring | Fair value | Current Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 10,390 | 7,427 |
Recurring | Fair value | Current Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Fair value | Current Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Fair value | Current Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 13,002 | 10,546 |
Recurring | Fair value | Current Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Fair value | Noncurrent Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 2,056 | 11,613 |
Recurring | Fair value | Noncurrent Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Fair value | Noncurrent Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Fair value | Noncurrent Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 474 | 934 |
Recurring | Fair value | Noncurrent Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Fair value | Other current liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (41,692) | (12,477) |
Recurring | Fair value | Other current liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | (17,265) | (18,202) |
Recurring | Fair value | Other current liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (4,807) | 0 |
Recurring | Fair value | Other current liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 233 | 0 |
Recurring | Fair value | Other current liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | (847) | (3,352) |
Recurring | Fair value | Noncurrent Liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (17,279) | (2,389) |
Recurring | Fair value | Noncurrent Liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | (3,728) | (7,129) |
Recurring | Fair value | Noncurrent Liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Fair value | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (2,468) | 0 |
Recurring | Fair value | Noncurrent Liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | ||
Liabilities: | ||
Net derivative liability positions | 0 | 0 |
Recurring | Level 1 | Current Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Current Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Current Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Current Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Current Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 1 | Other current liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Other current liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Other current liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Other current liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Other current liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 1 | Noncurrent Liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 2 | ||
Liabilities: | ||
Net derivative liability positions | (40,091) | 15,654 |
Recurring | Level 2 | Current Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 10,390 | 7,427 |
Recurring | Level 2 | Current Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 2 | Current Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 2 | Current Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 13,002 | 10,546 |
Recurring | Level 2 | Current Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 2 | Noncurrent Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 2,056 | 11,613 |
Recurring | Level 2 | Noncurrent Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 2 | Noncurrent Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 2 | Noncurrent Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 474 | 934 |
Recurring | Level 2 | Noncurrent Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 2 | Other current liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (41,692) | (12,477) |
Recurring | Level 2 | Other current liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 2 | Other current liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (4,807) | 0 |
Recurring | Level 2 | Other current liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 233 | 0 |
Recurring | Level 2 | Other current liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 2 | Noncurrent Liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (17,279) | (2,389) |
Recurring | Level 2 | Noncurrent Liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 2 | Noncurrent Liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 2 | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | (2,468) | 0 |
Recurring | Level 2 | Noncurrent Liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 3 | ||
Liabilities: | ||
Net derivative liability positions | (21,840) | (28,683) |
Recurring | Level 3 | Current Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Current Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Current Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Current Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Current Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Assets | Oil derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Assets | Oil derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Assets | NGL derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Assets | Natural gas derivatives | Commodity derivatives | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Assets | Natural gas derivatives | Deferred premiums | ||
Assets: | ||
Derivative assets before netting | 0 | 0 |
Recurring | Level 3 | Other current liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 3 | Other current liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | (17,265) | (18,202) |
Recurring | Level 3 | Other current liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 3 | Other current liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 3 | Other current liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | (847) | (3,352) |
Recurring | Level 3 | Noncurrent Liabilities | Oil derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Liabilities | Oil derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | (3,728) | (7,129) |
Recurring | Level 3 | Noncurrent Liabilities | NGL derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Liabilities | Natural gas derivatives | Commodity derivatives | ||
Liabilities: | ||
Derivative liabilities before netting | 0 | 0 |
Recurring | Level 3 | Noncurrent Liabilities | Natural gas derivatives | Deferred premiums | ||
Liabilities: | ||
Derivative liabilities before netting | $ 0 | $ 0 |
Fair value measurements - Narra
Fair value measurements - Narrative (Details) - Measurement input, discount rate - Recurring - Level 3 - Deferred premiums | Sep. 30, 2018 |
Minimum | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Debt instrument, measurement input | 0.0191 |
Maximum | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Debt instrument, measurement input | 0.0332 |
Weighted Average | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Debt instrument, measurement input | 0.0278 |
Fair value measurements - Cash
Fair value measurements - Cash payments required for deferred premium contracts (Details) $ in Thousands | Sep. 30, 2018USD ($) |
Fair Value Disclosures [Abstract] | |
Remaining 2,018 | $ 5,405 |
2,019 | 15,502 |
2,020 | 1,295 |
Total | $ 22,202 |
Fair value measurements - Summa
Fair value measurements - Summary of changes in net assets classified as Level 3 (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Changes in assets classified as Level 3 measurements | ||||
Change in net present value of derivative deferred premiums | $ 564 | $ 199 | ||
Deferred premiums | ||||
Changes in assets classified as Level 3 measurements | ||||
Balance of Level 3 at beginning of period | $ (25,026) | $ (12,554) | (28,683) | (8,998) |
Change in net present value of derivative deferred premiums | (168) | (88) | (564) | (199) |
Total purchases and settlements of derivative deferred premiums: | ||||
Purchases | (2,101) | (15,996) | (7,523) | (22,994) |
Settlements | 5,455 | 1,448 | 14,930 | 5,001 |
Balance of Level 3 at end of period | $ (21,840) | $ (27,190) | $ (21,840) | $ (27,190) |
Fair value measurements - Carry
Fair value measurements - Carrying amount of debt instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Long-term debt | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | $ 970,000 | $ 800,000 |
Long-term debt | January 2022 Notes | Senior Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | 450,000 | 450,000 |
Long-term debt | March 2023 Notes | Senior Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | 350,000 | 350,000 |
Long-term debt | Senior Secured Credit Facility | Secured debt | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | 170,000 | 0 |
Fair value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | 971,689 | 818,605 |
Fair value | January 2022 Notes | Senior Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | 448,875 | 454,500 |
Fair value | March 2023 Notes | Senior Notes | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | 352,730 | 364,105 |
Fair value | Senior Secured Credit Facility | Secured debt | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt | $ 170,084 | $ 0 |
Net income per common share (D
Net income per common share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Net income (numerator): | ||||
Net income—basic and diluted | $ 55,050 | $ 11,027 | $ 175,022 | $ 140,413 |
Weighted-average common shares outstanding (denominator): | ||||
Basic (in shares) | 230,605 | 239,306 | 233,228 | 239,017 |
Diluted (in shares) | 231,639 | 244,887 | 234,207 | 244,693 |
Net income per common share: | ||||
Basic (in dollars per share) | $ 0.24 | $ 0.05 | $ 0.75 | $ 0.59 |
Diluted (in dollars per share) | $ 0.24 | $ 0.05 | $ 0.75 | $ 0.57 |
Non-vested restricted stock awards | ||||
Weighted-average common shares outstanding (denominator): | ||||
Incremental common shares (in shares) | 935 | 650 | 911 | 845 |
Outstanding stock option awards | ||||
Weighted-average common shares outstanding (denominator): | ||||
Incremental common shares (in shares) | 99 | 130 | 68 | 129 |
Non-vested performance share awards | ||||
Weighted-average common shares outstanding (denominator): | ||||
Incremental common shares (in shares) | 0 | 4,801 | 0 | 4,702 |
Commitments and contingencies -
Commitments and contingencies - Litigation (Details) $ in Millions | Sep. 30, 2018USD ($)bbl | Jun. 15, 2018USD ($) | Dec. 11, 2017Claim |
Commitments and Contingencies Disclosure [Abstract] | |||
Barrels of crude oil produced | bbl | 19,000 | ||
Number of causes of action | Claim | 9 | ||
Gain contingency, unrecorded amount | $ 150 | ||
Estimated litigation liability | $ 37.4 |
Commitments and contingencies_2
Commitments and contingencies - Drilling contracts (Details) - Drilling contracts - USD ($) | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Cost of Goods and Services Sold [Abstract] | ||
Penalties incurred for early contract termination | $ 0 | $ 0 |
Future drilling contracts commitments | $ 22,900,000 |
Commitments and contingencies_3
Commitments and contingencies - Firm sale and transportation commitments (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Supply Commitment [Line Items] | ||||
Minimum volume commitments deficiency payments | $ 0.2 | $ 0.5 | $ 2.5 | $ 1.1 |
Firm sale and transportation commitments | ||||
Cost of Goods and Services Sold [Abstract] | ||||
Future drilling contracts commitments | $ 367.7 | $ 367.7 |
Commitments and contingencies_4
Commitments and contingencies - Purchase commitment (Details) - USD ($) $ in Millions | 3 Months Ended | |
Jun. 30, 2018 | Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | ||
Purchase agreement term | 1 year | |
Aggregate purchase commitment | $ 5.7 |
Commitments and contingencies_5
Commitments and contingencies - Environmental (Details) - USD ($) | Sep. 30, 2018 | Dec. 31, 2017 |
Commitments and Contingencies Disclosure [Abstract] | ||
Accrual for environmental loss contingencies | $ 0 | $ 0 |
Supplemental cash flow inform_3
Supplemental cash flow information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Non-cash investing activities: | ||||
(Decrease) increase in accrued capital expenditures | $ (44,533) | $ 39,156 | ||
Capitalized stock-based compensation | $ 1,927 | $ 1,870 | 6,025 | 5,642 |
Capitalized asset retirement costs | 719 | 670 | ||
Other supplemental cash flow information: | ||||
Capitalized interest | $ 710 | $ 756 |
Asset retirement obligations (D
Asset retirement obligations (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liability at beginning of period | $ 55,506 | $ 52,207 |
Liabilities added due to acquisitions, drilling, midstream service asset construction and other | 719 | 492 |
Accretion expense | 3,341 | 2,822 |
Liabilities settled due to plugging and abandonment or sale | (2,246) | (1,228) |
Revision of estimates | 0 | 178 |
Liability at end of period | $ 57,320 | $ 54,471 |
Income taxes - Additional Infor
Income taxes - Additional Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Operating loss carry-forward | ||||
Net operating loss carry-forward that will not expire due to TCJA | $ 86,400 | $ 86,400 | ||
Deferred tax assets, valuation allowance | 298,800 | 298,800 | ||
Current income tax benefit | 381 | $ 0 | 381 | $ 0 |
Internal Revenue Service (IRS) | Federal | ||||
Operating loss carry-forward | ||||
Operating loss carryforwards | 1,800,000 | 1,800,000 | ||
State of Oklahoma | State | ||||
Operating loss carry-forward | ||||
Operating loss carryforwards | 36,300 | 36,300 | ||
Texas | State | ||||
Operating loss carry-forward | ||||
Deferred tax liability | 1,800 | 1,800 | ||
Current income tax benefit | (400) | |||
Expected tax refund | $ 400 | $ 400 |
Subsidiary guarantors - Condens
Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Subsidiary guarantees | ||
Accounts receivable, net | $ 117,581 | $ 100,645 |
Other current assets | 71,946 | 134,737 |
Oil and natural gas properties, net | 1,938,490 | 1,589,339 |
Midstream service assets, net | 132,415 | 138,325 |
Other fixed assets, net | 42,264 | 40,721 |
Investment in subsidiaries | 0 | 0 |
Other noncurrent assets, net | 17,078 | 19,522 |
Total assets | 2,319,774 | 2,023,289 |
Accounts payable and accrued liabilities | 86,637 | 58,341 |
Other current liabilities | 172,632 | 219,078 |
Long-term debt, net | 963,191 | 791,855 |
Other noncurrent liabilities | 82,202 | 188,436 |
Stockholders' equity | 1,015,112 | 765,579 |
Total liabilities and stockholders' equity | 2,319,774 | 2,023,289 |
Intercompany eliminations | ||
Subsidiary guarantees | ||
Accounts receivable, net | 0 | 0 |
Other current assets | 0 | 0 |
Oil and natural gas properties, net | (22,174) | (16,715) |
Midstream service assets, net | 0 | 0 |
Other fixed assets, net | 0 | 0 |
Investment in subsidiaries | (130,439) | 7,566 |
Other noncurrent assets, net | 0 | 0 |
Total assets | (152,613) | (9,149) |
Accounts payable and accrued liabilities | 0 | 0 |
Other current liabilities | 0 | 0 |
Long-term debt, net | 0 | 0 |
Other noncurrent liabilities | 0 | 0 |
Stockholders' equity | (152,613) | (9,149) |
Total liabilities and stockholders' equity | (152,613) | (9,149) |
Laredo | Reportable Legal Entities | ||
Subsidiary guarantees | ||
Accounts receivable, net | 103,109 | 79,413 |
Other current assets | 70,413 | 132,219 |
Oil and natural gas properties, net | 1,951,518 | 1,596,834 |
Midstream service assets, net | 0 | 0 |
Other fixed assets, net | 42,071 | 40,344 |
Investment in subsidiaries | 130,439 | (7,566) |
Other noncurrent assets, net | 13,113 | 15,526 |
Total assets | 2,310,663 | 1,856,770 |
Accounts payable and accrued liabilities | 68,037 | 34,550 |
Other current liabilities | 162,893 | 193,104 |
Long-term debt, net | 963,191 | 791,855 |
Other noncurrent liabilities | 79,256 | 54,967 |
Stockholders' equity | 1,037,286 | 782,294 |
Total liabilities and stockholders' equity | 2,310,663 | 1,856,770 |
Subsidiary Guarantors | Reportable Legal Entities | ||
Subsidiary guarantees | ||
Accounts receivable, net | 14,472 | 21,232 |
Other current assets | 1,533 | 2,518 |
Oil and natural gas properties, net | 9,146 | 9,220 |
Midstream service assets, net | 132,415 | 138,325 |
Other fixed assets, net | 193 | 377 |
Investment in subsidiaries | 0 | 0 |
Other noncurrent assets, net | 3,965 | 3,996 |
Total assets | 161,724 | 175,668 |
Accounts payable and accrued liabilities | 18,600 | 23,791 |
Other current liabilities | 9,739 | 25,974 |
Long-term debt, net | 0 | 0 |
Other noncurrent liabilities | 2,946 | 133,469 |
Stockholders' equity | 130,439 | (7,566) |
Total liabilities and stockholders' equity | $ 161,724 | $ 175,668 |
Subsidiary guarantors - Conde_2
Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Subsidiary guarantees | ||||
Total revenues | $ 279,746 | $ 205,818 | $ 890,488 | $ 581,825 |
Total costs and expenses | 175,336 | 145,366 | 598,119 | 417,986 |
Operating income | 104,410 | 60,452 | 292,369 | 163,839 |
Interest expense | (14,845) | (23,697) | (42,787) | (69,590) |
Other (expense) income | (33,128) | (25,728) | (73,173) | 46,164 |
Income before income taxes | 56,437 | 11,027 | 176,409 | 140,413 |
Income tax expense | (1,387) | 0 | (1,387) | 0 |
Net income | 55,050 | 11,027 | 175,022 | 140,413 |
Intercompany eliminations | ||||
Subsidiary guarantees | ||||
Total revenues | (19,687) | (15,770) | (54,715) | (48,370) |
Total costs and expenses | (17,752) | (14,565) | (49,256) | (42,179) |
Operating income | (1,935) | (1,205) | (5,459) | (6,191) |
Interest expense | 0 | 0 | 0 | 0 |
Other (expense) income | (4,291) | (3,731) | (9,334) | (15,238) |
Income before income taxes | (6,226) | (4,936) | (14,793) | (21,429) |
Income tax expense | 0 | 0 | 0 | 0 |
Net income | (6,226) | (4,936) | (14,793) | (21,429) |
Laredo | Reportable Legal Entities | ||||
Subsidiary guarantees | ||||
Total revenues | 225,970 | 157,902 | 632,419 | 439,269 |
Total costs and expenses | 123,942 | 97,686 | 345,232 | 276,855 |
Operating income | 102,028 | 60,216 | 287,187 | 162,414 |
Interest expense | (14,845) | (23,697) | (42,787) | (69,590) |
Other (expense) income | (28,811) | (24,287) | (62,532) | 53,780 |
Income before income taxes | 58,372 | 12,232 | 181,868 | 146,604 |
Income tax expense | (1,387) | 0 | (1,387) | 0 |
Net income | 56,985 | 12,232 | 180,481 | 146,604 |
Subsidiary Guarantors | Reportable Legal Entities | ||||
Subsidiary guarantees | ||||
Total revenues | 73,463 | 63,686 | 312,784 | 190,926 |
Total costs and expenses | 69,146 | 62,245 | 302,143 | 183,310 |
Operating income | 4,317 | 1,441 | 10,641 | 7,616 |
Interest expense | 0 | 0 | 0 | 0 |
Other (expense) income | (26) | 2,290 | (1,307) | 7,622 |
Income before income taxes | 4,291 | 3,731 | 9,334 | 15,238 |
Income tax expense | 0 | 0 | 0 | 0 |
Net income | $ 4,291 | $ 3,731 | $ 9,334 | $ 15,238 |
Subsidiary guarantors - Conde_3
Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Subsidiary guarantees | ||
Net cash provided by operating activities | $ 408,528 | $ 272,051 |
Change in investment between affiliates | 0 | 0 |
Capital expenditures and other | (536,431) | (356,893) |
Net cash provided by financing activities | 66,151 | 72,988 |
Net decrease in cash and cash equivalents | (61,752) | (11,854) |
Cash and cash equivalents, beginning of period | 112,159 | 32,672 |
Cash and cash equivalents, end of period | 50,407 | 20,818 |
Intercompany eliminations | ||
Subsidiary guarantees | ||
Net cash provided by operating activities | (9,334) | (15,238) |
Change in investment between affiliates | 9,334 | 15,238 |
Capital expenditures and other | 0 | 0 |
Net cash provided by financing activities | 0 | 0 |
Net decrease in cash and cash equivalents | 0 | 0 |
Cash and cash equivalents, beginning of period | 0 | 0 |
Cash and cash equivalents, end of period | 0 | 0 |
Laredo | Reportable Legal Entities | ||
Subsidiary guarantees | ||
Net cash provided by operating activities | 402,065 | 273,309 |
Change in investment between affiliates | 3,115 | (36,890) |
Capital expenditures and other | (533,083) | (321,261) |
Net cash provided by financing activities | 66,151 | 72,988 |
Net decrease in cash and cash equivalents | (61,752) | (11,854) |
Cash and cash equivalents, beginning of period | 112,158 | 32,671 |
Cash and cash equivalents, end of period | 50,406 | 20,817 |
Subsidiary Guarantors | Reportable Legal Entities | ||
Subsidiary guarantees | ||
Net cash provided by operating activities | 15,797 | 13,980 |
Change in investment between affiliates | (12,449) | 21,652 |
Capital expenditures and other | (3,348) | (35,632) |
Net cash provided by financing activities | 0 | 0 |
Net decrease in cash and cash equivalents | 0 | 0 |
Cash and cash equivalents, beginning of period | 1 | 1 |
Cash and cash equivalents, end of period | $ 1 | $ 1 |
Subsequent events - Additional
Subsequent events - Additional Information (Details) - USD ($) | Oct. 15, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Nov. 05, 2018 | Oct. 23, 2018 | Dec. 31, 2017 |
Subsequent Event [Line Items] | ||||||
Borrowings on Senior Secured Credit Facility | $ 190,000,000 | $ 155,000,000 | ||||
Senior Secured Credit Facility | Secured debt | ||||||
Subsequent Event [Line Items] | ||||||
Amount outstanding | 170,000,000 | |||||
Current borrowing capacity | 1,300,000,000 | |||||
Aggregate elected commitment | 1,200,000,000 | |||||
Senior Secured Credit Facility | Secured debt | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Borrowings on Senior Secured Credit Facility | $ 20,000,000 | |||||
Amount outstanding | $ 190,000,000 | |||||
Current borrowing capacity | $ 1,300,000,000 | |||||
Aggregate elected commitment | $ 1,200,000,000 | |||||
Letter of Credit | Secured debt | ||||||
Subsequent Event [Line Items] | ||||||
Letters of credit outstanding | $ 0 | $ 0 | ||||
Letter of Credit | Secured debt | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Letters of credit outstanding | $ 14,700,000 |