Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2017 | Nov. 01, 2017 | |
Document Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q3 | |
Trading Symbol | BSM | |
Entity Registrant Name | Black Stone Minerals, L.P. | |
Entity Central Index Key | 1,621,434 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Common Units | ||
Document Information [Line Items] | ||
Entity Partnership Units Outstanding (in shares) | 103,417,081 | |
Subordinated Units | ||
Document Information [Line Items] | ||
Entity Partnership Units Outstanding (in shares) | 95,388,424 | |
Preferred Units | ||
Document Information [Line Items] | ||
Entity Partnership Units Outstanding (in shares) | 26,426 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 8,911 | $ 9,772 |
Accounts receivable | 68,895 | 68,181 |
Commodity derivative assets | 4,724 | 0 |
Prepaid expenses and other current assets | 1,269 | 1,036 |
TOTAL CURRENT ASSETS | 83,799 | 78,989 |
PROPERTY AND EQUIPMENT | ||
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $731,978 and $605,736 at September 30, 2017 and December 31, 2016, respectively | 2,892,447 | 2,697,073 |
Accumulated depreciation, depletion, amortization, and impairment | (1,736,695) | (1,652,930) |
Oil and natural gas properties, net | 1,155,752 | 1,044,143 |
Other property and equipment, net of accumulated depreciation of $14,384 and $14,327 at September 30, 2017 and December 31, 2016, respectively | 519 | 528 |
NET PROPERTY AND EQUIPMENT | 1,156,271 | 1,044,671 |
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS | 6,000 | 5,167 |
TOTAL ASSETS | 1,246,070 | 1,128,827 |
CURRENT LIABILITIES | ||
Accounts payable | 3,659 | 4,142 |
Accrued liabilities | 38,336 | 50,952 |
Commodity derivative liabilities | 0 | 16,237 |
Other current liabilities | 302 | 0 |
TOTAL CURRENT LIABILITIES | 42,297 | 71,331 |
LONG-TERM LIABILITIES | ||
Credit facility | 362,000 | 316,000 |
Accrued incentive compensation | 2,883 | 1,485 |
Commodity derivative liabilities | 0 | 482 |
Deferred revenue | 0 | 518 |
Asset retirement obligations | 13,909 | 13,350 |
Other long-term liability | 6,592 | 0 |
TOTAL LIABILITIES | 427,681 | 403,166 |
COMMITMENTS AND CONTINGENCIES (Note 8) | ||
MEZZANINE EQUITY | ||
Partners' equity - convertible redeemable preferred units, 26 and 53 units outstanding at September 30, 2017 and December 31, 2016, respectively | 27,092 | 54,015 |
EQUITY | ||
Partners' equity - general partner interest | 0 | 0 |
Noncontrolling interests | 904 | 1,021 |
TOTAL EQUITY | 791,297 | 671,646 |
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY | 1,246,070 | 1,128,827 |
Common Units | ||
EQUITY | ||
Partners' equity - units | 608,998 | 489,023 |
Subordinated Units | ||
EQUITY | ||
Partners' equity - units | $ 181,395 | $ 181,602 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Oil and natural gas properties, unproved property costs | $ 731,978 | $ 605,736 |
Other property and equipment accumulated depreciation and amortization | $ 14,384 | $ 14,327 |
Preferred Units | ||
Partners' equity, preferred units, outstanding (in shares) | 26,426 | 52,691 |
Common Units | ||
Partners' equity - units, outstanding (in shares) | 103,324,000 | 95,721,000 |
Subordinated Units | ||
Partners' equity - units, outstanding (in shares) | 95,388,424 | 95,164,000 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
REVENUE | ||||
Oil and condensate sales | $ 41,361 | $ 42,780 | $ 119,097 | $ 104,581 |
Natural gas and natural gas liquids sales | 45,047 | 38,986 | 142,651 | 85,706 |
Gain (loss) on commodity derivative instruments | (9,341) | 7,813 | 35,387 | (12,295) |
Lease bonus and other income | 12,044 | 9,592 | 37,082 | 26,129 |
TOTAL REVENUE | 89,111 | 99,171 | 334,217 | 204,121 |
OPERATING (INCOME) EXPENSE | ||||
Lease operating expense | 4,569 | 5,007 | 12,906 | 14,179 |
Production costs and ad valorem taxes | 11,549 | 9,228 | 35,314 | 23,301 |
Exploration expense | 8 | 6 | 616 | 643 |
Depreciation, depletion, and amortization | 29,204 | 28,731 | 84,483 | 79,654 |
Impairment of oil and natural gas properties | 0 | 0 | 0 | 6,775 |
General and administrative | 17,305 | 16,677 | 51,998 | 52,213 |
Accretion of asset retirement obligations | 260 | 206 | 760 | 680 |
(Gain) loss on sale of assets, net | 0 | 0 | (931) | (4,772) |
TOTAL OPERATING EXPENSE | 62,895 | 59,855 | 185,146 | 172,673 |
INCOME (LOSS) FROM OPERATIONS | 26,216 | 39,316 | 149,071 | 31,448 |
OTHER INCOME (EXPENSE) | ||||
Interest and investment income | (9) | 460 | 30 | 651 |
Interest expense | (4,172) | (2,282) | (11,660) | (4,773) |
Other income (expense) | (1) | 41 | 352 | 148 |
TOTAL OTHER EXPENSE | (4,182) | (1,781) | (11,278) | (3,974) |
NET INCOME (LOSS) | 22,034 | 37,535 | 137,793 | 27,474 |
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | 20 | 8 | 27 | 15 |
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS | (666) | (1,324) | (2,452) | (4,439) |
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | 21,388 | 36,219 | 135,368 | 23,050 |
ALLOCATION OF NET INCOME (LOSS): | ||||
General partner interest | 0 | 0 | 0 | 0 |
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | 21,388 | 36,219 | 135,368 | 23,050 |
Common Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 16,371 | $ 23,114 | $ 83,989 | $ 24,343 |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.16 | $ 0.24 | $ 0.86 | $ 0.26 |
Weighted average units outstanding (basic) (in shares) | 101,623 | 95,740 | 97,777 | 95,086 |
Per unit (diluted) (in dollars per share) | $ 0.16 | $ 0.24 | $ 0.86 | $ 0.26 |
Weighted average units outstanding (diluted) (in shares) | 101,623 | 96,011 | 97,777 | 95,619 |
DISTRIBUTIONS DECLARED AND PAID: | ||||
Per unit (in dollars per share) | $ 0.3125 | $ 0.2875 | $ 0.8875 | $ 0.8125 |
Subordinated Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 5,017 | $ 13,105 | $ 51,379 | $ (1,293) |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.05 | $ 0.14 | $ 0.54 | $ (0.01) |
Weighted average units outstanding (basic) (in shares) | 95,388 | 95,189 | 95,269 | 95,125 |
Per unit (diluted) (in dollars per share) | $ 0.05 | $ 0.14 | $ 0.54 | $ (0.01) |
Weighted average units outstanding (diluted) (in shares) | 95,388 | 95,189 | 95,269 | 95,467 |
DISTRIBUTIONS DECLARED AND PAID: | ||||
Per unit (in dollars per share) | $ 0.20875 | $ 0.1838 | $ 0.57625 | $ 0.5513 |
CONSOLIDATED STATEMENT OF EQUIT
CONSOLIDATED STATEMENT OF EQUITY - 9 months ended Sep. 30, 2017 - USD ($) $ in Thousands | Total | Noncontrolling interests | Common Units | Subordinated Units | Partners' equity— common units | Partners' equity— subordinated units |
Beginning balance (in shares) at Dec. 31, 2016 | 95,721,000 | 95,164,000 | ||||
Beginning balance at Dec. 31, 2016 | $ 671,646 | $ 1,021 | $ 489,023 | $ 181,602 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Restricted units granted, net of forfeitures (in shares) | 1,576,000 | 0 | ||||
Equity-based compensation | 26,316 | 26,430 | (114) | |||
Conversion of redeemable preferred units (in shares) | 201,000 | 263,000 | ||||
Conversion of redeemable preferred units | 6,624 | 2,868 | 3,756 | |||
Repurchases of common and subordinated units (in shares) | (427,000) | (39,000) | ||||
Repurchases of common and subordinated units | (7,845) | (7,553) | (292) | |||
Issuance of units for property acquisitions (in shares) | 4,341,000 | |||||
Issuance of units for property acquisitions | 71,592 | 71,592 | ||||
Distributions | (142,665) | (90) | (87,651) | (54,924) | ||
Charges to partners' equity for accrued distribution equivalent rights | (979) | (979) | ||||
Net income (loss) | 137,793 | (27) | 85,243 | 52,577 | ||
Issuance of common units, net of offering costs (in shares) | 1,912,000 | |||||
Issuance of common units, net of offering costs | 31,267 | 31,267 | ||||
Distributions on redeemable preferred units | (2,452) | (1,242) | (1,210) | |||
Ending balance (in shares) at Sep. 30, 2017 | 103,324,000 | 95,388,424 | ||||
Ending balance at Sep. 30, 2017 | $ 791,297 | $ 904 | $ 608,998 | $ 181,395 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income (loss) | $ 137,793 | $ 27,474 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation, depletion, and amortization | 84,483 | 79,654 |
Impairment of oil and natural gas properties | 0 | 6,775 |
Accretion of asset retirement obligations | 760 | 680 |
Amortization of deferred charges | 661 | 594 |
(Gain) loss on commodity derivative instruments | (35,387) | 12,295 |
Net cash received on settlement of commodity derivative instruments | 12,339 | 39,220 |
Equity-based compensation | 18,614 | 33,120 |
(Gain) loss on sale of assets, net | (931) | (4,772) |
Changes in operating assets and liabilities: | ||
Accounts receivable | (709) | (23,144) |
Prepaid expenses and other current assets | (234) | (862) |
Accounts payable and accrued liabilities | (3,940) | (29,063) |
Deferred revenue | (1,670) | (175) |
Settlement of asset retirement obligations | (113) | (237) |
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | 211,666 | 141,559 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Acquisitions of oil and natural gas properties | (89,030) | (140,893) |
Additions to oil and natural gas properties | (40,680) | (63,039) |
Purchases of other property and equipment | (118) | (5) |
Proceeds from farmout of oil and gas properties | 6,592 | 0 |
Proceeds from the sale of oil and natural gas properties | 6,754 | 177 |
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES | (116,482) | (203,760) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Borrowings under senior line of credit | 208,500 | 304,500 |
Repayments of borrowings under senior line of credit | (162,500) | (71,500) |
Distributions to non-controlling interests | (90) | (83) |
Proceeds from issuance of common units | 31,267 | 0 |
Redemptions of redeemable preferred units | (19,641) | (18,461) |
Loan origination fees | (50) | 0 |
Repurchases of common and subordinated units | (7,845) | (24,696) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | (96,045) | 53,816 |
NET CHANGE IN CASH AND CASH EQUIVALENTS | (861) | (8,385) |
CASH AND CASH EQUIVALENTS - beginning of the period | 9,772 | 13,233 |
CASH AND CASH EQUIVALENTS - end of the period | 8,911 | 4,848 |
SUPPLEMENTAL DISCLOSURE | ||
Interest paid | 11,041 | 4,060 |
Common and Subordinated Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions to unitholders | (142,575) | (130,883) |
Preferred Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions to unitholders | $ (3,111) | $ (5,061) |
Business and Basis of Presentat
Business and Basis of Presentation | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Business and Basis of Presentation | BUSINESS AND BASIS OF PRESENTATION Description of the Business Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. BSM received proceeds of $391.5 million from the sale of its common units, net of underwriting discount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtedness outstanding under its credit facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchange under the symbol “BSM.” Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) own oil and natural gas mineral interests in the United States. In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor were converted into an aggregate of 72,574,715 common units and 95,057,312 subordinated units of BSM at a conversion ratio of 12.9465 :1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 preferred units of BSM at a conversion ratio of one to one. The merger was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries. In addition to mineral interests, which make up the vast majority of the asset base, the Partnership’s assets also include nonparticipating and overriding royalty interests. These interests, which are non-cost-bearing, are collectively referred to as “mineral and royalty interests.” As of September 30, 2017 , the Partnership’s mineral and royalty interests were located in 41 states and 64 onshore oil and natural gas producing basins of the continental United States, including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. Basis of Presentation The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2016 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. All intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership. In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. The results of operations for the nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows. Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies Significant accounting policies are disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016 . There have been no changes in such policies or the application of such policies during the nine months ended September 30, 2017 . New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition . Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption permitted. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. The Partnership intends to use the modified retrospective adoption approach and does not plan to early adopt . The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard is not anticipated to have a material impact on the consolidated financial statements. The Partnership is concurrently evaluating the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership continues to evaluate the disclosure requirements of this new guidance, and expects to fully complete its evaluation of the impacts of ASU 2014-09 to the consolidated financial statements and related disclosures by 2017 year end . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach and does not plan to early adopt. Based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230) , to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is permitted. The Partnership intends to use the retrospective transition method, does not plan to early adopt, and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted under certain circumstances. The amendments in this ASU should be applied prospectively as of the beginning of the period of adoption. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In May 2017, the FASB issued ASU 2017-09 Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718) . The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met: • The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified. • The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified. • The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The amendments in this ASU should be applied prospectively to an award modified on or after the adoption date. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS The asset retirement obligations (“ARO”) liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s working-interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of its properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of these obligations. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Partnership’s ARO liability during the period: For the nine months ended September 30, 2017 (In thousands) Beginning asset retirement obligations $ 13,350 Liabilities incurred 290 Liabilities settled (113 ) Accretion expense 760 Dispositions (5 ) Revisions (71 ) Ending asset retirement obligations $ 14,211 Current asset retirement obligations $ 302 Non-current asset retirement obligations $ 13,909 |
Acquisitions and Dispositions
Acquisitions and Dispositions | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | ACQUISITIONS AND DISPOSITIONS Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost. 2017 Acquisitions During the nine months ended September 30, 2017 , the Partnership closed on multiple acquisitions of mineral and royalty interests in the Delaware Basin and East Texas, which also included producing properties. The following table summarizes the asset acquisitions which included producing properties: Proved Unproved Net Working Capital Total Fair Value Acquisition-Related Costs 1 Cash Fair Value of Common Units Issued (in thousands) January $ 5,135 $ 34,008 $ 263 $ 39,406 $ 1,162 $ 27,380 $ 12,026 June 5,006 45,477 — 50,483 1,468 4,802 45,681 August 3,277 9,984 — 13,261 89 4,289 8,972 September 3,120 — — 3,120 — 3,120 — Total fair value $ 16,538 $ 89,469 $ 263 $ 106,270 $ 2,719 $ 39,591 $ 66,679 1 Acquisition-related costs were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations. In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as follows: Unproved Cash Fair Value of Common Units Issued (in thousands) Q1 2017 $ 21,189 $ 21,017 $ 172 Q2 2017 13,329 13,329 — Q3 2017 19,946 15,205 4,741 $ 54,464 $ 49,551 $ 4,913 The cash portion of all acquisitions during the nine months ended September 30, 2017 was funded via borrowings under the Partnership's credit facility. Canaan Farmout On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of two years or until an additional 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of the Partnership's drilling and completion costs and will be assigned 80% of the Partnership's working interests in such wells ( 40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of the Partnership’s working interest ( 20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. The execution of this agreement is anticipated to offset the Partnership's future capital expenditures by approximately $30 to $35 million in 2017 and by an average of $40 to $50 million annually during the term of the agreement. 2016 Acquisitions During the nine months ended September 30, 2016, the Partnership acquired producing oil and natural gas properties and unproved acreage across a diverse oil and natural gas mineral asset package, including an acquisition in June 2016 in the DJ Basin. The following table summarizes the fair values assigned to the properties acquired: Proved Unproved Net Working Capital ARO Total Fair Value Cash (in thousands) June $ 39,735 $ 79,827 $ 2,064 $ (50 ) $ 121,576 $ 121,576 The Partnership also acquired unproved mineral and royalty interests in the Permian Basin and Midland Basin for $10 million and $8.3 million in cash, respectively. Additionally, throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.0 million in cash. All 2016 acquisition transactions were funded via borrowings under the Partnership's credit facility. |
Derivatives and Financial Instr
Derivatives and Financial Instruments | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives and Financial Instruments | DERIVATIVES AND FINANCIAL INSTRUMENTS The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas derivative instruments. From time to time, such instruments may include fixed-price-swap contracts, costless collars, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes. As of September 30, 2017 , the Partnership’s open derivative contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, any changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in “Revenue” in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of September 30, 2017 and December 31, 2016 . See Note 6 – Fair Value Measurement for further discussion. The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of September 30, 2017 , the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Seven of the Partnership's counterparties are lenders under the Partnership's credit facility. The Partnership would have been at risk of losing a fair value amount of $7.2 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of September 30, 2017 . The table below summarizes the fair value and classification of the Partnership’s derivative instruments: As of September 30, 2017 Classification Balance Sheet Location Gross Fair Effect of Net Carrying (In thousands) Assets: Current asset Commodity derivative assets $ 5,338 $ (614 ) $ 4,724 Long-term asset Deferred charges and other long-term assets 1,822 (217 ) 1,605 Total assets $ 7,160 $ (831 ) $ 6,329 Liabilities: Current liability Commodity derivative liabilities $ 614 $ (614 ) $ — Long-term liability Commodity derivative liabilities 217 (217 ) — Total liabilities $ 831 $ (831 ) $ — As of December 31, 2016 Classification Balance Sheet Location Gross Fair Effect of Net Carrying (In thousands) Assets: Current asset Commodity derivative assets $ 3,879 $ (3,879 ) $ — Long-term asset Deferred charges and other long-term assets — — — Total assets $ 3,879 $ (3,879 ) $ — Liabilities: Current liability Commodity derivative liabilities $ 20,116 $ (3,879 ) $ 16,237 Long-term liability Commodity derivative liabilities 482 — 482 Total liabilities $ 20,598 $ (3,879 ) $ 16,719 Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations. Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows: For the Nine Months Ended September 30, Derivatives not designated as hedging instruments 2017 2016 (In thousands) Beginning fair value of commodity derivative instruments $ (16,719 ) $ 64,534 Gain (loss) on oil derivative instruments 18,306 (8,906 ) Gain (loss) on natural gas derivative instruments 17,081 (3,389 ) Net cash received on settlements of oil derivative instruments (10,682 ) (23,034 ) Net cash received on settlements of natural gas derivative instruments (1,657 ) (16,186 ) Net change in fair value of commodity derivative instruments 23,048 (51,515 ) Ending fair value of commodity derivative instruments $ 6,329 $ 13,019 The Partnership had the following open derivative contracts for oil as of September 30, 2017 : Range (Per Bbl) Period and Type of Contract Volume Weighted Average Price Low High Oil Swap Contracts: 2017 Third Quarter 172,000 $ 53.31 $ 52.40 $ 55.23 Fourth Quarter 687,000 53.21 52.02 55.23 2018 First Quarter 611,000 $ 54.18 $ 52.09 $ 55.05 Second Quarter 573,000 54.16 52.09 54.90 Third Quarter 541,000 54.16 51.85 54.90 Fourth Quarter 502,000 54.22 51.85 54.90 The Partnership had the following open derivative contracts for natural gas as of September 30, 2017 : Range (Per MMBtu) Period and Type of Contract Volume Weighted Average Price Low High Natural Gas Swap Contracts: 2017 Fourth Quarter 13,130,000 $ 3.13 $ 2.92 $ 3.57 2018 First Quarter 12,570,000 $ 3.06 $ 2.96 $ 3.45 Second Quarter 11,340,000 3.03 2.86 3.23 Third Quarter 9,630,000 3.02 2.90 3.23 Fourth Quarter 8,210,000 3.01 2.90 3.23 Subsequent to September 30, 2017 , the Partnership entered into the following oil derivative contracts: Range (Per Bbl) Period and Type of Contract Volume Weighted Average Price Low High Oil Swap Contracts: 2017 Fourth Quarter 30,000 $ 56.51 $ 55.87 $ 57.15 2018 First Quarter 130,000 $ 55.02 $ 53.99 $ 57.15 Second Quarter 175,000 54.73 53.99 56.75 Third Quarter 215,000 54.71 53.99 55.87 Fourth Quarter 255,000 54.22 52.82 55.87 2019 First Quarter 165,000 $ 53.58 $ 52.82 $ 54.02 Second Quarter 165,000 53.58 52.82 54.02 Third Quarter 165,000 53.58 52.82 54.02 Fourth Quarter 165,000 53.58 52.82 54.02 Additionally, subsequent to September 30, 2017 , the Partnership entered into the following natural gas derivative contracts: Range (Per MMBtu) Period and Type of Contract Volume Weighted Average Price Low High Natural Gas Swap Contracts: 2018 First Quarter 1,020,000 $ 3.11 $ 3.01 $ 3.21 Second Quarter 2,320,000 3.00 2.93 3.04 Third Quarter 3,970,000 3.00 2.93 3.04 Fourth Quarter 5,420,000 3.00 2.92 3.04 2019 First Quarter 3,600,000 $ 2.91 $ 2.90 $ 2.93 Second Quarter 3,600,000 2.91 2.90 2.93 Third Quarter 3,600,000 2.91 2.90 2.93 Fourth Quarter 3,600,000 2.91 2.90 2.93 |
Fair Value Measurement
Fair Value Measurement | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurement | FAIR VALUE MEASUREMENT Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820 establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 —Unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 —Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Level 3 —Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value). A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the nine months ended September 30, 2017 or the year ended December 31, 2016 . The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of September 30, 2017 and December 31, 2016 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Derivatives and Financial Instruments for further discussion. The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Level 1 Level 2 Level 3 Total (In thousands) As of September 30, 2017 Financial Assets Commodity derivative instruments $ — $ 7,160 $ — $ (831 ) $ 6,329 Financial Liabilities Commodity derivative instruments $ — $ 831 $ — $ (831 ) $ — As of December 31, 2016 Financial Assets Commodity derivative instruments $ — $ 3,879 $ — $ (3,879 ) $ — Financial Liabilities Commodity derivative instruments $ — $ 20,598 $ — $ (3,879 ) $ 16,719 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Nonfinancial assets and liabilities measured at fair value on a nonrecurring basis include certain nonfinancial assets and liabilities, as may be acquired in a business combination, and measurements of oil and natural gas property values for assessment of impairment. The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 4 – Acquisitions and Dispositions. Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of September 30, 2017 or December 31, 2016 . The following table presents information about the Partnership’s assets measured at fair value on a nonrecurring basis: Fair Value Measurements Using 1 Net Book 1 Level 1 Level 2 Level 3 Impairment (In thousands) Three months ended September 30, 2017 Impaired oil and natural gas properties $ — — $ — $ — $ — $ — Three months ended September 30, 2016 Impaired oil and natural gas properties $ — $ — $ — $ — $ — Nine months ended September 30, 2017 Impaired oil and natural gas properties $ — — $ — $ — $ — $ — Nine months ended September 30, 2016 Impaired oil and natural gas properties $ — — $ — $ 3,042 $ 9,817 $ 6,775 1 Amounts represent value on the dates of assessment. |
Credit Facility
Credit Facility | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Credit Facility | CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement, as amended (the “Senior Line of Credit”). The Senior Line of Credit has a maximum credit amount of $1.0 billion . The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. Drawings on the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes. Effective April 15, 2016, the borrowing base was $450.0 million . The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base to $500.0 million , which became effective October 31, 2016. Effective April 25, 2017, the borrowing base redetermination resulted in an increase to $550.0 million . On November 1, 2017, the Partnership amended and restated the credit agreement to extend the maturity thereof for a term of five years, create a swingline facility and make other changes to the hedging and restrictive covenants. There was no change to the borrowing base. The Senior Line of Credit now terminates on November 1, 2022. Prior to October 31, 2016, borrowings under the Senior Line of Credit bore interest at LIBOR plus a margin between 1.50% and 2.50% , or the Prime Rate plus a margin between 0.50% and 1.50% , with the margin depending on the borrowing base utilization percentage. The Prime Rate was determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum. Effective October 31, 2016, borrowings under the Senior Line of Credit bore interest at LIBOR plus a margin between 2.00% and 3.00% , or the Prime rate plus a margin between 1.00% and 2.00% , with the margin depending on the borrowing base utilization. The weighted-average interest rate of the Senior Line of Credit was 3.74% and 3.26% as of September 30, 2017 and December 31, 2016 , respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days , in which case interest is payable at the end of every 90 -day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50% , or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50% . The Senior Line of Credit is secured by substantially all of the Partnership’s producing oil and natural gas assets. The Senior Line of Credit contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Senior Line of Credit requires the Partnership to maintain a current ratio of not less than 1.0 :1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5 :1.0. As of September 30, 2017 , the Partnership was in compliance with all financial covenants for the Senior Line of Credit. The aggregate principal balance outstanding was $362.0 million and $316.0 million at September 30, 2017 and December 31, 2016 , respectively. The unused portion of the available borrowings under the Senior Line of Credit was $188.0 million and $184.0 million at September 30, 2017 and December 31, 2016 , respectively. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been made. Litigation From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of September 30, 2017 will be resolved without material adverse effect on the Partnership’s financial condition or operations. |
Incentive Compensation
Incentive Compensation | 9 Months Ended |
Sep. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Incentive Compensation | INCENTIVE COMPENSATION On January 7, 2017, the Compensation Committee of the Board of Directors of the Partnership’s general partner (the “Board”) approved a special grant of 312,825 restricted common units to Thomas L. Carter, Jr., the President and Chief Executive Officer of the Partnership’s general partner. Such restricted common units are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020. On January 11, 2017, each non-employee director on the Board, other than Robert E. W. Sinclair, was granted 9,095 fully vested common units for service during 2016. Mr. Sinclair was granted 3,653 fully vested common units for services during 2016 prior to his resignation from the Board. On July 28, 2017, Mr. William Randall, the newly elected member of the Board, was issued 6,426 fully vested common units. On February 15, 2017, the Compensation Committee of the Board approved a grant of awards to each of the Partnership’s executive officers and certain other employees. These awards consisted of 438,067 restricted common units and 438,067 restricted performance units (in the form of phantom units) with distribution equivalent rights. The restricted common units are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020. The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 , respectively: Three Months Ended Nine Months Ended Incentive compensation expense 2017 2016 2017 2016 (In thousands) (In thousands) Cash—long-term incentive plan $ 359 $ 580 $ 995 $ 2,990 Equity-based compensation—restricted common and subordinated units 3,364 4,487 10,246 10,420 Equity-based compensation—restricted performance units 3,767 3,066 6,710 11,105 Board of Directors incentive plan 544 428 1,658 1,385 Total incentive compensation expense $ 8,034 $ 8,561 $ 19,609 $ 25,900 |
Redeemable Preferred Units
Redeemable Preferred Units | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Redeemable Preferred Units | REDEEMABLE PREFERRED UNITS The Partnership had 26,426 and 52,691 redeemable preferred units outstanding with a carrying value of $27.1 million and $54.0 million as of September 30, 2017 and December 31, 2016 , respectively. The aforementioned amounts included accrued distributions of $0.7 million as of September 30, 2017 and $1.3 million as of December 31, 2016 . The redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Partnership. The redeemable preferred units are entitled to an annual distribution of 10% of the outstanding funded capital of the redeemable preferred units, payable on a quarterly basis in arrears. The redeemable preferred units are convertible into common and subordinated units at any time at the option of the redeemable preferred unitholders. The redeemable preferred units have an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capital restructuring related to the IPO. The redeemable preferred unitholders can elect to have the Partnership redeem, at face value, all remaining redeemable preferred units as of December 31, 2017 , plus any accrued and unpaid distributions. All redeemable preferred units not redeemed as of 2017 year end shall automatically convert to common and subordinated units during the first quarter of 2018. For the nine months ended September 30, 2017 , 19,641 redeemable preferred units were redeemed for $20.1 million , including accrued unpaid yield, and 6,624 redeemable preferred units totaling $6.6 million were converted into 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016 . For the year ended December 31, 2016 , 6,064 redeemable preferred units totaling $6.1 million were converted into the equivalent of 184,006 common units and 240,986 subordinated units on an adjusted basis. |
Earnings Per Unit
Earnings Per Unit | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Unit | EARNINGS PER UNIT The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The redeemable preferred units could be converted into 0.8 million common units and 1.0 million subordinated units as of September 30, 2017 . At September 30, 2017 , if the outstanding redeemable preferred units were converted to common and subordinated units, the effect would be anti-dilutive. The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. At September 30, 2017 , there were no units related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU. The following table sets forth the computation of basic and diluted earnings per common and subordinated unit: For the Three Months Ended For the Nine Months Ended 2017 2016 2017 2016 (In thousands, except per unit amounts) (In thousands, except per unit amounts) NET INCOME (LOSS) $ 22,034 $ 37,535 $ 137,793 $ 27,474 NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS 20 8 27 15 DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS (666 ) (1,324 ) (2,452 ) (4,439 ) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 21,388 $ 36,219 $ 135,368 $ 23,050 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 16,371 23,114 83,989 24,343 Subordinated units 5,017 13,105 51,379 (1,293 ) $ 21,388 $ 36,219 $ 135,368 $ 23,050 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 0.16 $ 0.24 $ 0.86 $ 0.26 Weighted average common units outstanding (basic) 101,623 95,740 97,777 95,086 Per subordinated unit (basic) $ 0.05 $ 0.14 $ 0.54 $ (0.01 ) Weighted average subordinated units outstanding (basic) 95,388 95,189 95,269 95,125 Per common unit (diluted) $ 0.16 $ 0.24 $ 0.86 $ 0.26 Weighted average common units outstanding (diluted) 101,623 96,011 97,777 95,619 Per subordinated unit (diluted) $ 0.05 $ 0.14 $ 0.54 $ (0.01 ) Weighted average subordinated units outstanding (diluted) 95,388 95,189 95,269 95,467 |
AT-THE-MARKET OFFERING PROGRAM
AT-THE-MARKET OFFERING PROGRAM | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
At-The-Market Offering Program | AT-THE-MARKET OFFERING PROGRAM On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering price of up to $100,000,000 . Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange. Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent. The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s credit facility. Common units sold pursuant to the Equity Distribution Agreement are offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017. The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions. Through September 30, 2017 , the Partnership sold 1.9 million common units under the ATM Program for net proceeds of $31.3 million . |
Subsequent Events
Subsequent Events | 9 Months Ended |
Sep. 30, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS On November 1, 2017, the Partnership amended and restated its credit agreement, as discussed further in Note 7 — Credit Facility. On November 6, 2017 , the Board approved a distribution for the three months ended September 30, 2017 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions will be payable on November 24, 2017 to unitholders of record at the close of business on November 17, 2017 . Additionally, on November 6, 2017, the Partnership entered into oil and natural gas commodity derivative contracts, as summarized in Note 5 — Derivatives and Financial Instruments. |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2016 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. All intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership. In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. The results of operations for the nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements. The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows. |
Segment Reporting | Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level. |
New Accounting Pronouncements | New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition . Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption permitted. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. The Partnership intends to use the modified retrospective adoption approach and does not plan to early adopt . The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard is not anticipated to have a material impact on the consolidated financial statements. The Partnership is concurrently evaluating the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership continues to evaluate the disclosure requirements of this new guidance, and expects to fully complete its evaluation of the impacts of ASU 2014-09 to the consolidated financial statements and related disclosures by 2017 year end . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach and does not plan to early adopt. Based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230) , to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is permitted. The Partnership intends to use the retrospective transition method, does not plan to early adopt, and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted under certain circumstances. The amendments in this ASU should be applied prospectively as of the beginning of the period of adoption. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. In May 2017, the FASB issued ASU 2017-09 Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718) . The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met: • The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified. • The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified. • The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The amendments in this ASU should be applied prospectively to an award modified on or after the adoption date. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures. |
Earnings Per Unit | The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation Liability | The following table describes changes to the Partnership’s ARO liability during the period: For the nine months ended September 30, 2017 (In thousands) Beginning asset retirement obligations $ 13,350 Liabilities incurred 290 Liabilities settled (113 ) Accretion expense 760 Dispositions (5 ) Revisions (71 ) Ending asset retirement obligations $ 14,211 Current asset retirement obligations $ 302 Non-current asset retirement obligations $ 13,909 |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Schedule of Fair Values of the Properties Acquired | The following table summarizes the fair values assigned to the properties acquired: Proved Unproved Net Working Capital ARO Total Fair Value Cash (in thousands) June $ 39,735 $ 79,827 $ 2,064 $ (50 ) $ 121,576 $ 121,576 The following table summarizes the asset acquisitions which included producing properties: Proved Unproved Net Working Capital Total Fair Value Acquisition-Related Costs 1 Cash Fair Value of Common Units Issued (in thousands) January $ 5,135 $ 34,008 $ 263 $ 39,406 $ 1,162 $ 27,380 $ 12,026 June 5,006 45,477 — 50,483 1,468 4,802 45,681 August 3,277 9,984 — 13,261 89 4,289 8,972 September 3,120 — — 3,120 — 3,120 — Total fair value $ 16,538 $ 89,469 $ 263 $ 106,270 $ 2,719 $ 39,591 $ 66,679 1 Acquisition-related costs were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations. In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as follows: Unproved Cash Fair Value of Common Units Issued (in thousands) Q1 2017 $ 21,189 $ 21,017 $ 172 Q2 2017 13,329 13,329 — Q3 2017 19,946 15,205 4,741 $ 54,464 $ 49,551 $ 4,913 |
Derivatives and Financial Ins23
Derivatives and Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Derivative [Line Items] | |
Summary of Fair Value and Classification of Derivative Instruments | The table below summarizes the fair value and classification of the Partnership’s derivative instruments: As of September 30, 2017 Classification Balance Sheet Location Gross Fair Effect of Net Carrying (In thousands) Assets: Current asset Commodity derivative assets $ 5,338 $ (614 ) $ 4,724 Long-term asset Deferred charges and other long-term assets 1,822 (217 ) 1,605 Total assets $ 7,160 $ (831 ) $ 6,329 Liabilities: Current liability Commodity derivative liabilities $ 614 $ (614 ) $ — Long-term liability Commodity derivative liabilities 217 (217 ) — Total liabilities $ 831 $ (831 ) $ — As of December 31, 2016 Classification Balance Sheet Location Gross Fair Effect of Net Carrying (In thousands) Assets: Current asset Commodity derivative assets $ 3,879 $ (3,879 ) $ — Long-term asset Deferred charges and other long-term assets — — — Total assets $ 3,879 $ (3,879 ) $ — Liabilities: Current liability Commodity derivative liabilities $ 20,116 $ (3,879 ) $ 16,237 Long-term liability Commodity derivative liabilities 482 — 482 Total liabilities $ 20,598 $ (3,879 ) $ 16,719 |
Changes in Fair Value of Company's Commodity Derivative Instruments | Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows: For the Nine Months Ended September 30, Derivatives not designated as hedging instruments 2017 2016 (In thousands) Beginning fair value of commodity derivative instruments $ (16,719 ) $ 64,534 Gain (loss) on oil derivative instruments 18,306 (8,906 ) Gain (loss) on natural gas derivative instruments 17,081 (3,389 ) Net cash received on settlements of oil derivative instruments (10,682 ) (23,034 ) Net cash received on settlements of natural gas derivative instruments (1,657 ) (16,186 ) Net change in fair value of commodity derivative instruments 23,048 (51,515 ) Ending fair value of commodity derivative instruments $ 6,329 $ 13,019 |
Oil and Natural Gas | |
Derivative [Line Items] | |
Summary of Open Derivative Contracts | The Partnership had the following open derivative contracts for oil as of September 30, 2017 : Range (Per Bbl) Period and Type of Contract Volume Weighted Average Price Low High Oil Swap Contracts: 2017 Third Quarter 172,000 $ 53.31 $ 52.40 $ 55.23 Fourth Quarter 687,000 53.21 52.02 55.23 2018 First Quarter 611,000 $ 54.18 $ 52.09 $ 55.05 Second Quarter 573,000 54.16 52.09 54.90 Third Quarter 541,000 54.16 51.85 54.90 Fourth Quarter 502,000 54.22 51.85 54.90 The Partnership had the following open derivative contracts for natural gas as of September 30, 2017 : Range (Per MMBtu) Period and Type of Contract Volume Weighted Average Price Low High Natural Gas Swap Contracts: 2017 Fourth Quarter 13,130,000 $ 3.13 $ 2.92 $ 3.57 2018 First Quarter 12,570,000 $ 3.06 $ 2.96 $ 3.45 Second Quarter 11,340,000 3.03 2.86 3.23 Third Quarter 9,630,000 3.02 2.90 3.23 Fourth Quarter 8,210,000 3.01 2.90 3.23 Subsequent to September 30, 2017 , the Partnership entered into the following oil derivative contracts: Range (Per Bbl) Period and Type of Contract Volume Weighted Average Price Low High Oil Swap Contracts: 2017 Fourth Quarter 30,000 $ 56.51 $ 55.87 $ 57.15 2018 First Quarter 130,000 $ 55.02 $ 53.99 $ 57.15 Second Quarter 175,000 54.73 53.99 56.75 Third Quarter 215,000 54.71 53.99 55.87 Fourth Quarter 255,000 54.22 52.82 55.87 2019 First Quarter 165,000 $ 53.58 $ 52.82 $ 54.02 Second Quarter 165,000 53.58 52.82 54.02 Third Quarter 165,000 53.58 52.82 54.02 Fourth Quarter 165,000 53.58 52.82 54.02 Additionally, subsequent to September 30, 2017 , the Partnership entered into the following natural gas derivative contracts: Range (Per MMBtu) Period and Type of Contract Volume Weighted Average Price Low High Natural Gas Swap Contracts: 2018 First Quarter 1,020,000 $ 3.11 $ 3.01 $ 3.21 Second Quarter 2,320,000 3.00 2.93 3.04 Third Quarter 3,970,000 3.00 2.93 3.04 Fourth Quarter 5,420,000 3.00 2.92 3.04 2019 First Quarter 3,600,000 $ 2.91 $ 2.90 $ 2.93 Second Quarter 3,600,000 2.91 2.90 2.93 Third Quarter 3,600,000 2.91 2.90 2.93 Fourth Quarter 3,600,000 2.91 2.90 2.93 |
Fair Value Measurement (Tables)
Fair Value Measurement (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis | The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Level 1 Level 2 Level 3 Total (In thousands) As of September 30, 2017 Financial Assets Commodity derivative instruments $ — $ 7,160 $ — $ (831 ) $ 6,329 Financial Liabilities Commodity derivative instruments $ — $ 831 $ — $ (831 ) $ — As of December 31, 2016 Financial Assets Commodity derivative instruments $ — $ 3,879 $ — $ (3,879 ) $ — Financial Liabilities Commodity derivative instruments $ — $ 20,598 $ — $ (3,879 ) $ 16,719 |
Schedule of Assets Measured at Fair Value on a Nonrecurring Basis | The following table presents information about the Partnership’s assets measured at fair value on a nonrecurring basis: Fair Value Measurements Using 1 Net Book 1 Level 1 Level 2 Level 3 Impairment (In thousands) Three months ended September 30, 2017 Impaired oil and natural gas properties $ — — $ — $ — $ — $ — Three months ended September 30, 2016 Impaired oil and natural gas properties $ — $ — $ — $ — $ — Nine months ended September 30, 2017 Impaired oil and natural gas properties $ — — $ — $ — $ — $ — Nine months ended September 30, 2016 Impaired oil and natural gas properties $ — — $ — $ 3,042 $ 9,817 $ 6,775 1 Amounts represent value on the dates of assessment. |
Incentive Compensation (Tables)
Incentive Compensation (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of Incentive Compensation Expense | The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 , respectively: Three Months Ended Nine Months Ended Incentive compensation expense 2017 2016 2017 2016 (In thousands) (In thousands) Cash—long-term incentive plan $ 359 $ 580 $ 995 $ 2,990 Equity-based compensation—restricted common and subordinated units 3,364 4,487 10,246 10,420 Equity-based compensation—restricted performance units 3,767 3,066 6,710 11,105 Board of Directors incentive plan 544 428 1,658 1,385 Total incentive compensation expense $ 8,034 $ 8,561 $ 19,609 $ 25,900 |
Earnings Per Unit (Tables)
Earnings Per Unit (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Earnings per Common and Subordinated Unit | The following table sets forth the computation of basic and diluted earnings per common and subordinated unit: For the Three Months Ended For the Nine Months Ended 2017 2016 2017 2016 (In thousands, except per unit amounts) (In thousands, except per unit amounts) NET INCOME (LOSS) $ 22,034 $ 37,535 $ 137,793 $ 27,474 NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS 20 8 27 15 DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS (666 ) (1,324 ) (2,452 ) (4,439 ) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 21,388 $ 36,219 $ 135,368 $ 23,050 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 16,371 23,114 83,989 24,343 Subordinated units 5,017 13,105 51,379 (1,293 ) $ 21,388 $ 36,219 $ 135,368 $ 23,050 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 0.16 $ 0.24 $ 0.86 $ 0.26 Weighted average common units outstanding (basic) 101,623 95,740 97,777 95,086 Per subordinated unit (basic) $ 0.05 $ 0.14 $ 0.54 $ (0.01 ) Weighted average subordinated units outstanding (basic) 95,388 95,189 95,269 95,125 Per common unit (diluted) $ 0.16 $ 0.24 $ 0.86 $ 0.26 Weighted average common units outstanding (diluted) 101,623 96,011 97,777 95,619 Per subordinated unit (diluted) $ 0.05 $ 0.14 $ 0.54 $ (0.01 ) Weighted average subordinated units outstanding (diluted) 95,388 95,189 95,269 95,467 |
Business and Basis of Present27
Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions | May 06, 2015USD ($)$ / sharesshares | Sep. 30, 2017basinstateshares |
U.S. | ||
Limited Partners Capital Account [Line Items] | ||
Number of states major onshore oil and natural gas basins located | state | 41 | |
Number of onshore oil and natural gas producing basins | basin | 64 | |
Common Units | ||
Limited Partners Capital Account [Line Items] | ||
Units exchanged in merger (in shares) | 72,574,715 | 4,341,000 |
Capital units converted upon merger (in shares) | 201,000 | |
Common Units | Predecessor | ||
Limited Partners Capital Account [Line Items] | ||
Units conversion ratio as part of merger | 12.9465 | |
Units conversion ratio split up as part of merger | 0.4329 | |
Common Units | IPO | Limited Partner | ||
Limited Partners Capital Account [Line Items] | ||
Issuance of common units for initial public offering, net of offering costs, units | 22,500,000 | |
Price per common unit (in dollars per unit) | $ / shares | $ 19 | |
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions | $ | $ 391.5 | |
Subordinated Units | ||
Limited Partners Capital Account [Line Items] | ||
Units exchanged in merger (in shares) | 95,057,312 | |
Capital units converted upon merger (in shares) | 263,000 | |
Subordinated Units | Predecessor | ||
Limited Partners Capital Account [Line Items] | ||
Units conversion ratio split up as part of merger | 0.5671 | |
Preferred Units | Predecessor | ||
Limited Partners Capital Account [Line Items] | ||
Units conversion ratio as part of merger | 1 | |
Capital units converted upon merger (in shares) | 117,963 |
Asset Retirement Obligations -
Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation Liability (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Beginning asset retirement obligations | $ 13,350 | ||||
Liabilities incurred | 290 | ||||
Liabilities settled | (113) | ||||
Accretion expense | $ 260 | $ 206 | 760 | $ 680 | |
Dispositions | (5) | ||||
Revisions | (71) | ||||
Ending asset retirement obligations | 14,211 | 14,211 | |||
Other current liabilities | 302 | 302 | $ 0 | ||
Non-current asset retirement obligations | $ 13,909 | $ 13,909 | $ 13,350 |
Acquisitions and Dispositions -
Acquisitions and Dispositions - Additional Information (Details) $ in Millions | Feb. 21, 2017USD ($)wellphase | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) |
Business Acquisition [Line Items] | |||
Payments to acquire oil, mineral, and royalty interests | $ 1 | ||
Permian Basin | |||
Business Acquisition [Line Items] | |||
Payments to acquire oil, mineral, and royalty interests | $ 10 | ||
Midland Basin | |||
Business Acquisition [Line Items] | |||
Payments to acquire oil, mineral, and royalty interests | $ 8.3 | ||
Angelina County, Texas | Farmout Agreement | |||
Business Acquisition [Line Items] | |||
Ownership interest in the acreage, percent | 50.00% | ||
Number of wells anticipated to be drilled | well | 18 | ||
Additional wells to be drilled | well | 20 | ||
Number of phases | phase | 3 | ||
Angelina County, Texas | Farmout Agreement | Canaan Resource Partners | |||
Business Acquisition [Line Items] | |||
Number of additional phases | phase | 2 | ||
Term of phase (years) | 2 years | ||
Funding requirements, drilling and completion costs, percent | 80.00% | ||
Ownership interest in wells, percent | 80.00% | ||
Ownership interest, gross, percent | 40.00% | ||
Third phase, ownership interest in additional wells, percent | 40.00% | ||
Third phase, ownership interest in additional wells, gross, percent | 20.00% | ||
Third phase, funding requirements, drilling and completion costs, percent | 40.00% | ||
Angelina County, Texas | Farmout Agreement | Minimum | |||
Business Acquisition [Line Items] | |||
Anticipated reduction in capital obligations, next 12 months | $ 30 | ||
Anticipated reduction in capital obligations, annually | 40 | ||
Angelina County, Texas | Farmout Agreement | Maximum | |||
Business Acquisition [Line Items] | |||
Anticipated reduction in capital obligations, next 12 months | 35 | ||
Anticipated reduction in capital obligations, annually | $ 50 |
Acquisitions and Dispositions30
Acquisitions and Dispositions - Schedule of Fair Values of the Properties Acquired (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 6 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2017 | Aug. 31, 2017 | Jun. 30, 2017 | Jan. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Jun. 30, 2016 | Sep. 30, 2017 | Sep. 29, 2017 | |
Delaware Basin And East Texas | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proved oil and natural gas properties | $ 3,120,000 | $ 3,277,000 | $ 5,006,000 | $ 5,135,000 | $ 16,538,000 | |||||
Unproved oil and natural gas properties | 0 | 9,984,000 | 45,477,000 | 34,008,000 | 89,469,000 | |||||
Net working capital | 0 | 0 | 0 | 263,000 | 263,000 | |||||
Total fair value | 3,120,000 | 13,261,000 | 50,483,000 | 39,406,000 | 106,270,000 | |||||
Acquisition related costs | 0 | 89,000 | 1,468,000 | 1,162,000 | 2,719,000 | |||||
Cost incurred, acquired cash | 39,591,000 | 4,289,000 | 4,802,000 | 27,380,000 | $ 39,591,000 | $ 4,802,000 | 39,591,000 | $ 3,120,000 | ||
Fair value common units issued | 0 | $ 8,972,000 | 45,681,000 | $ 12,026,000 | 66,679,000 | |||||
East Texas | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Unproved oil and natural gas properties | 19,946 | 13,329 | $ 21,189 | 54,464 | ||||||
Cost incurred, acquired cash | $ 49,551 | $ 13,329 | 49,551 | 13,329 | 21,017 | 49,551 | $ 15,205 | |||
Fair value common units issued | $ 4,741 | $ 0 | $ 172 | $ 4,913 | ||||||
DJ Basin | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proved oil and natural gas properties | $ 39,735,000 | |||||||||
Unproved oil and natural gas properties | 79,827,000 | |||||||||
Net working capital | 2,064,000 | |||||||||
Asset retirement obligations | (50,000) | |||||||||
Total fair value | 121,576,000 | |||||||||
Cost incurred, acquired cash | $ 121,576,000 |
Derivatives and Financial Ins31
Derivatives and Financial Instruments - Additional Information (Details) $ in Millions | Sep. 30, 2017USD ($)counterparty |
Derivative [Line Items] | |
Number of counterparties | 9 |
Senior Line of Credit | |
Derivative [Line Items] | |
Number of counterparties | 7 |
Fair value of risk exposure | $ | $ 7.2 |
Derivatives and Financial Ins32
Derivatives and Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Derivatives Fair Value [Line Items] | ||
Gross Fair Value, Assets | $ 3,879 | |
Effect of Counterparty Netting, Assets | $ (831) | (3,879) |
Net Carrying Value on Balance Sheet, Assets | 6,329 | 0 |
Gross Fair Value, Liabilities | 20,598 | |
Effect of Counterparty Netting, Liabilities | (831) | (3,879) |
Net Carrying Value on Balance Sheet, Liabilities | 0 | 16,719 |
Commodity derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Fair Value, Assets | 5,338 | 3,879 |
Effect of Counterparty Netting, Assets | (614) | (3,879) |
Net Carrying Value on Balance Sheet, Assets | 4,724 | 0 |
Deferred charges and other long-term assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Fair Value, Assets | 1,822 | 0 |
Effect of Counterparty Netting, Assets | (217) | 0 |
Net Carrying Value on Balance Sheet, Assets | 1,605 | 0 |
Commodity derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Fair Value, Liabilities | 614 | 20,116 |
Effect of Counterparty Netting, Liabilities | (614) | (3,879) |
Net Carrying Value on Balance Sheet, Liabilities | 0 | 16,237 |
Commodity derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Fair Value, Liabilities | 217 | 482 |
Effect of Counterparty Netting, Liabilities | (217) | 0 |
Net Carrying Value on Balance Sheet, Liabilities | $ 0 | $ 482 |
Derivatives and Financial Ins33
Derivatives and Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Derivatives not designated as hedging instruments | ||||
Gain (loss) on commodity derivative instruments | $ (9,341) | $ 7,813 | $ 35,387 | $ (12,295) |
Net cash received on settlements of derivative instruments | (12,339) | (39,220) | ||
Not Designated as Hedging Instrument | ||||
Derivatives not designated as hedging instruments | ||||
Beginning fair value of commodity derivative instruments | (16,719) | 64,534 | ||
Net change in fair value of commodity derivative instruments | 23,048 | (51,515) | ||
Ending fair value of commodity derivative instruments | $ 6,329 | $ 13,019 | 6,329 | 13,019 |
Oil | Not Designated as Hedging Instrument | ||||
Derivatives not designated as hedging instruments | ||||
Gain (loss) on commodity derivative instruments | 18,306 | (8,906) | ||
Net cash received on settlements of derivative instruments | (10,682) | (23,034) | ||
Natural Gas | Not Designated as Hedging Instrument | ||||
Derivatives not designated as hedging instruments | ||||
Gain (loss) on commodity derivative instruments | 17,081 | (3,389) | ||
Net cash received on settlements of derivative instruments | $ (1,657) | $ (16,186) |
Derivatives and Financial Ins34
Derivatives and Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Swaps Contract - Not Designated as Hedging Instrument - Swap bbl in Thousands, MMBTU in Thousands | 1 Months Ended | 9 Months Ended |
Nov. 07, 2017MMBTU$ / MMBTU$ / bblbbl | Sep. 30, 2017MMBTU$ / MMBTU$ / bblbbl | |
Third Quarter 2017 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 172 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 53.31 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.40 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 55.23 | |
Fourth Quarter 2017 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 687 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 53.21 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.02 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 55.23 | |
Fourth Quarter 2017 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 13,130 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3.13 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.92 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.57 | |
First Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 611 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 54.18 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.09 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 55.05 | |
First Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 12,570 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3.06 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.96 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.45 | |
Second Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 573 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 54.16 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.09 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 54.90 | |
Second Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 11,340 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3.03 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.86 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.23 | |
Third Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 541 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 54.16 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 51.85 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 54.90 | |
Third Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 9,630 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3.02 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.90 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.23 | |
Fourth Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 502 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 54.22 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 51.85 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 54.90 | |
Fourth Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 8,210 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3.01 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.90 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.23 | |
Subsequent Event | Fourth Quarter 2017 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 30 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 56.51 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 55.87 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 57.15 | |
Subsequent Event | First Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 130 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 55.02 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 53.99 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 57.15 | |
Subsequent Event | First Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 1,020 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3.11 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 3.01 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.21 | |
Subsequent Event | Second Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 175 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 54.73 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 53.99 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 56.75 | |
Subsequent Event | Second Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 2,320 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.04 | |
Subsequent Event | Third Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 215 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 54.71 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 53.99 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 55.87 | |
Subsequent Event | Third Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 3,970 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.04 | |
Subsequent Event | Fourth Quarter 2018 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 255 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 54.22 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 55.87 | |
Subsequent Event | Fourth Quarter 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 5,420 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 3 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.92 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 3.04 | |
Subsequent Event | First Quarter 2019 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 165 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 53.58 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 54.02 | |
Subsequent Event | First Quarter 2019 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 3,600 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.91 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.90 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 | |
Subsequent Event | Second Quarter 2019 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 165 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 53.58 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 54.02 | |
Subsequent Event | Second Quarter 2019 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 3,600 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.91 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.90 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 | |
Subsequent Event | Third Quarter 2019 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 165 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 53.58 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 54.02 | |
Subsequent Event | Third Quarter 2019 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 3,600 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.91 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.90 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 | |
Subsequent Event | Fourth Quarter 2019 | Oil | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in Bbl) | bbl | 165 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 53.58 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 54.02 | |
Subsequent Event | Fourth Quarter 2019 | Natural Gas | ||
Derivative [Line Items] | ||
Derivative Contract, Volume (in MMBtu) | MMBTU | 3,600 | |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.91 | |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.90 | |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 |
Fair Value Measurement - Additi
Fair Value Measurement - Additional Information (Details) - USD ($) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2017 | Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | ||
Fair value, assets transfer between the three fair value hierarchy levels | $ 0 | $ 0 |
Fair value, liabilities transfer between the three fair value hierarchy levels | $ 0 | $ 0 |
Fair Value Measurement - Schedu
Fair Value Measurement - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Gross Fair Value, Assets | $ 3,879 | |
Effect of Counterparty Netting, Assets | $ (831) | (3,879) |
Net Carrying Value on Balance Sheet, Assets | 6,329 | 0 |
Gross Fair Value, Liabilities | 20,598 | |
Effect of Counterparty Netting, Liabilities | (831) | (3,879) |
Net Carrying Value on Balance Sheet, Liabilities | 0 | 16,719 |
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Effect of Counterparty Netting, Assets | (3,879) | |
Net Carrying Value on Balance Sheet, Assets | 6,329 | 0 |
Effect of Counterparty Netting, Liabilities | (3,879) | |
Net Carrying Value on Balance Sheet, Liabilities | 0 | 16,719 |
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Gross Fair Value, Assets | 7,160 | 3,879 |
Gross Fair Value, Liabilities | $ 831 | $ 20,598 |
Fair Value Measurement - Sche37
Fair Value Measurement - Schedule of Assets Measured at Fair Value on a Nonrecurring Basis (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Impaired oil and natural gas properties, Impairment | $ 0 | $ 0 | $ 0 | $ 6,775 |
Fair Value Measurements, Nonrecurring Basis | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Impaired oil and natural gas properties, Fair Value Measurements | 0 | 0 | 0 | |
Impaired oil and natural gas properties, Net Book Value | 0 | 0 | 0 | 9,817 |
Impaired oil and natural gas properties, Impairment | 0 | 0 | 0 | 6,775 |
Fair Value Measurements, Nonrecurring Basis | Level 1 | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Impaired oil and natural gas properties, Fair Value Measurements | 0 | 0 | 0 | 0 |
Fair Value Measurements, Nonrecurring Basis | Level 2 | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Impaired oil and natural gas properties, Fair Value Measurements | 0 | 0 | 0 | 0 |
Fair Value Measurements, Nonrecurring Basis | Level 3 | ||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||
Impaired oil and natural gas properties, Fair Value Measurements | $ 0 | $ 0 | $ 0 | $ 3,042 |
Credit Facility - Additional In
Credit Facility - Additional Information (Details) | Nov. 01, 2017 | Oct. 31, 2016USD ($) | Sep. 30, 2017USD ($) | Apr. 25, 2017USD ($) | Dec. 31, 2016USD ($) | Apr. 15, 2016USD ($) |
Line Of Credit Facility [Line Items] | ||||||
Credit facility | $ 362,000,000 | $ 316,000,000 | ||||
Senior Line of Credit | Revolving Credit Facility | ||||||
Line Of Credit Facility [Line Items] | ||||||
Maximum borrowing capacity | $ 1,000,000,000 | |||||
Borrowing base | $ 500,000,000 | $ 550,000,000 | $ 450,000,000 | |||
Interest payable, term | 90 days | |||||
Weighted average interest rate (percent) | 3.74% | 3.26% | ||||
Borrowing base threshold (percent) | 50.00% | |||||
Credit facility | $ 362,000,000 | $ 316,000,000 | ||||
Unused portion of current borrowing base | $ 188,000,000 | $ 184,000,000 | ||||
Senior Line of Credit | Revolving Credit Facility | Federal funds effective rate | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest rate (percent) | 0.50% | |||||
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Less Than 50% | ||||||
Line Of Credit Facility [Line Items] | ||||||
Commitment fee payable rate (percent) | 0.375% | |||||
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Equal to or Greater Than 50% | ||||||
Line Of Credit Facility [Line Items] | ||||||
Commitment fee payable rate (percent) | 0.50% | |||||
Senior Line of Credit | Revolving Credit Facility | Minimum | ||||||
Line Of Credit Facility [Line Items] | ||||||
Current ratio | 1 | |||||
Senior Line of Credit | Revolving Credit Facility | Minimum | LIBOR Plus Margin Rate | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest rate (percent) | 2.00% | 1.50% | ||||
Senior Line of Credit | Revolving Credit Facility | Minimum | Prime Rate Plus Margin Rate | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest rate (percent) | 1.00% | 0.50% | ||||
Senior Line of Credit | Revolving Credit Facility | Maximum | ||||||
Line Of Credit Facility [Line Items] | ||||||
Ratio of total debt to EBITDAX | 3.5 | |||||
Senior Line of Credit | Revolving Credit Facility | Maximum | LIBOR Plus Margin Rate | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest rate (percent) | 3.00% | 2.50% | ||||
Senior Line of Credit | Revolving Credit Facility | Maximum | Prime Rate Plus Margin Rate | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest rate (percent) | 2.00% | 1.50% | ||||
Subsequent Event | Senior Line of Credit | Revolving Credit Facility | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest payable, term | 5 years |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Details) | Sep. 30, 2017USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Provision for remediation costs | $ 0 |
Incentive Compensation - Additi
Incentive Compensation - Additional Information (Details) - shares | Jul. 28, 2017 | Feb. 15, 2017 | Jan. 11, 2017 | Jan. 07, 2017 |
Common Units | President and CEO | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Grant of stock units, fully vested (in shares) | 312,825 | |||
Common Units | Non-employee Directors | Non-Employee Director on the Board other than Robert E. W. Sinclair | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Grant of stock units, fully vested (in shares) | 9,095 | |||
Common Units | Non-employee Directors | Robert E. W. Sinclair | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Grant of stock units, fully vested (in shares) | 3,653 | |||
Common Units | Non-employee Directors | William Randall | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Grant of stock units, fully vested (in shares) | 6,426 | |||
Restricted Common Units | 2015 LTIP | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Grant of stock units (in shares) | 438,067 | |||
Restricted Performance Units | 2015 LTIP | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Grant of stock units (in shares) | 438,067 |
Incentive Compensation - Summar
Incentive Compensation - Summary of Incentive Compensation Expense (Details) - General and administrative expenses - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Cash—long-term incentive plan | $ 359 | $ 580 | $ 995 | $ 2,990 |
Total incentive compensation expense | 8,034 | 8,561 | 19,609 | 25,900 |
Restricted common and subordinated units | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Equity-based compensation | 3,364 | 4,487 | 10,246 | 10,420 |
Restricted Performance Units | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Equity-based compensation | 3,767 | 3,066 | 6,710 | 11,105 |
Board of Directors | Common Units | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Total incentive compensation expense | $ 544 | $ 428 | $ 1,658 | $ 1,385 |
Redeemable Preferred Units - Ad
Redeemable Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2017USD ($)$ / sharesshares | Dec. 31, 2016USD ($)shares | |
Class of Stock [Line Items] | ||
Preferred units, outstanding value | $ | $ 27,092 | $ 54,015 |
Preferred Units | ||
Class of Stock [Line Items] | ||
Partners' equity, preferred units, outstanding (in shares) | shares | 26,426 | 52,691 |
Preferred units, outstanding value | $ | $ 27,100 | $ 54,000 |
Accrued distributions | $ | $ 700 | $ 1,300 |
Preferred units distribution rate | 10.00% | |
Adjusted conversion price (in us dollars per share) | $ / shares | $ 14.2683 | |
Preferred units, redeemed (in shares) | shares | 19,641 | |
Payments redeem preferred units | $ | $ 20,100 | |
Number of preferred units converted (in shares) | shares | 6,624 | 6,064 |
Conversion of preferred units to common units | $ | $ 6,600 | $ 6,100 |
Common Units | ||
Class of Stock [Line Items] | ||
Adjusted conversion rate | 30.3431 | |
Conversion of preferred units (in shares) | shares | 200,996 | 184,006 |
Subordinated Units | ||
Class of Stock [Line Items] | ||
Adjusted conversion rate | 39.7427 | |
Conversion of preferred units (in shares) | shares | 263,247 | 240,986 |
Earnings Per Unit - Additional
Earnings Per Unit - Additional Information (Details) shares in Millions | 9 Months Ended |
Sep. 30, 2017shares | |
Common Units | |
Earnings Per Share Basic [Line Items] | |
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU | 0.8 |
Subordinated Units | |
Earnings Per Share Basic [Line Items] | |
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU | 1 |
Earnings Per Unit - Computation
Earnings Per Unit - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Earnings Per Share Basic [Line Items] | ||||
Net income (loss) | $ 22,034 | $ 37,535 | $ 137,793 | $ 27,474 |
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | 20 | 8 | 27 | 15 |
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS | (666) | (1,324) | (2,452) | (4,439) |
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | 21,388 | 36,219 | 135,368 | 23,050 |
ALLOCATION OF NET INCOME (LOSS): | ||||
General partner interest | 0 | 0 | 0 | 0 |
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | 21,388 | 36,219 | 135,368 | 23,050 |
Common Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 16,371 | $ 23,114 | $ 83,989 | $ 24,343 |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.16 | $ 0.24 | $ 0.86 | $ 0.26 |
Weighted average units outstanding (basic) (in shares) | 101,623 | 95,740 | 97,777 | 95,086 |
Per unit (diluted) (in dollars per share) | $ 0.16 | $ 0.24 | $ 0.86 | $ 0.26 |
Weighted average units outstanding (diluted) (in shares) | 101,623 | 96,011 | 97,777 | 95,619 |
Subordinated Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 5,017 | $ 13,105 | $ 51,379 | $ (1,293) |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.05 | $ 0.14 | $ 0.54 | $ (0.01) |
Weighted average units outstanding (basic) (in shares) | 95,388 | 95,189 | 95,269 | 95,125 |
Per unit (diluted) (in dollars per share) | $ 0.05 | $ 0.14 | $ 0.54 | $ (0.01) |
Weighted average units outstanding (diluted) (in shares) | 95,388 | 95,189 | 95,269 | 95,467 |
AT-THE-MARKET OFFERING PROGRAM
AT-THE-MARKET OFFERING PROGRAM (Details) - USD ($) shares in Millions | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | May 26, 2017 | |
Class of Stock [Line Items] | |||
Proceeds from sale of common units | $ 31,267,000 | $ 0 | |
Common Units | |||
Class of Stock [Line Items] | |||
Equity Distribution Agreement, maximum value | $ 100,000,000 | ||
Number of common units sold, units | 1.9 | ||
Proceeds from sale of common units | $ 31,300,000 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Details) - Subsequent Event | Nov. 06, 2017$ / shares |
Common Units | |
Subsequent Event [Line Items] | |
Quarterly cash distribution declared (in usd per unit) | $ 0.3125 |
Subordinated Units | |
Subsequent Event [Line Items] | |
Quarterly cash distribution declared (in usd per unit) | $ 0.20875 |