Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Aug. 01, 2018 | |
Document Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q2 | |
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) | 106,034,655 | |
Subordinated Units | ||
Document Information [Line Items] | ||
Entity Partnership Units Outstanding (in shares) | 96,328,836 | |
Preferred Units | ||
Document Information [Line Items] | ||
Entity Partnership Units Outstanding (in shares) | 14,711,219 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 7,071 | $ 5,642 |
Accounts receivable | 99,028 | 80,695 |
Commodity derivative assets | 0 | 94 |
Prepaid expenses and other current assets | 1,640 | 1,212 |
TOTAL CURRENT ASSETS | 107,739 | 87,643 |
PROPERTY AND EQUIPMENT | ||
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,041,363 and $988,720 at June 30, 2018 and December 31, 2017, respectively | 3,367,514 | 3,247,613 |
Accumulated depreciation, depletion, amortization, and impairment | (1,813,070) | (1,766,842) |
Oil and natural gas properties, net | 1,554,444 | 1,480,771 |
Other property and equipment, net of accumulated depreciation of $14,519 and $14,433 at June 30, 2018 and December 31, 2017, respectively | 468 | 559 |
NET PROPERTY AND EQUIPMENT | 1,554,912 | 1,481,330 |
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS | 6,813 | 7,478 |
TOTAL ASSETS | 1,669,464 | 1,576,451 |
CURRENT LIABILITIES | ||
Accounts payable | 2,952 | 2,464 |
Accrued liabilities | 52,576 | 52,631 |
Commodity derivative liabilities | 36,778 | 4,222 |
Other current liabilities | 391 | 417 |
TOTAL CURRENT LIABILITIES | 92,697 | 59,734 |
LONG–TERM LIABILITIES | ||
Credit facility | 421,000 | 388,000 |
Accrued incentive compensation | 3,202 | 3,648 |
Commodity derivative liabilities | 7,265 | 1,263 |
Asset retirement obligations | 14,589 | 14,092 |
Other long-term liabilities | 60,079 | 19,171 |
TOTAL LIABILITIES | 598,832 | 485,908 |
COMMITMENTS AND CONTINGENCIES (Note 8) | ||
EQUITY | ||
Partners' equity – general partner interest | 0 | 0 |
Noncontrolling interests | 731 | 867 |
TOTAL EQUITY | 772,271 | 768,121 |
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY | 1,669,464 | 1,576,451 |
Series A Redeemable Convertible Preferred Units | ||
MEZZANINE EQUITY | ||
Partners' equity – convertible preferred units | 0 | 27,028 |
Series B Cumulative Convertible Preferred Units | ||
MEZZANINE EQUITY | ||
Partners' equity – convertible preferred units | 298,361 | 295,394 |
Common Units | ||
EQUITY | ||
Partners' equity - units | 612,502 | 603,116 |
Subordinated Units | ||
EQUITY | ||
Partners' equity - units | $ 159,038 | $ 164,138 |
CONSOLIDATED BALANCE SHEETS (Un
CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) shares in Thousands, $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Oil and natural gas properties, unproved property costs | $ 1,041,363 | $ 988,720 |
Other property and equipment accumulated depreciation and amortization | $ 14,519 | $ 14,433 |
Series A Redeemable Convertible Preferred Units | ||
Partners' equity, preferred units, outstanding (in shares) | 0 | 26 |
Series B Cumulative Convertible Preferred Units | ||
Partners' equity, preferred units, outstanding (in shares) | 14,711 | 14,711 |
Common Units | ||
Partners' equity - units, outstanding (in shares) | 105,494 | 103,456 |
Subordinated Units | ||
Partners' equity - units, outstanding (in shares) | 96,329 | 95,388 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
REVENUE | ||||
Oil and condensate sales | $ 77,225 | $ 37,262 | $ 150,208 | $ 77,736 |
Natural gas and natural gas liquids sales | 53,854 | 49,903 | 107,099 | 97,604 |
Lease bonus and other income | 11,577 | 11,356 | 16,176 | 25,038 |
Revenue from contracts with customers | 142,656 | 98,521 | 273,483 | 200,378 |
Gain (loss) on commodity derivative instruments | (33,347) | 22,003 | (49,680) | 44,728 |
TOTAL REVENUE | 109,309 | 120,524 | 223,803 | 245,106 |
OPERATING (INCOME) EXPENSE | ||||
Lease operating expense | 4,290 | 4,148 | 8,538 | 8,337 |
Production costs and ad valorem taxes | 14,373 | 11,863 | 29,298 | 23,765 |
Exploration expense | 6,745 | 46 | 6,748 | 608 |
Depreciation, depletion, and amortization | 30,292 | 28,900 | 58,862 | 55,279 |
General and administrative | 19,812 | 17,481 | 38,333 | 34,693 |
Accretion of asset retirement obligations | 273 | 253 | 542 | 500 |
(Gain) loss on sale of assets, net | 0 | (7) | (2) | (931) |
TOTAL OPERATING EXPENSE | 75,785 | 62,684 | 142,319 | 122,251 |
INCOME (LOSS) FROM OPERATIONS | 33,524 | 57,840 | 81,484 | 122,855 |
OTHER INCOME (EXPENSE) | ||||
Interest and investment income | 37 | 33 | 70 | 39 |
Interest expense | (5,280) | (3,981) | (9,801) | (7,488) |
Other income (expense) | 409 | 282 | (1,106) | 351 |
TOTAL OTHER EXPENSE | (4,834) | (3,666) | (10,837) | (7,098) |
NET INCOME (LOSS) | 28,690 | 54,174 | 70,647 | 115,757 |
Net (income) loss attributable to noncontrolling interests | 48 | 16 | 22 | 7 |
Distributions on Series A redeemable preferred units | 0 | (672) | (25) | (1,786) |
Distributions on Series B cumulative convertible preferred units | (5,250) | 0 | (10,500) | 0 |
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | 23,488 | 53,518 | 60,144 | 113,978 |
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 | 23,488 | 53,518 | 60,144 | 113,978 |
Common Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 17,540 | $ 32,100 | $ 41,877 | $ 67,617 |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.17 | $ 0.33 | $ 0.40 | $ 0.69 |
Weighted average units outstanding (basic) (in shares) | 105,250 | 97,990 | 104,516 | 97,448 |
Per unit (diluted) (in dollars per share) | $ 0.17 | $ 0.33 | $ 0.40 | $ 0.69 |
Weighted average units outstanding (diluted) (in shares) | 105,250 | 97,990 | 104,516 | 97,448 |
DISTRIBUTIONS DECLARED AND PAID: | ||||
Per unit (in dollars per share) | $ 0.3125 | $ 0.2875 | $ 0.6250 | $ 0.5750 |
Subordinated Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 5,948 | $ 21,418 | $ 18,267 | $ 46,361 |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.06 | $ 0.22 | $ 0.19 | $ 0.49 |
Weighted average units outstanding (basic) (in shares) | 96,329 | 95,388 | 95,864 | 95,269 |
Per unit (diluted) (in dollars per share) | $ 0.06 | $ 0.22 | $ 0.19 | $ 0.49 |
Weighted average units outstanding (diluted) (in shares) | 96,329 | 95,388 | 95,864 | 95,269 |
DISTRIBUTIONS DECLARED AND PAID: | ||||
Per unit (in dollars per share) | $ 0.2087 | $ 0.1838 | $ 0.4175 | $ 0.3675 |
CONSOLIDATED STATEMENT OF EQUIT
CONSOLIDATED STATEMENT OF EQUITY - 6 months ended Jun. 30, 2018 - USD ($) shares in Thousands, $ in Thousands | Total | Noncontrolling interests | Common Units | Subordinated Units | Partners' equity — common units | Partners' equity — subordinated units | Series B Preferred Units | Series B Preferred UnitsPartners' equity — common units |
Beginning balance (in shares) at Dec. 31, 2017 | 103,456 | 95,388 | ||||||
Beginning balance at Dec. 31, 2017 | $ 768,121 | $ 867 | $ 603,116 | $ 164,138 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Conversion of Series A redeemable preferred units (in shares) | 736 | 964 | ||||||
Conversion of Series A redeemable preferred units | 24,248 | 10,498 | 13,750 | |||||
Repurchases of common and subordinated units (in shares) | (486) | (23) | ||||||
Repurchases of common and subordinated units | (9,071) | (8,729) | (342) | |||||
Issuance of common units, net of offering costs (in shares) | 517 | |||||||
Issuance of common units, net of offering costs | 9,067 | 9,067 | ||||||
Restricted units granted, net of forfeitures, units | 1,271 | |||||||
Equity–based compensation | 26,815 | 23,569 | 3,246 | |||||
Distributions | (105,727) | (114) | (65,592) | (40,021) | ||||
Charges to partners' equity for accrued distribution equivalent rights | (1,304) | (1,304) | ||||||
Distributions on preferred units | (25) | (13) | (12) | $ (10,500) | $ (10,500) | |||
Net income (loss) | 70,647 | (22) | 52,390 | 18,279 | ||||
Ending balance (in shares) at Jun. 30, 2018 | 105,494 | 96,329 | ||||||
Ending balance at Jun. 30, 2018 | $ 772,271 | $ 731 | $ 612,502 | $ 159,038 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income (loss) | $ 70,647 | $ 115,757 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation, depletion, and amortization | 58,862 | 55,279 |
Accretion of asset retirement obligations | 542 | 500 |
Amortization of deferred charges | 422 | 436 |
(Gain) loss on commodity derivative instruments | 49,680 | (44,728) |
Net cash (paid) received on settlement of commodity derivative instruments | (10,665) | 7,359 |
Equity-based compensation | 15,350 | 10,939 |
Exploratory dry hole expense | 6,743 | 0 |
Deferred rent | 321 | 0 |
(Gain) loss on sale of assets, net | (2) | (931) |
Changes in operating assets and liabilities: | ||
Accounts receivable | (17,915) | (4,318) |
Prepaid expenses and other current assets | (428) | (729) |
Accounts payable, accrued liabilities, and other | 2,826 | (311) |
Settlement of asset retirement obligations | (57) | (89) |
NET CASH PROVIDED BY OPERATING ACTIVITIES | 176,326 | 139,164 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Acquisitions of oil and natural gas properties | (56,069) | (66,501) |
Additions to oil and natural gas properties | (73,675) | (32,083) |
Additions to oil and natural gas properties leasehold costs | (3,799) | (1,820) |
Purchases of other property and equipment | (5) | (96) |
Proceeds from the sale of oil and natural gas properties | 1,255 | 2,133 |
Proceeds from farmouts of oil and natural gas properties | 41,034 | 0 |
NET CASH USED IN INVESTING ACTIVITIES | (91,259) | (98,367) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Proceeds from issuance of common units, net of offering costs | 9,067 | 991 |
Distributions to noncontrolling interests | (114) | (66) |
Redemptions of Series A redeemable preferred units | (2,115) | (19,641) |
Borrowings under credit facility | 175,000 | 159,500 |
Repayments under credit facility | (142,000) | (82,500) |
Debt issuance costs and other | (755) | (50) |
NET CASH USED IN FINANCING ACTIVITIES | (83,638) | (43,082) |
NET CHANGE IN CASH AND CASH EQUIVALENTS | 1,429 | (2,285) |
CASH AND CASH EQUIVALENTS – beginning of the period | 5,642 | 9,772 |
CASH AND CASH EQUIVALENTS – end of the period | 7,071 | 7,487 |
SUPPLEMENTAL DISCLOSURE | ||
Interest paid | 9,364 | 7,062 |
Common and Subordinated Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions to unitholders | (105,785) | (91,019) |
Repurchases of common and subordinated units | (9,071) | (7,845) |
Preferred Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions to unitholders | (690) | (2,452) |
Series B Preferred Units | Preferred Units | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Distributions to unitholders | $ (7,175) | $ 0 |
Business and Basis of Presentat
Business and Basis of Presentation | 6 Months Ended |
Jun. 30, 2018 | |
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, as defined in Note 7 – 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 ("U.S."). 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 Series A redeemable 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 June 30, 2018 , the Partnership’s mineral and royalty interests were located in 41 states and 64 onshore oil and natural gas producing basins of the continental U.S., 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 2017 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. The results of operations for the six months ended June 30, 2018 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all 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. 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. 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 unaudited interim 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 unaudited interim 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 | 6 Months Ended |
Jun. 30, 2018 | |
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, 2017 . There have been no changes in such policies or the application of such policies during the six months ended June 30, 2018 , with the exception of ASC 606, as defined below. Accounts Receivable The following table presents information about the Partnership's accounts receivable: June 30, 2018 December 31, 2017 (in thousands) Accounts receivable: Revenues from contracts with customers $ 94,981 $ 77,544 Other 4,047 3,151 Total accounts receivable $ 99,028 $ 80,695 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 supersedes Accounting Standards Codification ("ASC") 605, Revenue Recognition . Under the new standard, entities are required to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services, which may require more judgment than under previous U.S. GAAP. See Note 3 – Impact of ASC 606 Adoption for further details related to the Partnership’s adoption of this standard. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which will supersede the lease requirements in Topic 840, Leases by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet. The new lease 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 FASB recently issued ASU 2018-11, Leases (Topic 842), Targeted Improvements , which would allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the consolidated financial statements, and will also allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative catch-up adjustment in the period of adoption rather than in the earliest period presented. The Partnership plans to use a modified retrospective transition method to apply the new standard to leases that exist or are entered into after the adoption date of January 1, 2019. The Partnership does not plan to early adopt. Based on evaluations to-date, the new guidance will not have a material impact on the Partnership's 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. |
Impact of ASC 606 Adoption
Impact of ASC 606 Adoption | 6 Months Ended |
Jun. 30, 2018 | |
Revenue Recognition and Deferred Revenue [Abstract] | |
Impact of ASC 606 Adoption | IMPACT OF ASC 606 ADOPTION ASC 606, Revenue from Contracts with Customers , requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018 . Revenues from Contracts with Customers Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606. Lease bonus and other income The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment. Production imbalances The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018 , these amounts were de minimis. As such, upon adoption of ASC 606, there was no material impact to the financial statements due to this change in accounting for the Partnership's production imbalances. Allocation of transaction price to remaining performance obligations Oil and natural gas sales The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Lease bonus and other income Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the three and six months ended June 30, 2018 , revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial. |
Oil and Natural Gas Properties
Oil and Natural Gas Properties Acquisitions | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Oil and Natural Gas Properties Acquisitions | OIL AND NATURAL GAS PROPERTIES ACQUISITIONS 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. 2018 Acquisitions During the six months ended June 30, 2018 , the Partnership closed on multiple acquisitions of mineral and royalty interests, which also included proved oil and natural gas properties, in the Permian Basin. The following table summarizes the acquisitions which were considered business combinations: Assets Acquired Cash Consideration Paid Proved Unproved Net Working Capital Total Fair Value (in thousands) March 2018 $ 984 $ 21,452 $ 133 $ 22,569 $ 22,569 June 2018 883 13,688 8 14,579 14,579 Total fair value $ 1,867 $ 35,140 $ 141 $ 37,148 $ 37,148 In addition, the Partnership acquired mineral and royalty interests in unproved oil and natural gas properties in East Texas from various sellers for $21.5 million in cash. All 2018 acquisitions were funded via borrowings under the Partnership's Credit Facility as well as funds from operating activities. Noble Acquisition On November 28, 2017 (the "Close Date"), BSMC closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition." The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan (the "Noble Assets") include approximately 1.1 million gross ( 140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota. The Partnership funded the $335.0 million purchase price (before customary post-closing adjustments) using (i) approximately $300.0 million in proceeds from its issuance of 14,711,219 Series B cumulative convertible preferred units to Mineral Royalties One, L.L.C., an affiliate of The Carlyle Group (the "Purchaser"), in a private placement which also closed on November 28, 2017, and (ii) approximately $35.0 million from borrowings under its Credit Facility. See additional discussion of the Series B cumulative convertible preferred units in Note 10 – Preferred Units. The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value remains preliminary and will be completed after post-closing purchase price adjustments are finalized, but in no case later than one year from the acquisition date. Since December 31, 2017, the Partnership has recorded an adjustment to the purchase price to reduce the amount allocated to unproved properties by $2.6 million , which reduces the Acquisitions of oil and natural gas properties line item of the consolidated statement of cash flows for the six months ended June 30, 2018 . The following table summarizes the adjusted allocation of the fair value of the assets acquired and the acquisition-related costs as of June 30, 2018 : Assets Acquired Cash Consideration Paid 1 Acquisition-Related Costs 2 Proved Unproved Net Working Capital Total Fair Value (in thousands) Noble Assets $ 68,877 $ 257,154 $ 5,917 $ 331,948 $ 331,948 $ 247 1 Represents cash consideration paid on the Close Date, as adjusted for the $2.6 million purchase price adjustment recorded during the six months ended June 30, 2018 . 2 Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017. The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future commodity prices; (iii) estimated future cash flows; and (iv) market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change. Actual and Pro Forma Impact of Noble Acquisition (Unaudited) Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statements of operations for the three and six months ended June 30, 2018 was $12.7 million and $22.8 million , respectively. The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2017. Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 (in thousands, except per unit amounts) Revenue and other income $ 129,768 $ 264,089 Net income 59,402 126,726 Net income attributable to noncontrolling interests 16 7 Distributions on Series A redeemable preferred units (672 ) (1,786 ) Distributions on Series B cumulative convertible preferred units (5,250 ) (10,500 ) Net income attributable to the general partner and common and subordinated units $ 53,496 $ 114,447 Allocation of net income: General partner interest $ — $ — Common units 32,081 67,854 Subordinated units 21,415 46,593 $ 53,496 $ 114,447 Net income attributable to limited partners per common and subordinated unit: Per common unit (basic) $ 0.33 $ 0.70 Per subordinated unit (basic) $ 0.22 $ 0.49 Per common unit (diluted) $ 0.33 $ 0.70 Per subordinated unit (diluted) $ 0.22 $ 0.49 The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Noble Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Partnership's consolidated results of operations would have been had the acquisition been completed on January 1, 2017. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined company. The unaudited pro forma consolidated results reflect the following pro forma adjustments for the periods presented: • Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets. • Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility. • Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units. • The Series B cumulative convertible preferred units were not included in the calculation of pro forma diluted earnings per common unit for the three months ended June 30, 2017 as they were anti-dilutive under the if-converted method. • The Series B cumulative convertible preferred units were included in the calculation of pro forma diluted earnings per common unit for the six months ended June 30, 2017 due to their dilutive effect under the if-converted method. • The Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit. 2017 Acquisitions In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests during the year ended December 31, 2017, which also included proved oil and natural gas properties, as reflected in the table below. These acquisitions were considered business combinations and were primarily focused in the Delaware Basin and East Texas. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility. Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued Acquisition-Related Costs 1 (in thousands) January $ 5,135 $ 34,008 $ 263 $ 39,406 $ 27,380 $ 12,026 $ 1,162 June 5,006 45,477 — 50,483 4,802 45,681 1,481 August 3,277 9,984 — 13,261 4,289 8,972 107 September 3,120 — — 3,120 3,120 — — Total fair value $ 16,538 $ 89,469 $ 263 $ 106,270 $ 39,591 $ 66,679 $ 2,750 1 Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017. Additionally, the Partnership acquired mineral and royalty interests in unproved oil and natural gas properties in East Texas from various sellers for $56.7 million during the year ended December 31, 2017. The cash portion of these acquisitions of $51.7 million was funded via borrowings under the Partnership's Credit Facility, with an additional $5.0 million funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates. Farmout Agreements 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/Bossier 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. At its option, during the first three phases of the agreement, Canaan can commit on a phase-by-phase basis to fund a portion of the Partnership's drilling and completion costs to earn a percentage of the Partnership's working interest in wells drilled and completed during each phase. After the third phase, Canaan can earn a percentage of the Partnership's working interest in additional wells drilled in the area by committing on a well-by-well basis to fund a portion of the Partnership's costs for each well. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. Since the inception of the agreement, the Partnership has received $41.3 million from Canaan under the agreement. All amounts received are included in the Long-term liabilities – other long-term liabilities line item of the June 30, 2018 consolidated balance sheet, as no working interest had been assigned to Canaan as of that date. Pivotal Farmout On November 21, 2017, the Partnership entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas targeting its Haynesville/Bossier acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining working interest not covered by the Canaan Farmout, as well as the Partnership's working interests in wells operated by its other major operator in the area. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells. Since the inception of the agreement, the Partnership has received $18.9 million from Pivotal under the agreement. As of June 30, 2018 , the Partnership had assigned to Pivotal working interests in wells drilled and completed during the initial phase, and as such, $16.8 million is included in the Long-term liabilities – other long-term liabilities line item of the consolidated balance sheet. As of December 31, 2017 , all amounts received from Canaan and Pivotal under the agreements were included in the Long-term liabilities – other long-term liabilities line item of the consolidated balance sheet, as no working interest had been assigned to Canaan or Pivotal as of that date. |
Commodity Derivative Financial
Commodity Derivative Financial Instruments | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Commodity Derivatives And Financial Instruments | COMMODITY DERIVATIVE 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 variable-to-fixed-price swaps, costless collars, fixed-price contracts 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 June 30, 2018 , the Partnership’s open derivative contracts consisted of fixed-price swap contracts and costless collar contracts. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. A costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling 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 June 30, 2018 and December 31, 2017 . See Note 6 – Fair Value Measurements 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 June 30, 2018 , the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Eight of the Partnership's counterparties are lenders under the Credit Facility. The Partnership would have been at risk of losing a fair value amount of $6.6 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of June 30, 2018 . The tables below summarize the fair values and classifications of the Partnership’s derivative instruments as of each date: June 30, 2018 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 1,815 $ (1,815 ) $ — Long-term asset Deferred charges and other long-term assets 4,799 (4,799 ) — Total assets $ 6,614 $ (6,614 ) $ — Liabilities: Current liability Commodity derivative liabilities $ 38,593 $ (1,815 ) $ 36,778 Long-term liability Commodity derivative liabilities 12,064 (4,799 ) 7,265 Total liabilities $ 50,657 $ (6,614 ) $ 44,043 December 31, 2017 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 10,713 $ (10,619 ) $ 94 Long-term asset Deferred charges and other long-term assets 1,392 (1,029 ) 363 Total assets $ 12,105 $ (11,648 ) $ 457 Liabilities: Current liability Commodity derivative liabilities $ 14,841 $ (10,619 ) $ 4,222 Long-term liability Commodity derivative liabilities 2,292 (1,029 ) 1,263 Total liabilities $ 17,133 $ (11,648 ) $ 5,485 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 and are as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, Derivatives not designated as hedging instruments 2018 2017 2018 2017 Beginning fair value of commodity derivative instruments $ (16,986 ) $ 1,728 $ (5,028 ) $ (16,719 ) Gain (loss) on oil derivative instruments (30,018 ) 13,494 (44,494 ) 27,799 Gain (loss) on natural gas derivative instruments (3,329 ) 8,509 (5,186 ) 16,929 Net cash paid (received) on settlements of oil derivative instruments 9,380 (3,847 ) 14,528 (6,656 ) Net cash paid (received) on settlements of natural gas derivative instruments (3,090 ) 766 (3,863 ) (703 ) Net change in fair value of commodity derivative instruments (27,057 ) 18,922 (39,015 ) 37,369 Ending fair value of commodity derivative instruments $ (44,043 ) $ 20,650 $ (44,043 ) $ 20,650 The Partnership had the following open derivative contracts for oil as of June 30, 2018 : Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2018 Second Quarter 281,000 $ 55.27 $ 52.09 $ 61.88 Third Quarter 849,000 55.28 51.85 61.88 Fourth Quarter 854,000 55.18 51.85 61.88 2019 First Quarter 645,000 $ 58.66 $ 52.82 $ 65.58 Second Quarter 645,000 58.66 52.82 65.58 Third Quarter 645,000 58.20 52.82 63.75 Fourth Quarter 645,000 58.20 52.82 63.75 Weighted Average Floor Price (Per Bbl) Weighted Average Ceiling Price (Per Bbl) Period and Type of Contract Volume (Bbl) Oil Collar Contracts: 2020 First Quarter 150,000 $ 55.00 $ 65.75 Second Quarter 150,000 55.00 65.75 Third Quarter 150,000 55.00 65.75 Fourth Quarter 150,000 55.00 65.75 The Partnership had the following open derivative contracts for natural gas as of June 30, 2018 : Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2018 Third Quarter 13,600,000 $ 3.01 $ 2.90 $ 3.23 Fourth Quarter 13,630,000 3.01 2.90 3.23 2019 First Quarter 7,200,000 $ 2.86 $ 2.81 $ 2.93 Second Quarter 7,240,000 2.86 2.81 2.93 Third Quarter 7,280,000 2.86 2.81 2.93 Fourth Quarter 7,280,000 2.86 2.81 2.93 |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS 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, Fair Value Measurement , 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 six months ended June 30, 2018 or the year ended December 31, 2017 . 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 June 30, 2018 and December 31, 2017 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 – Commodity Derivative 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 Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of June 30, 2018 Financial Assets Commodity derivative instruments $ — $ 6,614 $ — $ (6,614 ) $ — Financial Liabilities Commodity derivative instruments $ — $ 50,657 $ — $ (6,614 ) $ 44,043 As of December 31, 2017 Financial Assets Commodity derivative instruments $ — $ 12,105 $ — $ (11,648 ) $ 457 Financial Liabilities Commodity derivative instruments $ — $ 17,133 $ — $ (11,648 ) $ 5,485 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 – Oil and Natural Gas Properties Acquisitions. 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 proved reserves, future commodity prices, timing of future production, future capital expenditures, 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 June 30, 2018 or December 31, 2017 . There were no assets measured at fair value on a nonrecurring basis, after initial recognition, for the three and six months ended June 30, 2018 and 2017. |
Credit Facility
Credit Facility | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Credit Facility | CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility 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. The borrowing base is redetermined semi-annually, usually in October and April. Effective April 25, 2017, the borrowing base redetermination increased the borrowing base from $500.0 million to $550.0 million . On November 1, 2017, the Partnership amended and restated the credit agreement to create a swingline facility that permits short-term borrowings on same-day notice, make other changes to the hedging and restrictive covenants, and extend the maturity for a term of five years, which terminates on November 1, 2022. Effective May 4, 2018, the borrowing base was increased to $600.0 million . Borrowings under the Credit Facility bear 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 Credit Facility was 4.60% and 4.06% as of June 30, 2018 and December 31, 2017 , 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 Credit Facility is secured by substantially all of the Partnership’s producing properties. The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility 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 June 30, 2018 , the Partnership was in compliance with all financial covenants in the Credit Facility. The aggregate principal balance outstanding was $421.0 million and $388.0 million at June 30, 2018 and December 31, 2017 , respectively. The unused portion of the available borrowings under the Credit Facility was $179.0 million and $162.0 million at June 30, 2018 and December 31, 2017 , respectively. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
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. Put Option Related to Noble Acquisition By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, the Partnership acquired a 100% interest in Comin-Temin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of June 30, 2018 , the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded. 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 June 30, 2018 will be resolved without material adverse effect on the Partnership’s financial condition or operations. |
Incentive Compensation
Incentive Compensation | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Incentive Compensation | INCENTIVE COMPENSATION The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three and six months ended June 30, 2018 and 2017 : Three Months Ended Six Months Ended 2018 2017 2018 2017 (in thousands) Cash—long-term incentive plan $ 855 $ 214 $ 1,673 $ 636 Equity-based compensation—restricted common and subordinated units 3,371 2,940 6,776 4,748 Equity-based compensation—restricted performance units 5,173 2,723 7,415 5,076 Board of Directors incentive plan 581 614 1,160 1,114 Total incentive compensation expense $ 9,980 $ 6,491 $ 17,024 $ 11,574 |
Preferred Units
Preferred Units | 6 Months Ended |
Jun. 30, 2018 | |
Equity [Abstract] | |
Redeemable Preferred Units | PREFERRED UNITS Series A Redeemable Preferred Units As of June 30, 2018 , there were no Series A redeemable preferred units outstanding, while as of December 31, 2017 there were 26,363 Series A redeemable preferred units outstanding with a carrying value of $27.0 million . This carrying value included accrued distributions of $0.7 million . The Series A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption was outside the control of the Partnership. The Series A redeemable preferred units were entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears. The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units had 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. For the year ended December 31, 2017 , 19,704 Series A redeemable preferred units were redeemed for $20.2 million , including accrued unpaid yield. For the year ended December 31, 2017 , 6,624 Series A 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. The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017 , plus any accrued and unpaid distributions. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. For the six months ended June 30, 2018 , 2,115 Series A redeemable preferred units were redeemed for $2.1 million , including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017 . Series B Cumulative Convertible Preferred Units On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the Purchaser for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million . The Series B cumulative convertible preferred units are entitled to an annual distribution of 7% , payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926 . The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarter thereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926 , adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Series B cumulative convertible preferred units had a carrying value of $298.4 million and $295.4 million , including accrued distributions of $5.3 million and $1.9 million , as of June 30, 2018 and December 31, 2017 , respectively. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership. |
Earnings Per Unit
Earnings Per Unit | 6 Months Ended |
Jun. 30, 2018 | |
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 Series B cumulative convertible preferred units could be converted into approximately 15.0 million common units as of June 30, 2018 . At June 30, 2018 , if the outstanding Series B cumulative convertible preferred units were converted to common units, the effect would be anti-dilutive; therefore, they are not included in the calculation of diluted EPU for the three and six months ended June 30, 2018. 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 June 30, 2018 , 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: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 28,690 $ 54,174 $ 70,647 $ 115,757 Net (income) loss attributable to noncontrolling interests 48 16 22 7 Distributions on Series A redeemable preferred units — (672 ) (25 ) (1,786 ) Distributions on Series B cumulative convertible preferred units (5,250 ) — $ (10,500 ) $ — NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 23,488 $ 53,518 $ 60,144 $ 113,978 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 17,540 32,100 41,877 67,617 Subordinated units 5,948 21,418 18,267 46,361 $ 23,488 $ 53,518 $ 60,144 $ 113,978 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 0.17 $ 0.33 $ 0.40 $ 0.69 Weighted average common units outstanding (basic) 105,250 97,990 104,516 97,448 Per subordinated unit (basic) $ 0.06 $ 0.22 $ 0.19 $ 0.49 Weighted average subordinated units outstanding (basic) 96,329 95,388 95,864 95,269 Per common unit (diluted) $ 0.17 $ 0.33 $ 0.40 $ 0.69 Weighted average common units outstanding (diluted) 105,250 97,990 104,516 97,448 Per subordinated unit (diluted) $ 0.06 $ 0.22 $ 0.19 $ 0.49 Weighted average subordinated units outstanding (diluted) 96,329 95,388 95,864 95,269 |
At-The-Market Offering Program
At-The-Market Offering Program | 6 Months Ended |
Jun. 30, 2018 | |
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 amount 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 SEC 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. For the six months ended June 30, 2018 , the Partnership sold 516,639 common units under the ATM Program for net proceeds of $9.1 million . |
Subsequent Events
Subsequent Events | 6 Months Ended |
Jun. 30, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS On July 6, 2018, the Partnership closed on an acquisition of mineral and royalty interests, which also included proved oil and natural gas properties, for approximately $10.8 million , consisting of cash of approximately $2.1 million and common units issued with a fair value of approximately $8.7 million based on the Partnership's common unit price on the closing date. The acquisition was accounted for as a business combination. On August 6, 2018 , the Board of Directors of the Partnership's general partner approved a distribution for the three months ended June 30, 2018 of $0.3375 per common unit and $0.3375 per subordinated unit. Distributions will be payable on August 23, 2018 to unitholders of record at the close of business on August 16, 2018 . |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
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 2017 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. The results of operations for the six months ended June 30, 2018 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all 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. 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. 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 unaudited interim 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 unaudited interim 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 supersedes Accounting Standards Codification ("ASC") 605, Revenue Recognition . Under the new standard, entities are required to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services, which may require more judgment than under previous U.S. GAAP. See Note 3 – Impact of ASC 606 Adoption for further details related to the Partnership’s adoption of this standard. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which will supersede the lease requirements in Topic 840, Leases by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet. The new lease 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 FASB recently issued ASU 2018-11, Leases (Topic 842), Targeted Improvements , which would allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the consolidated financial statements, and will also allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative catch-up adjustment in the period of adoption rather than in the earliest period presented. The Partnership plans to use a modified retrospective transition method to apply the new standard to leases that exist or are entered into after the adoption date of January 1, 2019. The Partnership does not plan to early adopt. Based on evaluations to-date, the new guidance will not have a material impact on the Partnership's 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. |
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. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies - (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Accounting Policies [Abstract] | |
Schedule of Accounts Receivable | The following table presents information about the Partnership's accounts receivable: June 30, 2018 December 31, 2017 (in thousands) Accounts receivable: Revenues from contracts with customers $ 94,981 $ 77,544 Other 4,047 3,151 Total accounts receivable $ 99,028 $ 80,695 |
Oil and Natural Gas Propertie22
Oil and Natural Gas Properties Acquisitions (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Schedule of Fair Values of the Properties Acquired | Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash Fair Value of Common Units Issued Acquisition-Related Costs 1 (in thousands) January $ 5,135 $ 34,008 $ 263 $ 39,406 $ 27,380 $ 12,026 $ 1,162 June 5,006 45,477 — 50,483 4,802 45,681 1,481 August 3,277 9,984 — 13,261 4,289 8,972 107 September 3,120 — — 3,120 3,120 — — Total fair value $ 16,538 $ 89,469 $ 263 $ 106,270 $ 39,591 $ 66,679 $ 2,750 1 Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017. The following table summarizes the acquisitions which were considered business combinations: Assets Acquired Cash Consideration Paid Proved Unproved Net Working Capital Total Fair Value (in thousands) March 2018 $ 984 $ 21,452 $ 133 $ 22,569 $ 22,569 June 2018 883 13,688 8 14,579 14,579 Total fair value $ 1,867 $ 35,140 $ 141 $ 37,148 $ 37,148 The following table summarizes the adjusted allocation of the fair value of the assets acquired and the acquisition-related costs as of June 30, 2018 : Assets Acquired Cash Consideration Paid 1 Acquisition-Related Costs 2 Proved Unproved Net Working Capital Total Fair Value (in thousands) Noble Assets $ 68,877 $ 257,154 $ 5,917 $ 331,948 $ 331,948 $ 247 1 Represents cash consideration paid on the Close Date, as adjusted for the $2.6 million purchase price adjustment recorded during the six months ended June 30, 2018 . 2 Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017 |
Schedule of Pro Forma Information From Business Acquisition | The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2017. Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 (in thousands, except per unit amounts) Revenue and other income $ 129,768 $ 264,089 Net income 59,402 126,726 Net income attributable to noncontrolling interests 16 7 Distributions on Series A redeemable preferred units (672 ) (1,786 ) Distributions on Series B cumulative convertible preferred units (5,250 ) (10,500 ) Net income attributable to the general partner and common and subordinated units $ 53,496 $ 114,447 Allocation of net income: General partner interest $ — $ — Common units 32,081 67,854 Subordinated units 21,415 46,593 $ 53,496 $ 114,447 Net income attributable to limited partners per common and subordinated unit: Per common unit (basic) $ 0.33 $ 0.70 Per subordinated unit (basic) $ 0.22 $ 0.49 Per common unit (diluted) $ 0.33 $ 0.70 Per subordinated unit (diluted) $ 0.22 $ 0.49 |
Commodity Derivative Financia23
Commodity Derivative Financial Instruments (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Derivative [Line Items] | |
Summary of Fair Value and Classification of Derivative Instruments | The tables below summarize the fair values and classifications of the Partnership’s derivative instruments as of each date: June 30, 2018 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 1,815 $ (1,815 ) $ — Long-term asset Deferred charges and other long-term assets 4,799 (4,799 ) — Total assets $ 6,614 $ (6,614 ) $ — Liabilities: Current liability Commodity derivative liabilities $ 38,593 $ (1,815 ) $ 36,778 Long-term liability Commodity derivative liabilities 12,064 (4,799 ) 7,265 Total liabilities $ 50,657 $ (6,614 ) $ 44,043 December 31, 2017 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 10,713 $ (10,619 ) $ 94 Long-term asset Deferred charges and other long-term assets 1,392 (1,029 ) 363 Total assets $ 12,105 $ (11,648 ) $ 457 Liabilities: Current liability Commodity derivative liabilities $ 14,841 $ (10,619 ) $ 4,222 Long-term liability Commodity derivative liabilities 2,292 (1,029 ) 1,263 Total liabilities $ 17,133 $ (11,648 ) $ 5,485 |
Changes in Fair Value of Company's Commodity Derivative Instruments | 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 and are as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, Derivatives not designated as hedging instruments 2018 2017 2018 2017 Beginning fair value of commodity derivative instruments $ (16,986 ) $ 1,728 $ (5,028 ) $ (16,719 ) Gain (loss) on oil derivative instruments (30,018 ) 13,494 (44,494 ) 27,799 Gain (loss) on natural gas derivative instruments (3,329 ) 8,509 (5,186 ) 16,929 Net cash paid (received) on settlements of oil derivative instruments 9,380 (3,847 ) 14,528 (6,656 ) Net cash paid (received) on settlements of natural gas derivative instruments (3,090 ) 766 (3,863 ) (703 ) Net change in fair value of commodity derivative instruments (27,057 ) 18,922 (39,015 ) 37,369 Ending fair value of commodity derivative instruments $ (44,043 ) $ 20,650 $ (44,043 ) $ 20,650 |
Oil and Natural Gas | |
Derivative [Line Items] | |
Summary of Open Derivative Contracts | The Partnership had the following open derivative contracts for oil as of June 30, 2018 : Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2018 Second Quarter 281,000 $ 55.27 $ 52.09 $ 61.88 Third Quarter 849,000 55.28 51.85 61.88 Fourth Quarter 854,000 55.18 51.85 61.88 2019 First Quarter 645,000 $ 58.66 $ 52.82 $ 65.58 Second Quarter 645,000 58.66 52.82 65.58 Third Quarter 645,000 58.20 52.82 63.75 Fourth Quarter 645,000 58.20 52.82 63.75 Weighted Average Floor Price (Per Bbl) Weighted Average Ceiling Price (Per Bbl) Period and Type of Contract Volume (Bbl) Oil Collar Contracts: 2020 First Quarter 150,000 $ 55.00 $ 65.75 Second Quarter 150,000 55.00 65.75 Third Quarter 150,000 55.00 65.75 Fourth Quarter 150,000 55.00 65.75 The Partnership had the following open derivative contracts for natural gas as of June 30, 2018 : Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2018 Third Quarter 13,600,000 $ 3.01 $ 2.90 $ 3.23 Fourth Quarter 13,630,000 3.01 2.90 3.23 2019 First Quarter 7,200,000 $ 2.86 $ 2.81 $ 2.93 Second Quarter 7,240,000 2.86 2.81 2.93 Third Quarter 7,280,000 2.86 2.81 2.93 Fourth Quarter 7,280,000 2.86 2.81 2.93 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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 Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of June 30, 2018 Financial Assets Commodity derivative instruments $ — $ 6,614 $ — $ (6,614 ) $ — Financial Liabilities Commodity derivative instruments $ — $ 50,657 $ — $ (6,614 ) $ 44,043 As of December 31, 2017 Financial Assets Commodity derivative instruments $ — $ 12,105 $ — $ (11,648 ) $ 457 Financial Liabilities Commodity derivative instruments $ — $ 17,133 $ — $ (11,648 ) $ 5,485 |
Incentive Compensation (Tables)
Incentive Compensation (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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 six months ended June 30, 2018 and 2017 : Three Months Ended Six Months Ended 2018 2017 2018 2017 (in thousands) Cash—long-term incentive plan $ 855 $ 214 $ 1,673 $ 636 Equity-based compensation—restricted common and subordinated units 3,371 2,940 6,776 4,748 Equity-based compensation—restricted performance units 5,173 2,723 7,415 5,076 Board of Directors incentive plan 581 614 1,160 1,114 Total incentive compensation expense $ 9,980 $ 6,491 $ 17,024 $ 11,574 |
Earnings Per Unit (Tables)
Earnings Per Unit (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 28,690 $ 54,174 $ 70,647 $ 115,757 Net (income) loss attributable to noncontrolling interests 48 16 22 7 Distributions on Series A redeemable preferred units — (672 ) (25 ) (1,786 ) Distributions on Series B cumulative convertible preferred units (5,250 ) — $ (10,500 ) $ — NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 23,488 $ 53,518 $ 60,144 $ 113,978 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 17,540 32,100 41,877 67,617 Subordinated units 5,948 21,418 18,267 46,361 $ 23,488 $ 53,518 $ 60,144 $ 113,978 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 0.17 $ 0.33 $ 0.40 $ 0.69 Weighted average common units outstanding (basic) 105,250 97,990 104,516 97,448 Per subordinated unit (basic) $ 0.06 $ 0.22 $ 0.19 $ 0.49 Weighted average subordinated units outstanding (basic) 96,329 95,388 95,864 95,269 Per common unit (diluted) $ 0.17 $ 0.33 $ 0.40 $ 0.69 Weighted average common units outstanding (diluted) 105,250 97,990 104,516 97,448 Per subordinated unit (diluted) $ 0.06 $ 0.22 $ 0.19 $ 0.49 Weighted average subordinated units outstanding (diluted) 96,329 95,388 95,864 95,269 |
Business and Basis of Present27
Business and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Millions | May 06, 2015USD ($)$ / sharesshares | Jun. 30, 2018basinstateshares |
Limited Partners Capital Account [Line Items] | ||
Cost basis, ownership percentage | 20.00% | |
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] | ||
Issuance of common units, net of offering costs (in shares) | 517,000 | |
Units exchanged in merger (in shares) | 72,574,715 | |
Capital units converted upon merger (in shares) | 736,000 | |
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, net of offering costs (in shares) | 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) | 964,000 | |
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] | ||
Capital units converted upon merger (in shares) | 117,963 |
Summary of Significant Accoun28
Summary of Significant Accounting Policies Accounts Receivable (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable | $ 99,028 | $ 80,695 |
Revenues from contracts with customers | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable | 94,981 | 77,544 |
Other | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable | $ 4,047 | $ 3,151 |
Oil and Natural Gas Propertie29
Oil and Natural Gas Properties Acquisitions - Schedule of Fair Values of the Properties Acquired (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Sep. 30, 2017 | Aug. 31, 2017 | Jun. 30, 2017 | Jan. 31, 2017 | Jun. 30, 2018 | Dec. 31, 2017 | Jun. 29, 2018 |
Permian Basin | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proved | $ 883 | $ 984 | $ 1,867 | |||||||
Unproved | 13,688 | 21,452 | 35,140 | |||||||
Net Working Capital | 8 | 133 | 141 | |||||||
Total Fair Value | 14,579 | 22,569 | 37,148 | |||||||
Cash Consideration Paid | $ 37,148 | 37,148 | $ 22,569 | 37,148 | $ 14,579 | |||||
East Texas | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Total Fair Value | $ 56,700 | |||||||||
Noble Acquisition | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proved | 68,877 | |||||||||
Unproved | 257,154 | |||||||||
Net Working Capital | 5,917 | |||||||||
Total Fair Value | 331,948 | |||||||||
Cash Consideration Paid | 331,948 | $ 331,948 | $ 331,948 | |||||||
Acquisition-Related Costs | $ 247 | |||||||||
2017 Acquisitions | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proved | $ 3,120 | $ 3,277 | $ 5,006 | $ 5,135 | 16,538 | |||||
Unproved | 0 | 9,984 | 45,477 | 34,008 | 89,469 | |||||
Net Working Capital | 0 | 0 | 0 | 263 | 263 | |||||
Total Fair Value | 3,120 | 13,261 | 50,483 | 39,406 | 106,270 | |||||
Cash Consideration Paid | 3,120 | 4,289 | 4,802 | 27,380 | 39,591 | |||||
Acquisition-Related Costs | 0 | 107 | 1,481 | 1,162 | 2,750 | |||||
Fair Value of Common Units Issued | $ 0 | $ 8,972 | $ 45,681 | $ 12,026 | $ 66,679 |
Oil and Natural Gas Propertie30
Oil and Natural Gas Properties Acquisitions - Additional Information (Details) $ in Thousands | Jun. 30, 2018USD ($) | Nov. 28, 2017USD ($)astateshares | Nov. 21, 2017 | Feb. 21, 2017 | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Jun. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) |
Business Acquisition [Line Items] | |||||||||
Asset acquisition, purchase price allocation, subsequent years, adjustments | $ 2,600 | $ 2,600 | $ 2,600 | $ 2,600 | |||||
Issuance of common units, net of offering costs | 9,067 | ||||||||
Permian Basin | |||||||||
Business Acquisition [Line Items] | |||||||||
Costs incurred, acquisition of oil and gas properties | $ 14,579 | $ 22,569 | 37,148 | ||||||
East Texas | |||||||||
Business Acquisition [Line Items] | |||||||||
Payments to acquire oil, mineral, and royalty interests | 21,500 | $ 51,700 | |||||||
Costs incurred, acquisition of oil and gas properties | 56,700 | ||||||||
Angelina County, Texas | Farmout Agreement | |||||||||
Business Acquisition [Line Items] | |||||||||
Ownership interest, acreage, percent | 50.00% | ||||||||
Angelina County, Texas | Farmout Agreement | Canaan Resource Partners | |||||||||
Business Acquisition [Line Items] | |||||||||
Business combination, pro forma information, revenue of acquiree since acquisition date, actual | 41,300 | ||||||||
San Augustine County, Texas | Farmout Agreement | Pivotal | |||||||||
Business Acquisition [Line Items] | |||||||||
Term of phase (years) | 8 years | ||||||||
Business combination, pro forma information, revenue of acquiree since acquisition date, actual | 18,900 | ||||||||
Business combination, pro forma information, long-term liabilities of acquiree since acquisition date, actual | 16,800 | ||||||||
Series B Cumulative Convertible Preferred Units | |||||||||
Business Acquisition [Line Items] | |||||||||
Proceeds from issuance of convertible preferred stock | $ 300,000 | ||||||||
Partners' equity — common units | |||||||||
Business Acquisition [Line Items] | |||||||||
Issuance of common units, net of offering costs | 9,067 | ||||||||
Partners' equity — common units | East Texas | |||||||||
Business Acquisition [Line Items] | |||||||||
Issuance of common units, net of offering costs | $ 5,000 | ||||||||
Noble Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Number of states major onshore oil and natural gas basins located | state | 20 | ||||||||
Payments to acquire businesses, gross | $ 335,000 | ||||||||
Costs incurred, acquisition of oil and gas properties | $ 331,948 | ||||||||
Business combination, pro forma information, revenue of acquiree since acquisition date, actual | $ 12,700 | $ 22,800 | |||||||
Noble Acquisition | Series B Cumulative Convertible Preferred Units | |||||||||
Business Acquisition [Line Items] | |||||||||
Proceeds from issuance of convertible preferred stock | $ 300,000 | ||||||||
Number of shares issued (in shares) | shares | 14,711,219 | ||||||||
Revolving Credit Facility | Senior Line of Credit | Noble Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Long-term line of credit | $ 35,000 | ||||||||
Mining Properties and Mineral Rights | Noble Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Gas and oil area, developed, gross | a | 1,100,000 | ||||||||
Gas and oil area, developed, net | a | 140,000 | ||||||||
Non-participating Royalty Interest | Noble Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Gas and oil area, developed, gross | a | 380,000 | ||||||||
Overriding Royalty Interest | Noble Acquisition | |||||||||
Business Acquisition [Line Items] | |||||||||
Gas and oil area, developed, gross | a | 600,000 |
Oil and Natural Gas Propertie31
Oil and Natural Gas Properties Acquisitions - Pro Forma Information (Details) - Noble Acquisition - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended |
Jun. 30, 2017 | Jun. 30, 2017 | |
Business Acquisition [Line Items] | ||
Revenue and other income | $ 129,768 | $ 264,089 |
Net income | 59,402 | 126,726 |
Net income attributable to noncontrolling interests | 16 | 7 |
Distributions on Series A redeemable preferred units | (672) | (1,786) |
Distributions on Series B cumulative convertible preferred units | (5,250) | (10,500) |
Net income attributable to the general partner and common and subordinated units | 53,496 | 114,447 |
Allocation of net income: | ||
General partner interest | 0 | 0 |
Common Units | ||
Allocation of net income: | ||
Allocation of net income | $ 32,081 | $ 67,854 |
Net income attributable to limited partners per common and subordinated unit: | ||
Per unit (basic) (in usd per share) | $ 0.33 | $ 0.70 |
Per unit (diluted) (in usd per share) | $ 0.33 | $ 0.70 |
Subordinated Units | ||
Allocation of net income: | ||
Allocation of net income | $ 21,415 | $ 46,593 |
Net income attributable to limited partners per common and subordinated unit: | ||
Per unit (basic) (in usd per share) | $ 0.22 | $ 0.49 |
Per unit (diluted) (in usd per share) | $ 0.22 | $ 0.49 |
Commodity Derivative Financia32
Commodity Derivative Financial Instruments - Additional Information (Details) $ in Thousands | Jun. 30, 2018USD ($)counterparty | Dec. 31, 2017USD ($) |
Derivative [Line Items] | ||
Number of counterparties | 9 | |
Gross fair value amount | $ | $ 6,614 | $ 12,105 |
Senior Line of Credit | ||
Derivative [Line Items] | ||
Number of counterparties | 8 |
Commodity Derivative Financia33
Commodity Derivative Financial Instruments - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Derivatives Fair Value [Line Items] | ||
Gross fair value amount | $ 6,614 | $ 12,105 |
Effect of Counterparty Netting, Assets | (6,614) | (11,648) |
Total net carrying value on Balance Sheet, assets | 0 | 457 |
Gross Fair Value, Liabilities | 50,657 | 17,133 |
Effect of Counterparty Netting, Liabilities | (6,614) | (11,648) |
Total net carrying value on Balance Sheet, liabilities | 44,043 | 5,485 |
Commodity derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross fair value amount | 1,815 | 10,713 |
Effect of Counterparty Netting, Assets | (1,815) | (10,619) |
Total net carrying value on Balance Sheet, assets | 0 | 94 |
Deferred charges and other long-term assets | ||
Derivatives Fair Value [Line Items] | ||
Gross fair value amount | 4,799 | 1,392 |
Effect of Counterparty Netting, Assets | (4,799) | (1,029) |
Total net carrying value on Balance Sheet, assets | 0 | 363 |
Commodity derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Fair Value, Liabilities | 38,593 | 14,841 |
Effect of Counterparty Netting, Liabilities | (1,815) | (10,619) |
Total net carrying value on Balance Sheet, liabilities | 36,778 | 4,222 |
Commodity derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Fair Value, Liabilities | 12,064 | 2,292 |
Effect of Counterparty Netting, Liabilities | (4,799) | (1,029) |
Total net carrying value on Balance Sheet, liabilities | $ 7,265 | $ 1,263 |
Commodity Derivative Financia34
Commodity Derivative Financial Instruments - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Derivatives not designated as hedging instruments | ||||
Gain (loss) on commodity derivative instruments | $ (33,347) | $ 22,003 | $ (49,680) | $ 44,728 |
Net cash paid (received) on settlements of derivative instruments | 10,665 | (7,359) | ||
Not Designated as Hedging Instrument | ||||
Derivatives not designated as hedging instruments | ||||
Beginning fair value of commodity derivative instruments | (16,986) | 1,728 | (5,028) | (16,719) |
Net change in fair value of commodity derivative instruments | (27,057) | 18,922 | (39,015) | 37,369 |
Ending fair value of commodity derivative instruments | (44,043) | 20,650 | (44,043) | 20,650 |
Not Designated as Hedging Instrument | Oil | ||||
Derivatives not designated as hedging instruments | ||||
Gain (loss) on commodity derivative instruments | (30,018) | 13,494 | (44,494) | 27,799 |
Net cash paid (received) on settlements of derivative instruments | 9,380 | (3,847) | 14,528 | (6,656) |
Not Designated as Hedging Instrument | Natural Gas | ||||
Derivatives not designated as hedging instruments | ||||
Gain (loss) on commodity derivative instruments | (3,329) | 8,509 | (5,186) | 16,929 |
Net cash paid (received) on settlements of derivative instruments | $ (3,090) | $ 766 | $ (3,863) | $ (703) |
Commodity Derivative Financia35
Commodity Derivative Financial Instruments - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Thousands | 6 Months Ended |
Jun. 30, 2018MMBTU$ / MMBTU$ / bblbbl | |
Swaps Contract | Second Quarter 2018 | Oil | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 281 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 55.27 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.09 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 61.88 |
Swaps Contract | Third Quarter 2018 | Oil | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 849 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 55.28 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 51.85 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 61.88 |
Swaps Contract | Third Quarter 2018 | Natural Gas | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in MMBtu) | MMBTU | 13,600 |
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 |
Swaps Contract | Fourth Quarter 2018 | Oil | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 854 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 55.18 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 51.85 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 61.88 |
Swaps Contract | Fourth Quarter 2018 | Natural Gas | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in MMBtu) | MMBTU | 13,630 |
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 |
Swaps Contract | First Quarter 2019 | Oil | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 645 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 58.66 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 65.58 |
Swaps Contract | First Quarter 2019 | Natural Gas | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in MMBtu) | MMBTU | 7,200 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.86 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.81 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 |
Swaps Contract | Second Quarter 2019 | Oil | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 645 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 58.66 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 65.58 |
Swaps Contract | Second Quarter 2019 | Natural Gas | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in MMBtu) | MMBTU | 7,240 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.86 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.81 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 |
Swaps Contract | Third Quarter 2019 | Oil | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 645 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 58.20 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 63.75 |
Swaps Contract | Third Quarter 2019 | Natural Gas | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in MMBtu) | MMBTU | 7,280 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.86 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.81 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 |
Swaps Contract | Fourth Quarter 2019 | Oil | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 645 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | 58.20 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 52.82 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 63.75 |
Swaps Contract | Fourth Quarter 2019 | Natural Gas | Swap | |
Derivative [Line Items] | |
Derivative Contract, Volume (in MMBtu) | MMBTU | 7,280 |
Derivative Contract, Weighted Average Price (in USD per Bbl or MMBtu) | $ / MMBTU | 2.86 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | $ / MMBTU | 2.81 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | $ / MMBTU | 2.93 |
Collar Contract [Member] | First Quarter 2020 | Oil | Collar | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 150 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 55 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 65.75 |
Collar Contract [Member] | Second Quarter 2020 | Oil | Collar | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 150 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 55 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 65.75 |
Collar Contract [Member] | Third Quarter 2020 | Oil | Collar | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 150 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 55 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 65.75 |
Collar Contract [Member] | Fourth Quarter 2020 | Oil | Collar | |
Derivative [Line Items] | |
Derivative Contract, Volume (in Bbl) | bbl | 150 |
Derivative Contract, Price Range Low (in USD per Bbl or MMBtu) | 55 |
Derivative Contract, Price Range High (in USD per Bbl or MMBtu) | 65.75 |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Gross fair value amount | $ 6,614 | $ 12,105 |
Effect of Counterparty Netting, Assets | (6,614) | (11,648) |
Total net carrying value on Balance Sheet, assets | 0 | 457 |
Gross Fair Value, Liabilities | 50,657 | 17,133 |
Effect of Counterparty Netting, Liabilities | (6,614) | (11,648) |
Total net carrying value on Balance Sheet, liabilities | 44,043 | 5,485 |
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 | (6,614) | (11,648) |
Total net carrying value on Balance Sheet, assets | 0 | 457 |
Effect of Counterparty Netting, Liabilities | (6,614) | (11,648) |
Total net carrying value on Balance Sheet, liabilities | 44,043 | 5,485 |
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Gross fair value amount | 0 | 0 |
Gross Fair Value, Liabilities | 0 | 0 |
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 amount | 6,614 | 12,105 |
Gross Fair Value, Liabilities | 50,657 | 17,133 |
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Gross fair value amount | 0 | 0 |
Gross Fair Value, Liabilities | $ 0 | $ 0 |
Credit Facility (Details)
Credit Facility (Details) | Nov. 01, 2017 | Jun. 30, 2018USD ($) | May 04, 2018USD ($) | Dec. 31, 2017USD ($) | Apr. 25, 2017USD ($) | Oct. 31, 2016USD ($) |
Line Of Credit Facility [Line Items] | ||||||
Credit facility | $ 421,000,000 | $ 388,000,000 | ||||
Senior Line of Credit | Revolving Credit Facility | ||||||
Line Of Credit Facility [Line Items] | ||||||
Maximum borrowing capacity | $ 1,000,000,000 | |||||
Borrowing base | $ 600,000,000 | $ 550,000,000 | $ 500,000,000 | |||
Interest payable, term | 5 years | 90 days | ||||
Weighted average interest rate (percent) | 4.60% | 4.06% | ||||
Borrowing base threshold (percent) | 50.00% | |||||
Credit facility | $ 421,000,000 | $ 388,000,000 | ||||
Unused portion of current borrowing base | $ 179,000,000 | $ 162,000,000 | ||||
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] | ||||||
Interest payable, term | 90 days | |||||
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% | |||||
Senior Line of Credit | Revolving Credit Facility | Minimum | Prime Rate Plus Margin Rate | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest rate (percent) | 1.00% | |||||
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% | |||||
Senior Line of Credit | Revolving Credit Facility | Maximum | Prime Rate Plus Margin Rate | ||||||
Line Of Credit Facility [Line Items] | ||||||
Interest rate (percent) | 2.00% |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Details) | Jun. 30, 2018 | Nov. 28, 2017 |
Samedan | ||
Business Acquisition [Line Items] | ||
Business acquisition, percentage of voting interests acquired | 100.00% | |
Comin | ||
Business Acquisition [Line Items] | ||
Business acquisition, percentage of voting interests acquired | 100.00% | |
Noncontrolling interest, ownership percentage by noncontrolling owners | 47.34% | |
Temin | ||
Business Acquisition [Line Items] | ||
Noncontrolling interest, ownership percentage by noncontrolling owners | 44.39% |
Incentive Compensation - Summar
Incentive Compensation - Summary of Incentive Compensation Expense (Details) - General and administrative expenses - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Cash—long-term incentive plan | $ 855 | $ 214 | $ 1,673 | $ 636 |
Total incentive compensation expense | 9,980 | 6,491 | 17,024 | 11,574 |
Restricted common and subordinated units | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Equity-based compensation | 3,371 | 2,940 | 6,776 | 4,748 |
Restricted Performance Units | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Equity-based compensation | 5,173 | 2,723 | 7,415 | 5,076 |
Board of Directors | Common Units | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Total incentive compensation expense | $ 581 | $ 614 | $ 1,160 | $ 1,114 |
Preferred Units (Details)
Preferred Units (Details) $ / shares in Units, $ in Thousands | Nov. 28, 2017USD ($)$ / sharesshares | Jun. 30, 2018USD ($)$ / sharesshares | Jun. 30, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)shares |
Preferred Units | ||||
Class of Stock [Line Items] | ||||
Partners' equity, preferred units, outstanding (in shares) | shares | 0 | 0 | 26,363 | |
Preferred units, outstanding value | $ 27,000 | |||
Accrued distributions | $ 700 | |||
Preferred units distribution rate | 10.00% | |||
Adjusted conversion price (in us dollars per share) | $ / shares | $ 14.2683 | $ 14.2683 | ||
Number of preferred units redeemed | shares | 2,115 | 2,115 | 19,704 | |
Preferred stock, redemption amount | $ 2,100 | $ 2,100 | $ 20,200 | |
Number of preferred units converted (in shares) | shares | 24,248 | 24,248 | 6,624 | |
Conversion of preferred units to common units | $ 24,200 | $ 6,600 | ||
Common Units | ||||
Class of Stock [Line Items] | ||||
Adjusted conversion rate | 30.3431 | |||
Conversion of preferred units (in shares) | shares | 735,758 | 200,996 | ||
Number of shares issued (in shares) | shares | 516,639 | |||
Subordinated Units | ||||
Class of Stock [Line Items] | ||||
Adjusted conversion rate | 39.7427 | |||
Conversion of preferred units (in shares) | shares | 963,681 | 263,247 | ||
Series B Cumulative Convertible Preferred Units | ||||
Class of Stock [Line Items] | ||||
Partners' equity, preferred units, outstanding (in shares) | shares | 14,711,000 | 14,711,000 | 14,711,000 | |
Preferred units, outstanding value | $ 298,361 | $ 298,361 | $ 295,394 | |
Accrued distributions | 5,300 | $ 5,300 | $ 1,900 | |
Preferred units distribution rate | 7.00% | |||
Shares, price per share (in dollars per share) | $ / shares | $ 20.3926 | |||
Proceeds from issuance of convertible preferred stock | $ 300,000 | |||
Minimum underlying value for conversion trigger | $ 10,000 | |||
Series B Cumulative Convertible Preferred Units | Noble Acquisition | ||||
Class of Stock [Line Items] | ||||
Number of shares issued (in shares) | shares | 14,711,219 | |||
Proceeds from issuance of convertible preferred stock | $ 300,000 |
Earnings Per Unit - Additional
Earnings Per Unit - Additional Information (Details) shares in Millions | 6 Months Ended |
Jun. 30, 2018shares | |
Common Units | |
Earnings Per Share Basic [Line Items] | |
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU | 15 |
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 | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Earnings Per Share Basic [Line Items] | ||||
Net income (loss) | $ 28,690 | $ 54,174 | $ 70,647 | $ 115,757 |
Net (income) loss attributable to noncontrolling interests | 48 | 16 | 22 | 7 |
Distributions on Series A redeemable preferred units | 0 | (672) | (25) | (1,786) |
Distributions on Series B cumulative convertible preferred units | (5,250) | 0 | (10,500) | 0 |
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | 23,488 | 53,518 | 60,144 | 113,978 |
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 | 23,488 | 53,518 | 60,144 | 113,978 |
Common Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 17,540 | $ 32,100 | $ 41,877 | $ 67,617 |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.17 | $ 0.33 | $ 0.40 | $ 0.69 |
Weighted average units outstanding (basic) (in shares) | 105,250 | 97,990 | 104,516 | 97,448 |
Per unit (diluted) (in dollars per share) | $ 0.17 | $ 0.33 | $ 0.40 | $ 0.69 |
Weighted average units outstanding (diluted) (in shares) | 105,250 | 97,990 | 104,516 | 97,448 |
Subordinated Units | ||||
ALLOCATION OF NET INCOME (LOSS): | ||||
Allocation of net income (loss) | $ 5,948 | $ 21,418 | $ 18,267 | $ 46,361 |
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||
Per unit (basic) (in dollars per share) | $ 0.06 | $ 0.22 | $ 0.19 | $ 0.49 |
Weighted average units outstanding (basic) (in shares) | 96,329 | 95,388 | 95,864 | 95,269 |
Per unit (diluted) (in dollars per share) | $ 0.06 | $ 0.22 | $ 0.19 | $ 0.49 |
Weighted average units outstanding (diluted) (in shares) | 96,329 | 95,388 | 95,864 | 95,269 |
At-The-Market Offering Program
At-The-Market Offering Program (Details) - Common Units - USD ($) | 6 Months Ended | |
Jun. 30, 2018 | May 26, 2017 | |
Class of Stock [Line Items] | ||
Equity Distribution Agreement, maximum value | $ 100,000,000 | |
Number of common units sold, units | 516,639 | |
Proceeds from sale of common units | $ 9,100,000 |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event - USD ($) $ / shares in Units, $ in Millions | Aug. 06, 2018 | Jul. 06, 2018 |
Common Units | ||
Subsequent Event [Line Items] | ||
Quarterly cash distribution declared (in usd per unit) | $ 0.3375 | |
Subordinated Units | ||
Subsequent Event [Line Items] | ||
Quarterly cash distribution declared (in usd per unit) | $ 0.3375 | |
Mineral and Royalty Interests | ||
Subsequent Event [Line Items] | ||
Business combination, consideration transferred | $ 10.8 | |
Payments to acquire businesses, gross | 2.1 | |
Mineral and Royalty Interests | Common Units | ||
Subsequent Event [Line Items] | ||
Fair Value of Common Units Issued | $ 8.7 |