Document and Entity Information
Document and Entity Information - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Mar. 01, 2016 | Jun. 30, 2015 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K/A | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | NRP | ||
Entity Registrant Name | NATURAL RESOURCE PARTNERS LP | ||
Entity Central Index Key | 1,171,486 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 12.2 | ||
Entity Public Float | $ 295 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 51,773 | $ 50,076 |
Accounts receivable, net | 50,167 | 66,455 |
Accounts receivable—affiliates | 6,864 | 9,494 |
Inventory | 7,835 | 5,814 |
Prepaid expenses and other | 4,490 | 4,279 |
Total current assets | 121,129 | 136,118 |
Land | 25,022 | 25,243 |
Plant and equipment, net | 61,239 | 60,093 |
Mineral rights, net | 1,094,027 | 1,781,852 |
Intangible assets, net | 56,927 | 60,733 |
Equity in unconsolidated investment | 261,942 | 264,020 |
Long-term contracts receivable—affiliate | 47,359 | 50,008 |
Goodwill | 0 | 52,012 |
Other assets | 15,306 | 14,645 |
Other assets—affiliate | 1,124 | 0 |
Total assets | 1,684,075 | 2,444,724 |
Current liabilities: | ||
Accounts payable | 8,465 | 22,465 |
Accounts payable—affiliates | 1,464 | 950 |
Accrued liabilities | 45,735 | 43,533 |
Current portion of long-term debt, net | 80,983 | 80,983 |
Total current liabilities | 136,647 | 147,931 |
Deferred revenue | 80,812 | 73,207 |
Deferred revenue—affiliates | 82,853 | 87,053 |
Long-term debt, net | 1,284,083 | 1,374,336 |
Long-term debt, net—affiliate | 19,930 | 19,904 |
Other non-current liabilities | $ 6,808 | $ 22,138 |
Commitments and contingencies | ||
Partners’ capital: | ||
Common unitholders’ interest (12.2 million units outstanding) | $ 79,094 | $ 709,019 |
General partner’s interest | (606) | 12,245 |
Accumulated other comprehensive loss | (2,152) | (459) |
Total partners’ capital | 76,336 | 720,805 |
Non-controlling interest | (3,394) | (650) |
Total capital | 72,942 | 720,155 |
Total liabilities and capital | $ 1,684,075 | $ 2,444,724 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - shares shares in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Common units outstanding (in shares) | 12.2 | 12.2 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues and other income: | |||
Total revenues and other income | $ 488,849 | $ 399,752 | $ 358,117 |
Operating expenses: | |||
Operating and maintenance expenses | 155,959 | 83,433 | 33,211 |
Operating and maintenance expenses—affiliates, net | 16,031 | 10,770 | 8,821 |
Depreciation, depletion and amortization | 100,828 | 79,876 | 64,377 |
General and administrative | 7,036 | 7,287 | 11,452 |
General and administrative—affiliates | 5,312 | 3,258 | 3,286 |
Asset impairment | 681,594 | 26,209 | 734 |
Total operating expenses | 966,760 | 210,833 | 121,881 |
Income (loss) from operations | (477,911) | 188,919 | 236,236 |
Other income (expense) | |||
Interest expense | (93,827) | (80,185) | (64,396) |
Interest income | 18 | 96 | 238 |
Other expense, net | (93,809) | (80,089) | (64,158) |
Net income (loss) | (571,720) | 108,830 | 172,078 |
Net income (loss) attributable to partners: | |||
Limited partners | (559,492) | 106,653 | 168,636 |
General partner | $ (12,228) | $ 2,177 | $ 3,442 |
Basic and diluted net income (loss) per common unit (in dollars per share) | $ (45.75) | $ 9.42 | $ 15.39 |
Weighted average number of common units outstanding (in shares) | 12,230 | 11,326 | 10,958 |
Add: comprehensive income (loss) from unconsolidated investment and other | $ (1,693) | $ (81) | $ 65 |
Comprehensive income (loss) | (573,413) | 108,749 | 172,143 |
Coal, Hard Mineral Royalty and Other | |||
Revenues and other income: | |||
Coal, hard mineral royalty and other—affiliates | 89,715 | 84,559 | 93,026 |
Total revenues and other income | 156,638 | 172,160 | 213,825 |
VantaCore | |||
Revenues and other income: | |||
Total revenues and other income | 139,013 | 42,051 | 0 |
Oil and Gas | |||
Revenues and other income: | |||
Total revenues and other income | 53,565 | 59,566 | 17,080 |
Soda Ash | |||
Revenues and other income: | |||
Total revenues and other income | $ 49,918 | $ 41,416 | $ 34,186 |
Consolidated Statements of Part
Consolidated Statements of Partners' Capital - USD ($) shares in Thousands, $ in Thousands | Total | General Partner [Member] | Common Stock [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Partners Capital Excluding Noncontrolling Interest [Member] | Non-Controlling Interest [Member] |
Balance, beginning of period at Dec. 31, 2012 | $ 617,447 | $ 10,026 | $ 605,019 | $ (443) | $ 614,602 | $ 2,845 |
Balance, beginning of period (in shares) at Dec. 31, 2012 | 10,603 | |||||
Issuance of common units | 75,000 | $ 75,000 | 75,000 | |||
Issuance of common units (in shares) | 378 | |||||
Capital contribution | 1,531 | 1,531 | 1,531 | |||
Cost associated with equity transactions | (293) | $ (293) | (293) | |||
Distributions to unitholders | (246,518) | (4,930) | (241,588) | (246,518) | ||
Distributions to non-controlling interests | (2,521) | (2,521) | ||||
Net income (loss) | 172,078 | 3,442 | 168,636 | 172,078 | ||
Comprehensive income from unconsolidated investment and other | 65 | 65 | 65 | |||
Balance, end of period at Dec. 31, 2013 | 616,789 | 10,069 | $ 606,774 | (378) | 616,465 | 324 |
Balance, end of period (in shares) at Dec. 31, 2013 | 10,981 | |||||
Issuance of common units | 127,202 | $ 127,202 | 127,202 | |||
Issuance of common units (in shares) | 1,006 | |||||
Issuance of common units for acquisitions | 31,604 | $ 31,604 | 31,604 | |||
Issuance of common units for acquisitions (in shares) | 243 | |||||
Capital contribution | 3,240 | 3,240 | 3,240 | |||
Cost associated with equity transactions | (4,413) | $ (4,413) | (4,413) | |||
Distributions to unitholders | (162,042) | (3,241) | (158,801) | (162,042) | ||
Distributions to non-controlling interests | (974) | (974) | ||||
Net income (loss) | 108,830 | 2,177 | 106,653 | 108,830 | ||
Comprehensive income from unconsolidated investment and other | (81) | (81) | (81) | |||
Balance, end of period at Dec. 31, 2014 | 720,155 | 12,245 | $ 709,019 | (459) | 720,805 | (650) |
Balance, end of period (in shares) at Dec. 31, 2014 | 12,230 | |||||
Cost associated with equity transactions | (109) | $ (109) | (109) | |||
Distributions to unitholders | (71,758) | (1,434) | (70,324) | (71,758) | ||
Distributions to non-controlling interests | (2,744) | (2,744) | ||||
Net income (loss) | (571,720) | (12,228) | (559,492) | (571,720) | ||
Non-cash contributions | 811 | 811 | 811 | |||
Comprehensive income from unconsolidated investment and other | (1,693) | (1,693) | (1,693) | |||
Balance, end of period at Dec. 31, 2015 | $ 72,942 | $ (606) | $ 79,094 | $ (2,152) | $ 76,336 | $ (3,394) |
Balance, end of period (in shares) at Dec. 31, 2015 | 12,230 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities: | |||
Net income (loss) | $ (571,720) | $ 108,830 | $ 172,078 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Asset impairment | 681,594 | 26,209 | 734 |
Depreciation, depletion and amortization | 100,828 | 79,876 | 64,377 |
Distributions from equity earnings from unconsolidated investments | 46,795 | 43,005 | 24,113 |
Equity earnings from unconsolidated investment | (49,918) | (41,416) | (34,186) |
Gain on reserve swap | (9,290) | (5,690) | (8,149) |
Other, net | (1,295) | 1,942 | (8,721) |
Other, net—affiliates | (287) | 0 | 0 |
Change in operating assets and liabilities: | |||
Accounts receivable | 16,486 | (8,685) | 2,593 |
Accounts receivable—affiliates | 2,630 | (1,828) | 2,947 |
Accounts payable | (3,775) | (2,408) | 1,633 |
Accounts payable—affiliates | 514 | 559 | (566) |
Accrued liabilities | (4,676) | (1,821) | 7,927 |
Deferred revenue | 7,605 | 2,056 | 4,164 |
Deferred revenue—affiliates | (4,200) | 15,618 | 15,076 |
Accrued incentive plan expenses | (7,023) | (5,265) | 2,284 |
Other items, net | (1,030) | (47) | (516) |
Other items, net—affiliates | 186 | (180) | 1,286 |
Net cash provided by operating activities | 203,424 | 210,755 | 247,074 |
Cash flows from investing activities: | |||
Acquisition of mineral rights | (40,679) | (356,026) | (72,000) |
Acquisition of plant and equipment and other | (10,175) | (2,454) | 0 |
Proceeds from sale of plant and equipment and other | 11,024 | 1,006 | 0 |
Proceeds from sale of mineral rights | 7,096 | 412 | 10,929 |
Acquisition of equity interests | 0 | 0 | (293,085) |
Acquisition of aggregates business | 0 | (168,978) | 0 |
Return of equity and other unconsolidated investments | 0 | 3,633 | 48,833 |
Return of long-term contract receivables—affiliate | 2,463 | 1,904 | 2,558 |
Net cash used in investing activities | (30,271) | (520,503) | (302,765) |
Cash flows from financing activities: | |||
Proceeds from loans | 100,000 | 617,471 | 567,020 |
Proceeds from loans—affiliate | 0 | 19,904 | 0 |
Proceeds from issuance of common units | 0 | 127,202 | 75,000 |
Capital contribution by general partner | 0 | 3,240 | 1,531 |
Repayments of loans | (190,983) | (327,983) | (386,230) |
Distributions to partners | (71,758) | (162,042) | (246,518) |
Distributions to non-controlling interest | (2,744) | (974) | (2,521) |
Debt issue costs and other | (5,971) | (9,507) | (9,502) |
Net cash provided by (used in) financing activities | (171,456) | 267,311 | (1,220) |
Net increase (decrease) in cash and cash equivalents | 1,697 | (42,437) | (56,911) |
Cash and cash equivalents at beginning of period | 50,076 | 92,513 | 149,424 |
Cash and cash equivalents at end of period | 51,773 | 50,076 | 92,513 |
Supplemental cash flow information: | |||
Cash paid during the period for interest | 88,493 | 76,155 | 55,191 |
Non-cash investing activities: | |||
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities | $ 5,949 | $ 11,879 | $ 3,019 |
Units issued for acquisition of aggregate operations (in shares) | 0 | 31,604 | 0 |
Non-cash contingent consideration on equity investments | $ 0 | $ 0 | $ 15,000 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Organization and Nature of Operations Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning, operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, oil and gas, construction aggregates, frac sand and other natural resources. As used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or indicated by context. The Partnership’s coal reserves are located in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. The Partnership does not operate any coal mines, but leases its coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell its reserves in exchange for royalty payments. The Partnership also owns and manages infrastructure assets that generate additional revenues, primarily in the Illinois Basin. The Partnership owns or leases aggregates and industrial minerals located in a number of states across the country. The Partnership derives a small percentage of its aggregates and industrial mineral revenues by leasing its owned reserves to third party operators who mine and sell the reserves in exchange for royalty payments. However, the majority of the Partnership’s aggregates revenues come through its ownership of VantaCore Partners LLC ("VantaCore"), which was acquired in October 2014. VantaCore specializes in the construction materials industry and operates four hard rock quarries, six sand and gravel plants, two asphalt plants and two marine terminals. VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. The Partnership owns a 49% non-controlling equity interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, the Partnership’s operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. The Partnership receives regular quarterly distributions from this business, and records income in accordance with the equity method of accounting. The Partnership also owns various interests in oil and gas properties that are located in the Williston Basin, the Appalachian Basin, Louisiana and Oklahoma. The Partnership’s interests in the Appalachian Basin, Louisiana and Oklahoma are minerals and royalty interests, while in the Williston Basin the Partnership owns non-operated working interests. The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through two wholly owned operating companies: NRP (Operating) LLC ("NRP Opco") and NRP Oil and Gas LLC ("NRP Oil and Gas"). NRP Oil and Gas holds the Partnership's non operated oil and gas working interests in the Williston Basin. All other operations of the Partnership, including other oil and gas assets, are held by NRP Opco. NRP GP has sole responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson is entitled to nominate all ten of the directors to the board of directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, LLC, an affiliate of Christopher Cline. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Basis of Presentation The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with International Paper Company controlled by the Partnership. The Partnership has an equity investment through which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the investee’s activities which is accounted for using the equity method. Intercompany transactions and balances have been eliminated. Management’s Forecast, Strategic Plan and Going Concern Analysis While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics continue to be impacted by demand challenges for coal and excess worldwide supply of oil and gas. In particular, as described in Note 10. Debt and Debt—Affiliate , NRP Oil and Gas and NRP Opco have debt agreements that contain customary financial covenants, including maintenance covenants, and other covenants. In addition, NRP has issued $425 million of 9.125% Senior Notes that are governed by an indenture ("the Indenture") containing customary incurrence-based financial covenants and other covenants, but not maintenance covenants. The following discussion presents management’s going concern analysis in light of management’s outlook and strategic plan to address its debt covenant compliance and maturities. Opco and NRP As of December 31, 2015, Opco had $290.0 million of indebtedness outstanding under its revolving credit facility due October 2017 (the "Opco Credit Facility") and $585.9 million outstanding under several series of Private Placement Notes (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required to be below 4.0 x through March 31, 2016. Commencing with respect to the period ended June 30, 2016, the maximum leverage ratio reduces to 3.75 x and reduces again to 3.5 x commencing with respect to the period ended June 30, 2017. In addition, the Opco Debt agreements contain certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. As of December 31, 2015, Opco was in compliance with and we forecast that Opco will continue to remain in compliance through December 31, 2016 with the covenants contained in its debt agreements. In addition, we believe Opco has sufficient liquidity to make all regularly scheduled principal and interest payments through December 31, 2016. We are currently pursuing or considering a number of actions including (i) dispositions of assets, (ii) actively managing our debt capital structure through a number of potential alternatives, including exchange offers and non-traditional debt financing, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital and (vi) improving our cash flows from operations. While we forecast that we will be in compliance with all of the covenants under the Opco Debt agreements through December 31, 2016, our forecast is sensitive to commodity pricing and counterparty risk. Accordingly, management intends to pursue one or more of the alternatives discussed above in order to mitigate the effects of further commodity price and market deterioration which could otherwise cause us to breach financial covenants under the Opco Debt agreements. Breaches of the Opco Debt agreement covenants that are not waived or cured, to the extent possible, would result in an event of default under the Opco Debt agreements, and if such debt is accelerated by the lenders thereunder, such acceleration would also result in a cross-default under the Indenture. NRP Oil and Gas NRP Oil and Gas had $85.0 million outstanding under its senior secured, reserve-based revolving credit facility (the "RBL Facility") as of December 31, 2015. The facility is secured by a first priority lien on substantially all of NRP Oil and Gas’s assets and is not guaranteed by NRP or any other subsidiary of NRP. Due to the significant and sustained decline in oil prices since the end of 2014, management forecasts that NRP Oil and Gas may not be able to remain in compliance with the 3.5 x leverage ratio as required in the RBL Facility during the next 12 months. In addition, management expects that, due to current oil and gas prices, the next borrowing base redetermination under the RBL Facility that is scheduled to occur in May 2016 may result in a reduction of the borrowing base by an amount that would exceed NRP Oil and Gas’s ability to repay principal within the required time-frame following such redetermination. In addition, the RBL Facility requires the entity to provide annual financial statements that include a report from its independent registered public accounting firm with an opinion that does not contain "a "going concern" or like qualification or exception." Any of these events would qualify as an event of default and would provide the RBL Facility lenders with the ability to accelerate the debt outstanding under the RBL Facility to the extent not waived or cured. While we are attempting to take appropriate mitigating actions, there is no assurance that any particular actions with respect to amending, refinancing, extending the maturity or curing potential defaults in the RBL Facility will be sufficient, and we may be required to sell some or all of the assets of NRP Oil and Gas, raise new equity capital at NRP Oil and Gas or pursue restructuring alternatives. As a result, we believe there is substantial doubt about the ability of NRP Oil and Gas to continue as a going concern through December 31, 2016. As we were in compliance with all covenants contained in the RBL Facility throughout 2015 and at December 31, 2015, we have classified this debt as non-current in accordance with its terms. An event of default under the RBL facility and subsequent acceleration of that debt by the lenders thereunder would not result in a cross-default under the Indenture. NRP Oil and Gas is designated as an "Unrestricted Subsidiary" for purposes of the Indenture, which prevents an event of default under the RBL Facility and subsequent acceleration of that debt from triggering an event of default under the Indenture. In addition, there are no cross-defaults under the Opco Debt agreements as a result of a default under the RBL Facility. As a result, there would be no default or acceleration of indebtedness under the Indenture or under the Opco Debt agreements in the event NRP Oil and Gas is in default under its RBL Facility. Recasting of Certain Prior Period Information Due to the acquisitions that diversified our natural resource asset base, effective for the quarter ended December 31, 2015, management revised the Partnership's operating segments to align with its management structure and organizational responsibilities and revised the information that its chief operating decision maker regularly reviews for purposes of allocating resources and assessing performance. As a result, effective for the quarter ended December 31, 2015, we report our financial performance based on new segments as described in "Note 3. Segment Information". We recast certain prior period amounts to conform to the way we internally manage and monitor segment performance. This change had no impact on the Partnership's consolidated financial position, net income (loss) or cash flows. In addition, certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation. Prior year general and administrative charges that were allocated to the operating segments have been reclassified to Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Reverse Unit Split On January 26, 2016, the board of directors of our general partner approved a 1-for-10 reverse split on our common units, effective following market close on February 17, 2016. Pursuant to the authorization provided, the Partnership completed the 1-for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange on February 18, 2016. As a result of the reverse unit split, every 10 outstanding common units were combined into one common unit. The reverse unit split reduced the number of common units outstanding from 122.3 million units to approximately 12.2 million units. All units and per unit data included in these consolidated financial statements have been retroactively restated to reflect the reverse unit split. Use of Estimates Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income during the reporting period. Actual results could differ from those estimates. Business Combinations For purchase acquisitions accounted for as business combinations, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. Out-of-Period Adjustment In March 2015, the Partnership recorded an out-of-period adjustment to correct an error in depletion expense related to its oil and gas royalty interests owned by BRP, in which the Partnership owns a 51% interest. Depletion expense for the year ended December 31, 2015 includes a credit of $3.8 million to adjust the impact of depletion expense recorded in prior periods. After evaluating the quantitative and qualitative aspects of the error and the out-of-period adjustment to the Partnership’s financial results, management determined the misstatement and the out-of-period adjustment are not material to the prior period financial statements. Fair Value The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See "Note 11. Fair Value Measurements." There are three levels of inputs that may be used to measure fair value: • Level 1—Quoted prices in active markets for identical assets or liabilities. • Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. • Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation. Cash and Cash Equivalents The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents. Accounts Receivable Accounts receivable from the Partnership’s lessees and customers do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying Consolidated Balance Sheets. The Partnership evaluates the collectability of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its accounts receivable and when it becomes aware of a specific lessee’s or customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s or customer’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. The reserve is recognized as a reduction in the accounts receivable and an increase in operating and maintenance expenses or operating and maintenance expenses—affiliates. Accounts are charged off when collection efforts are complete and future recovery is doubtful. The allowance for doubtful accounts included in the Partnership's net accounts receivable balance (including affiliates) was $5.3 million and $0.7 million at December 31, 2015 and December 31, 2014, respectively. A significant amount of the change to the Partnership's allowance for doubtful accounts during 2015 relates to new allowances for doubtful coal-related receivables. Inventory Inventories are stated at the lower of cost or market. The cost of aggregates and asphalt components such as stone, sand, and recycled and liquid asphalt is determined by the first-in, first-out (FIFO) method. Cost includes all direct materials, direct labor and related production overheads based on normal operating capacity. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Partnership’s aggregates operations. Plant and Equipment Plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the asset acquired and consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at cost and are depreciated on a straight-line basis over their useful lives generally as follows: Years Buildings and improvements 20 to 40 Machinery and equipment 5 to 12 Leasehold improvements Life of Lease The Partnership begins capitalizing mine development costs at its aggregates operations at a point when reserves are determined to be proven or probable, economically mineable and when demand supports investment in the market. Capitalization of these costs ceases when production commences. Mine development costs are amortized based on production over the estimated life of mineral reserves and amortization is included as a component of depreciation expense. Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein. The Partnership owns royalty and non-operated working interests in oil and natural gas reserves, all of which are located in the U.S. The Partnership does not determine whether or when to develop reserves. The Partnership uses the successful efforts method to account for its working interest in oil and gas properties. Oil and gas non-operated working interests are depleted on a unit-of-production basis. The depletion rate is adjusted annually based upon the amount of remaining reserves as determined by independent third party petroleum engineers. Oil and gas royalty interests are depleted on a straight-line basis over 30 years or the life of the asset, whichever is shorter. Intangible Assets The Partnership’s intangible assets consist primarily of contracts that at acquisition were more favorable for the Partnership than prevailing market rates, known as above-market contracts. The estimated fair values of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis except that a minimum amortization is calculated on a straight-line basis for temporarily idled assets. Asset Impairment We have developed procedures to periodically evaluate our long-lived assets for possible impairment. These procedures are performed throughout the year and are based on historic, current and future performance and are designed to be early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property. As a result of the continued weakness in the coal markets and the potential for further declines in oil and natural gas prices, we intend to closely monitor our coal and oil and gas assets, and the impairment evaluation process may be completed more frequently if deemed necessary. Future impairment analyses could result in downward adjustments to the carrying value of our assets. During 2015, we recorded impairment expense of $676.1 million on certain of our mineral rights within our Coal, Hard Mineral Royalty and Other and Oil and Gas segments as well as plant and equipment within our Coal, Hard Mineral Royalty and Other and VantaCore segments. We evaluate our equity investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. In accordance with FASB accounting and disclosure guidance for goodwill, we test our recorded goodwill for impairment annually or more often if indicators of potential impairment exist, by determining if the carrying value of a reporting unit exceeds its estimated fair value. Factors that could trigger an interim impairment test include, but are not limited to, underperformance relative to historical or projected future operating results or significant changes in our overall business, industry, or economic trends. We recorded a $5.5 million impairment loss related to the VantaCore reporting unit for the year ended December 31, 2015. Revenue Recognition Coal, Hard Mineral Royalty and Other Revenues. Coal and hard mineral royalty revenues are recognized on the basis of tons of mineral sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons of material processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, we receive a fixed price per ton for all material transported on the beltlines. Most of the Partnership’s coal and aggregates lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments. Soda Ash Revenues. We account for non-marketable investments using the equity method of accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for our investment in Ciner Wyoming using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of the fair value of the underlying net assets of equity method investees is hypothetically allocated first to identified tangible assets and liabilities, then to finite-lived intangibles or indefinite-lived intangibles and the balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived intangibles, if any, and goodwill are not amortized. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income. Our carrying value in Ciner Wyoming is reflected in the caption "Equity in unconsolidated investments" in our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity in earnings of Ciner Wyoming." These earnings are generated from natural resources, which are considered part of our core business activities consistent with its directly owned revenue generating activities. Investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the proportionate share of the investee’s book value, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets. VantaCore Revenues. Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to the estimated total costs for each contract. That method is used since we consider total cost to be the best available measure of progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred. Oil and Gas Revenues . Oil and gas related revenues consist of revenues from our non-operated working interests, royalties and overriding royalties. Revenues related to our non-operated working interests in oil and gas assets are recognized on the basis of our net revenue interests in hydrocarbons produced. Our revenues fluctuate based on changes in the market prices for oil and natural gas, the decline in production from producing wells, and other factors affecting the third-party oil and natural gas exploration and production companies that operate our wells, including the cost of development and production. Oil and gas royalty revenues are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Also, included within oil and gas royalties are lease bonus payments, which are generally paid upon the execution of a lease. Property Taxes The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in Coal, Hard Mineral Royalty and Other revenues and in Operating and maintenance expenses, respectively, in the Consolidated Statements of Comprehensive Income. Transportation Revenue and Expense The Company records transportation revenue and pays transportation costs to a Foresight affiliate to operate equipment on behalf of the Company. The revenue and expenses related to these transactions are recorded as Coal, Hard Mineral Royalty and Other—affiliates revenues and Operating and maintenance expenses—affiliates in the Consolidated Statements of Comprehensive Income. Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as Coal, Hard Mineral Royalty and Other revenues and Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income. Asset Retirement Costs and Obligations The Partnership accrues for mine closure, reclamation as well as plugging and abandonment of its oil and gas non-operated working interests in accordance with authoritative guidance related to accounting for asset retirement costs and obligations. This guidance requires the fair value of an obligation be recognized in the period it is incurred, if the fair value can be reasonably estimated. The Partnership recognizes an asset and liability related to the present value of future estimated costs. Depreciation or depletion of the capitalized asset retirement cost is determined based upon the underlying asset being retired in the future. Accretion of the asset retirement obligation is recognized over time and will increase as the obligation becomes more near term. It is reasonably possible that the estimates related to asset retirement and environmental obligations may change in the future. See "Note 13. Asset Retirement Obligations." Unit-Based Compensation We have awarded unit-based compensation in the form of phantom units that are more fully described in Note 16. Long-Term Incentive Plans." A summary of our accounting policy for unit-based awards follows. The Partnership accounts for awards relating to its Long-Term Incentive Plan using the fair value method, which requires the Partnership to estimate the fair value of the grant, and charge or credit the estimated fair value to expense over the requisite service period of the grant based on fluctuations in the Partnership’s common unit price. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability and the fair value is recalculated at each reporting date over the service or vesting period of the grant. See "Note 16. Long-Term Incentive Plans." Deferred Financing Costs Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These costs are amortized over the term of the debt. Deferred financing costs are included in Other Assets on the Partnership's Consolidated Balance Sheets. Income Taxes No provision for income taxes related to the operations of the Partnership has been included in the accompanying financial statements because, as a partnership, it is not subject to federal or material state income taxes and the tax effect of its activities accrues to the unitholders. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities. Lessee Audits and Inspections The Partnership periodically audits lessee information by examining certain records and internal reports of its lessees. The Partnership’s regional managers also perform periodic mine inspections to verify that the information that has been reported to the Partnership is accurate. The audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to the Partnership and the actual results from each property. Audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the revenue was initially recorded. Typically there are no material adjustments from this process. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board ("FASB") amended its guidance on revenue recognition. The core principle of this amendment is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted for reporting periods beginning after December 15, 2016, including interim reporting periods within that period. This guidance can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows. In August 2014, the FASB issued guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The new guidance will require a formal assessment of going concern b |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information The Partnership's segments are strategic business units that offer products and services to different customer segments in different geographies within the U.S. and that are managed accordingly. NRP has the following four operating segments: Coal, Hard Mineral Royalty and Other —consists primarily of coal royalty, coal related transportation and processing assets, aggregate and industrial minerals royalty assets and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of states across the United States. Soda Ash —consists of the Partnership's 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business. VantaCore —consists of our construction materials business acquired in October 2014 that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. Oil and Gas —consists of our non-operated working interests, royalty interests and overriding royalty interests in oil and natural gas properties. Our primary interests in oil and natural gas producing properties are non-operated working interests located in the Williston Basin in North Dakota and Montana. We also own fee mineral, royalty or overriding royalty interests in oil and gas properties in several other regions, including the Appalachian Basin, Oklahoma and Louisiana. Direct segment costs and certain costs incurred at a corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments. These allocated costs include costs of: taxes, legal, information technology and shared facilities services and are included in Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. Prior year general and administrative charges that are allocated to the operating segments have been reclassified to operating and maintenance expenses. Intersegment sales are at prices that approximate market. In reconciling items to consolidated operating income, Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other corporate-level activity not specifically allocated to a segment. The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands): Operating Segments For the Year Ended Coal, Hard Mineral Royalty and Other Soda Ash VantaCore Oil and Gas Corporate and Financing Total December 31, 2015 Revenues (including affiliates) $ 246,353 $ 49,918 $ 139,013 $ 53,565 $ — $ 488,849 Intersegment revenues (expenses) 21 — (21 ) — — — Depreciation, depletion and amortization 44,478 — 15,578 40,772 — 100,828 Asset impairment 307,800 — 6,218 367,576 — 681,594 Interest expense, net — — — — (93,809 ) (93,809 ) Net income (loss) (138,388 ) 49,918 272 (377,365 ) (106,157 ) (571,720 ) Capital expenditures 428 — 14,039 30,457 — 44,924 Total assets at December 31, 2015 1,047,922 261,942 200,348 158,862 15,001 1,684,075 December 31, 2014 Revenues (including affiliates) $ 256,719 $ 41,416 $ 42,051 $ 59,566 $ — $ 399,752 Depreciation, depletion and amortization 52,645 — 3,296 23,935 — 79,876 Asset impairment 26,209 — — — — 26,209 Interest expense, net — — — — (80,089 ) (80,089 ) Net income (loss) 143,678 41,416 32 14,338 (90,634 ) 108,830 Capital expenditures 5,351 — 171,116 359,851 — 536,318 Total assets at December 31, 2014 1,403,762 264,020 219,658 540,713 16,571 2,444,724 December 31, 2013 Revenues (including affiliates) $ 306,851 $ 34,186 $ — $ 17,080 $ — $ 358,117 Depreciation, depletion and amortization 58,502 — — 5,875 — 64,377 Asset impairment 734 — — — — 734 Interest expense, net — — — — (64,158 ) (64,158 ) Net income (loss) 211,590 34,186 — 5,198 (78,896 ) 172,078 Capital expenditures — 293,085 — 75,019 — 368,104 Total assets at December 31, 2013 1,520,428 269,338 — 189,211 12,879 1,991,856 |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions | Acquisitions VantaCore Acquisition On October 1, 2014, the Partnership continued its effort to own a more diversified portfolio of natural resources by completing its acquisition of VantaCore for $200.6 million in cash and common units. At the time of acquisition, VantaCore operated three hard rock quarries, six sand and gravel plants, two asphalt plants, one underground limestone mine and one marine terminal. VantaCore is headquartered in Philadelphia, Pennsylvania and its current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. This acquisition aligned the Partnership’s effort to own a more diversified portfolio of natural resources. The Partnership accounted for the transaction as a business combination under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisitions were expensed as incurred. The fair value of these assets and liabilities was estimated using a discounted cash flow technique with significant inputs including future production volumes, aggregate sales prices, reserves and operating costs that are not observable in the market and thus represents a Level 3 fair value measurement. The results of operations of the acquisition have been included in our consolidated financial statements since the acquisition date. In the first quarter 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for various items of VantaCore’s plant and equipment that existed as of acquisition date. As a result of this adjustment, plant and equipment was increased by $22.5 million with a corresponding decrease to goodwill. In the second quarter 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for VantaCore’s right to mine and intangible assets that existed as of the acquisition date. As a result of this adjustment, Mineral rights, net and Intangible assets, net were increased by $24.7 million with a corresponding decrease to Goodwill. The purchase price allocation was further adjusted as more detailed analysis was completed for VantaCore’s asset retirement obligations that existed as of acquisition date. As a result of this adjustment, asset retirement obligations were decreased by $2.3 million with a corresponding decrease to the asset retirement cost that was capitalized as part of the related land, property and equipment. The accounting for the VantaCore acquisition was completed in the second quarter of 2015 with the exception of this asset retirement obligation adjustment that was recoded in the fourth quarter of 2015. Measurement-period adjustments were not material to prior period financial statements and were recorded during the period in which the amount of the adjustment was determined. The accounting for the VantaCore acquisition is summarized as follows (in thousands): October 1, 2014 Consideration Cash $ 168,978 NRP common units 31,604 Total consideration given $ 200,582 Allocation of Purchase Price Current assets $ 37,222 Land, property and equipment 59,946 Mineral rights 111,500 Other assets 4,347 Current liabilities (16,953 ) Asset retirement obligation (1,005 ) Goodwill 5,525 Fair value of net assets acquired $ 200,582 Included in the Consolidated Statements of Comprehensive Income was revenue of $42.1 million and operating income of $0.1 million for the year ended December 31, 2014. Transaction costs through December 31, 2014 associated with this acquisition were $2.9 million and were expensed as incurred. These expenses are reflected in Operating and maintenance expenses on the Consolidated Statements of Comprehensive Income. Sanish Field Acquisition On November 12, 2014, the Partnership continued its effort to own a more diversified portfolio of natural resources by completing its acquisition of non-operated oil and gas working interests in the Sanish Field of the Williston Basin from an affiliate of Kaiser-Francis Oil Company for $339.1 million . The Partnership accounted for the transaction as a business combination under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisitions were expensed as incurred. The fair value of these assets and liabilities was estimated using a discounted cash flow technique with significant inputs that are not observable in the market and thus represents a Level 3 fair value measurement. Significant inputs used to determine the fair value include estimates of: (i) reserves, including estimated oil and natural gas reserves and risk-adjusted probable reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The results of operations of the acquisition have been included in our consolidated financial statements since the acquisition date. The accounting for the Sanish Field acquisition was completed in the second quarter of 2015 without significant changes during the measurement period and is summarized as follows (in thousands): November 12, 2014 Consideration Cash $ 339,093 Allocation of Purchase Price Mineral rights - proven oil and gas properties 298,293 Mineral rights - probable and possible oil and gas resources 40,800 Fair value of net assets acquired $ 339,093 Included in the Consolidated Statements of Comprehensive Income was revenue of $12.8 million and operating income of $3.7 million for the year ended December 31, 2014. The transaction costs incurred in connection with this acquisition were $1.8 million through December 31, 2014, and were expensed as incurred. These expenses are reflected in Operating and maintenance expenses on the Consolidated Statements of Comprehensive Income. Pro Forma Financial Information (unaudited) The following unaudited pro forma financial information (in thousands) presents a summary of the Partnership’s consolidated revenues, net income and net income per common unit for the twelve months ended December 31, 2014 and 2013 assuming the VantaCore and Sanish Field acquisitions had been completed as of January 1, 2013, including adjustments to reflect the values assigned to the net assets acquired: For the Years ended December 31, 2014 2013 Total revenues and other income $ 533,517 $ 579,933 Net income $ 122,319 $ 197,164 Basic and diluted net income per common unit $ 9.90 $ 16.00 Other Oil and Gas Aquisitions During the year ended December 31, 2013, the Partnership also completed two smaller acquisitions of oil and natural gas properties located in the Williston Basin as described below: Sundance Acquisition In December, 2013, the Partnership completed the acquisition of non-operated working interests in oil and gas properties in the Williston Basin of North Dakota from Sundance Energy, Inc. for $29.4 million , following post-closing purchase price adjustments. The Partnership accounted for the transaction in accordance with the authoritative guidance for business combinations. During the third quarter of 2014, the Partnership finalized the determination of the fair value of the assets acquired and liabilities assumed in the acquisition, with no material adjustments. The assets acquired are included in Mineral rights in the accompanying Consolidated Balance Sheets. Abraxas Acquisition In August, 2013, the Partnership completed the acquisition of non-operated working interests in oil and gas properties in the Williston Basin of North Dakota and Montana from Abraxas Petroleum for $38.0 million , following post-closing purchase price adjustments. The Partnership accounted for the transaction in accordance with the authoritative guidance for business combinations. During the second quarter of 2014, the Partnership finalized the determination of the fair values of the assets acquired and liabilities assumed in the acquisition, with no material adjustments. The assets acquired are included in Mineral rights on the accompanying Consolidated Balance Sheets. With respect to the Abraxas and Sundance acquisitions, revenues of $5.4 million and operating income of $2.5 million were included in the Consolidated Statements of Comprehensive Income and Consolidated Balance Sheet for the year ended December 31, 2013. |
Equity Investment
Equity Investment | 12 Months Ended |
Dec. 31, 2015 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Investment | Equity Investment We account for our 49% investment in Ciner Wyoming LLC ("Ciner Wyoming", and formerly "OCI Wyoming LLC") using the equity method of accounting. Ciner Wyoming distributed $46.8 million , $46.6 million and $72.9 million to us in the year ended December 31, 2015, 2014 and 2013, respectively. The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was $154.8 million and $162.7 million as of December 31, 2015 and 2014, respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years . The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method. Our equity in the earnings of Ciner Wyoming is summarized as follows (in thousands): For the Year Ended December 31, 2015 2014 2013 Income allocation to NRP’s equity interests $ 54,709 $ 47,354 $ 37,036 Amortization of basis difference (4,791 ) (5,938 ) (2,850 ) Equity in earnings of unconsolidated investment $ 49,918 $ 41,416 $ 34,186 The results of Ciner Wyoming’s operations are summarized as follows (in thousands): For the Year Ended December 31, 2015 2014 2013 Sales $ 486,393 $ 465,032 $ 442,132 Gross profit 131,493 118,439 94,299 Net Income 111,650 96,640 79,655 The financial position of Ciner Wyoming is summarized as follows (in thousands): For the Year Ended December 31, 2015 2014 Current assets $ 144,695 $ 179,851 Noncurrent assets 233,845 223,053 Current liabilities 43,018 47,704 Noncurrent liabilities 116,808 149,192 |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2015 | |
Inventory Disclosure [Abstract] | |
Inventory | Inventory The components of inventories at December 31, 2015 and 2014 are as follows (in thousands): December 31, December 31, Aggregates $ 7,056 $ 4,596 Supplies and parts 779 1,218 Total inventory $ 7,835 $ 5,814 |
Plant and Equipment
Plant and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Plant and Equipment | Plant and Equipment The Partnership’s plant and equipment consist of the following (in thousands): December 31, 2015 December 31, 2014 Plant and equipment at cost $ 92,203 $ 89,759 Construction in process 1,074 457 Less accumulated depreciation (32,038 ) (30,123 ) Total plant and equipment, net $ 61,239 $ 60,093 Depreciation expense related to the Partnership's plant and equipment totaled $15.9 million , $7.6 million and $6.0 million for the year ended December 31, 2015, 2014 and 2013, respectively. During the second quarter of 2015 the Partnership recorded a $2.3 million impairment expense related to a coal preparation plant and during the fourth quarter of 2015 the Partnership recorded a $4.7 million impairment expense related to coal processing and transportation assets as well as obsolete equipment at our Logan office. The fair value measurement of these impaired assets recorded at fair value were $0.0 million at the end of the reporting period. The Partnership also recorded a $0.7 million impairment expense related to obsolete plant and equipment at VantaCore. During the fourth quarter of 2014, the Partnership recorded $0.8 million in impairment expense related to a coal preparation plant. These impairment charges are included in Asset impairments in the Consolidated Statements of Comprehensive Income for the year ending December 31, 2015 and December 31, 2014, respectively. |
Mineral Rights
Mineral Rights | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Mineral Rights | Mineral Rights The Partnership’s mineral rights consist of the following (in thousands): For the Year Ended December 31, 2015 Carrying Value Accumulated Depletion Net Book Value Coal, Hard Mineral Royalty and Other $ 1,278,274 $ (432,260 ) $ 846,014 VantaCore 112,700 (3,082 ) 109,618 Oil and Gas 155,293 (16,898 ) 138,395 Total $ 1,546,267 $ (452,240 ) $ 1,094,027 For the Year Ended December 31, 2014 Carrying Value Accumulated Depletion Net Book Value Coal, Hard Mineral Royalty and Other $ 1,680,169 $ (505,582 ) $ 1,174,587 VantaCore 87,907 (482 ) 87,425 Oil and Gas 560,395 (40,555 ) 519,840 Total $ 2,328,471 $ (546,619 ) $ 1,781,852 Depletion expense related to the Partnership’s mineral rights totaled $80.3 million , $68.6 million and $54.6 million for the year ended December 31, 2015, 2014 and 2013, respectively. Impairment of Mineral Rights The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These procedures are performed throughout the year and consider both quantitative and qualitative information based on historic, current and future performance and are designed to identify impairment indicators. If an impairment indicator is identified, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is primarily determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants. The inputs used by management for fair value measurements include significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement for these types of assets. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require that a separate impairment evaluation be completed on a significant property. During the years ended December 31, 2015, 2014 and 2013, the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense as follows (in thousands): For the years ended December 31, Impaired Asset Description 2015 2014 2013 Oil and gas properties $ 367,576 (1 ) $ — $ — Coal properties 257,468 (2 ) 16,793 (4 ) 734 Hard mineral royalty properties 43,402 (3 ) 3,013 (4 ) Total $ 668,446 $ 19,806 $ 734 (1) We recorded $335.7 million of oil and gas property impairment during the third quarter 2015 and $31.9 million during the fourth quarter of 2015. The fair value measurement of these impaired assets recorded at fair value were $108.0 million at the end of the reporting period. These impairments primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on our acreage. NRP compared net capitalized costs of its oil and natural gas properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and natural gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials. (2) We recorded $1.5 million of coal property impairment during the second quarter of 2015, $247.8 million of coal property impairment during the third quarter of 2015 and $8.2 million during the fourth quarter of 2015. The fair value measurement of these impaired assets recorded at fair value were $0.4 million at the end of the reporting period. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. (3) We recorded $43.4 million of aggregates property impairment during the third quarter of 2015. The fair value measurement of these impaired assets recorded at fair value was $0.0 million at the end of the reporting period. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. (4) We recorded $16.8 million of coal property impairment and $3.0 million impairment of our aggregates properties during the fourth quarter of 2014. Management concluded certain unleased properties were impaired due primarily to the ongoing regulatory environment and continued depressed coal markets with little indications of improvement in the near term. The fair values for those unleased properties were determined for the associated reserves using Level 2 market approaches based upon recent comparable sales and Level 3 expected cash flows. |
Goodwill and Intangible Assets
Goodwill and Intangible Assets | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | Goodwill and Intangible Assets The Partnership's intangible assets consist of the following (in thousands): December 31, 2015 December 31, 2014 Contract intangibles $ 81,109 $ 82,972 Other intangibles 5,076 3,004 Less accumulated amortization (29,258 ) (25,243 ) Total intangible assets, net $ 56,927 $ 60,733 Amortization expense related to the Partnership's intangible assets totaled $4.6 million , $3.6 million and $3.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. During the second quarter of 2014, the Partnership and a lessee amended an aggregates lease in its Coal, Hard Mineral Royalty and Other segment, which led the Partnership to conclude an impairment triggering event had occurred. Fair value of the lease agreement was determined using Level 3 expected cash flows. The resulting impairment expense of $5.6 million is included in Asset impairments on the Consolidated Statements of Comprehensive Income. The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods. For the Year Ended December 31, Estimated Amortization Expense (in thousands) 2016 $ 3,544 2017 3,095 2018 3,108 2019 3,108 2020 3,108 The weighted average remaining amortization period for contract intangibles and other intangibles was 14 years and 31 years , respectively. During the fourth quarter of 2014, $52.0 million of goodwill was added relating to the VantaCore acquisition. This amount represented the preliminary residual value. During 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for VantaCore’s property, plant and equipment, right to mine assets and asset retirement obligations that existed as of the acquisition date. These adjustments decreased goodwill by $46.5 million and resulted in an acquisition date goodwill of $5.5 million . During the fourth quarter of 2015, we evaluated goodwill for impairment and compared the estimated fair value of the VantaCore reporting unit to its carrying amount. The carrying amount exceeded fair value and we recorded a $5.5 million goodwill impairment expense. The lower fair value was primarily a result of the deterioration in certain regional markets in which VantaCore operates causing a decline in future performance levels compared to levels estimated during the purchase price allocation process. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. These estimates were based on current conditions and historical experience applied to develop projections of future operating performance. |
Debt and Debt - Affiliate
Debt and Debt - Affiliate | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Debt and Debt—Affiliate | Debt and Debt—Affiliate As used in this Note 10, references to "NRP LP" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC, or NRP Oil and Gas LLC, wholly owned subsidiaries of NRP LP, or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP LP. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP LP and a co-issuer with NRP LP on the 9.125% senior notes described below. See discussion of Management's Forecast, Strategic Plan and Going Concern Analysis and certain matters involving the Partnership's debt in Note 2. As of December 31, 2015 and 2014, Debt and debt—affiliate consisted of the following (in thousands): December 31, 2015 December 31, 2014 NRP LP Debt: $425 million 9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% $ 422,923 $ 422,167 Opco Debt: $300 million floating rate revolving credit facility, due October 2017 290,000 — $300 million floating rate revolving credit facility, due August 2016 — 200,000 $200 million floating rate term loan, due January 2016 — 75,000 4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018 13,850 18,467 8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019 85,714 107,143 5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020 38,462 46,154 5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021 1,153 1,345 5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 21,600 24,300 4.73% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 60,000 67,500 5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 135,000 150,000 8.92% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 40,909 45,455 5.03% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 148,077 161,538 5.18% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 42,308 46,154 NRP Oil and Gas Debt: Reserve-based revolving credit facility due November 2019 85,000 110,000 Total debt and debt—affiliate 1,384,996 1,475,223 Less: current portion of long-term debt, net (80,983 ) (80,983 ) Total long-term debt and debt—affiliate $ 1,304,013 $ 1,394,240 NRP LP Debt Senior Notes In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300.0 million of 9.125% Senior Notes due 2018 at an offering price of 99.007% of par. Net proceeds after expenses from the issuance of the senior notes were approximately $289.0 million . The senior notes call for semi-annual interest payments on April 1 and October 1 of each year, and will mature on October 1, 2018. In October 2014, NRP LP, together with NRP Finance as co-issuer, issued an additional $125.0 million of its 9.125% Senior Notes due 2018 at an offering price of 99.5% of par. The notes constitute the same series of securities as the existing $300.0 million 9.125% senior notes due 2018 issued in September 2013. Net proceeds of $122.6 million from the additional issuance of the Senior Notes were used to fund a portion of the purchase price of NRP’s acquisition of non-operated working interests in oil and gas assets located in the Williston Basin in North Dakota. The notes call for semi-annual interest payments on April 1 and October 1 of each year and will mature on October 1, 2018. NRP and NRP Finance have the option to redeem the NRP Senior Notes, in whole or in part, at any time on or after April 1, 2016, at fixed redemption prices specified in the indenture governing the NRP Senior Notes (the "NRP Senior Notes Indenture"). Before April 1, 2016, NRP and NRP Finance may redeem all or part of the NRP Senior Notes at a redemption price equal to the sum of the principal plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore, before April 1, 2016, NRP and NRP Finance may on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes with the net proceeds of certain public or private equity offerings at a redemption price of 109.125% of the principal amount of notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the indenture, the holders of the notes may require NRP and NRP Finance to purchase their notes at a purchase price equal to 101% of the principal amount of the notes, plus accrued and unpaid interest, if any. The indenture governing the $425.0 million of senior notes issued by NRP LP (the "Indenture") contains covenants that, among other things, limit the ability of NRP LP and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the Indenture, NRP LP and certain of its subsidiaries generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as defined in the indenture) is at least 2.0 to 1.0 for the four preceding full fiscal quarters. The ability of NRP LP and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of NRP LP and certain of its subsidiaries that is senior to NRP LP’s unsecured indebtedness exceeds certain thresholds. As of December 31, 2015 and December 31, 2014, NRP was in compliance with the terms of the financial covenants contained in its debt agreements. Opco Debt All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of December 31, 2015 and December 31, 2014, Opco was in compliance with the terms of the financial covenants contained in its debt agreements. Revolving Credit Facility In June 2015, Opco entered into a $300.0 million Third Amended and Restated Credit Agreement (the "A&R Revolving Credit Facility"), which amended and restated Opco’s $300.0 million Second Amended and Restated Credit Agreement due August 2016. The A&R Revolving Credit Facility matures on October 2, 2017 , is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of the assets of Opco and its subsidiaries, as further described below. Initially, indebtedness under the A&R Revolving Credit Facility bears interest, at Opco's option, at a rate of either: • the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50% ; or (iii) LIBOR plus 1% , in each case plus 2.375% ; or • a rate equal to LIBOR plus 3.375% Borrowings under the A&R Revolving Credit Facility will bear interest at such rate until the time that Opco delivers quarterly financial statements for the year ended December 31, 2015 to the lenders thereunder. Following such delivery date, indebtedness under the A&R Revolving Credit Facility will bear interest, at Opco's option, at a rate of either: • the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50% ; or (iii) LIBOR plus 1% , in each case plus an applicable margin ranging from 1.50% to 2.50% or • a rate equal to LIBOR plus an applicable margin ranging from 2.50% to 3.50% The weighted average interest rates for the borrowings outstanding under the A&R Revolving Credit Facility for the twelve months ended December 31, 2015 and year ended December 31, 2014 were 2.91% and 1.98% , respectively. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay all amounts outstanding under the A&R Revolving Credit Facility at any time without penalty. The A&R Revolving Credit Facility contains financial covenants requiring Opco to maintain: • a leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the A&R Revolving Credit Facility) not to exceed: • 4.0 to 1.0 for each fiscal quarter ending on or before March 31, 2016; • 3.75 to 1.0 for each subsequent fiscal quarter ending on or before March 31, 2017; and • 3.5 to 1.0 for each fiscal quarter ending on or after June 30, 2017; and • a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0. The A&R Revolving Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of liquidity. The A&R Revolving Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes (as described below). The A&R Revolving Credit Facility is collateralized and secured by liens on certain of Opco’s assets with a carrying value of $709.9 million classified as Land, Mineral rights and Plant and equipment on the Partnership’s Consolidated Balance Sheet as of December 31, 2015. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of VantaCore’s construction aggregates mining operations, and (5) certain of Opco’s coal-related infrastructure assets. Term Loan During 2013, Opco entered into a $200.0 million Term Loan facility (the "Term Loan") with a maturity date of January 23, 2016. The weighted average interest rates for the debt outstanding under the term loan for the twelve months ended December 31, 2015 and 2014 were 2.19% and 2.22% respectively. Opco repaid $101.0 million in principal under the Term Loan during the third quarter of 2013, and repaid an additional $24.0 million during the fourth quarter of 2014. In September 2015, Opco repaid the remaining $75.0 million on the term loan using borrowings under the A&R Revolving Credit Facility. Senior Notes Opco made principal payments of $80.8 million on its senior notes during the year ended December 31, 2015. The Note Purchase Agreements relating to Opco’s senior notes contain covenants requiring Opco to: • Maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters; • not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and • maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0. The 8.38% and 8.92% senior notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. In connection with the entry into the A&R Revolving Credit Facility in June 2015, Opco entered into the Third Amendment to the Note Purchase Agreements (the "NPA Amendment") that provides for the security of the senior notes by the same collateral package pledged by Opco and its subsidiaries to secure the A&R Revolving Credit Facility, as described above. In addition, the NPA Amendment includes a covenant that provides that, in the event Opco or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the A&R Revolving Credit Facility, and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the senior notes and the holders of the senior notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement. NRP Oil and Gas Debt Revolving Credit Facility In August 2013, NRP Oil and Gas entered into a 5 -year, $100.0 million senior secured, reserve-based revolving credit facility in order to fund capital expenditure requirements related to the development of the oil and gas assets in which it owns non-operated working interests. In connection with the closing of the Sanish Field acquisition in November 2014, the credit facility was amended to increase its size to $500.0 million with an initial borrowing base of $137.0 million , and the maturity date thereof was extended to November 2019 . The maximum amount available under the credit facility is subject to semi-annual redeterminations of the borrowing base in May and November of each year, based on the value of the proved oil and natural gas reserves of NRP Oil and Gas, in accordance with the lenders’ customary procedures and practices. NRP Oil and Gas and the lenders each have a right to one additional redetermination each year. In April 2015, the lenders completed their semi-annual redetermination of the borrowing base under the NRP Oil and Gas revolving credit facility and the $137.0 million borrowing base under that facility was redetermined to $105.0 million . In October 2015, the lenders under the NRP Oil and Gas revolving credit facility completed their semi-annual redetermination of the borrowing base under the NRP Oil and Gas revolving credit facility and the $105.0 million borrowing base was redetermined to $88.0 million . The Partnership repaid $25.0 million of outstanding borrowings under the NRP Oil and Gas revolving credit facility during the year ended December 31, 2015. At December 31, 2015 and 2014, there was $85.0 million and $110.0 million respectively, outstanding under the NRP Oil and Gas revolving credit facility. The credit facility is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas is the sole obligor under its revolving credit facility, and neither the Partnership nor any of its other subsidiaries is a guarantor of such facility. The weighted average interest rate for the debt outstanding under the credit facility for the twelve months ended December 31, 2015 and, 2014 was 2.50% and 2.37% , respectively. Indebtedness under the NRP Oil and Gas credit facility bears interest, at the option of NRP Oil and Gas, at either: • the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 0.50% to 1.50%; or • a rate equal to LIBOR, plus an applicable margin ranging from 1.50% to 2.50%. NRP Oil and Gas incurs a commitment fee on the unused portion of the borrowing base under the credit facility at a rate ranging from 0.375% to 0.50% per annum. The NRP Oil and Gas credit facility contains certain covenants, which, among other things, require the maintenance of: • a total leverage ratio (defined as the ratio of the total debt of NRP Oil and Gas to its EBITDAX) of not more than 3.5 to 1.0; and • a minimum current ratio of 1.0 to 1.0. As of December 31, 2015 and 2014, NRP Oil and Gas was in compliance with the terms of the financial covenants contained in its credit facility. Consolidated Principal Payments The consolidated principal payments due are set forth below (in thousands): NRP LP Opco NRP Oil and Gas Senior Notes Senior Notes Credit Facility Credit Facility Total 2016 $ — $ 80,983 $ — $ — $ 80,983 2017 — 80,983 290,000 — 370,983 2018 425,000 (1 ) 80,983 — — 505,983 2019 — 76,366 — 85,000 161,366 2020 — 54,938 — — 54,938 Thereafter — 212,820 — — 212,820 $ 425,000 $ 587,073 $ 290,000 $ 85,000 $ 1,387,073 (1) The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2015 were carried at $422.9 million . |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. The following table (in thousands) shows the carrying amount and estimated fair value of our other financial instruments: December 31, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Assets Contracts receivable—affiliate, current and long-term (1) $ 4,891 $ 4,158 $ 4,870 $ 5,162 Debt and debt—affiliate NRP LP senior notes (2) $ 422,923 $ 277,313 $ 422,167 $ 423,780 Opco senior notes and utility local improvement obligation (1) $ 587,073 $ 383,065 $ 668,056 $ 672,740 Opco revolving credit facility and term loan facility (3) $ 290,000 $ 290,000 $ 275,000 $ 275,000 NRP Oil and Gas revolving credit facility (3) $ 85,000 $ 85,000 $ 110,000 $ 110,000 (1) The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing trading prices near year end. (2) The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near year end. (3) The Level 3 fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Reimbursements to Affiliates of our General Partner The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. Direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by the Partnership’s general partner and its affiliates, Quintana Minerals Corporation and Western Pocahontas Properties Limited Partnership ("WPPLP"). In addition, the Partnership receives non-cash equity contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners' Capital. The Partnership had Accounts payable—affiliates to Quintana Minerals Corporation of $1.1 million and $0.6 million at December 31, 2015 and 2014, respectively, for services provided by Quintana Minerals Corporation to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.3 million and $0.4 million at December 31, 2015 and 2014, respectively. Direct general and administrative expenses charged to the Partnership by its general partner for services performed by WPPLP and Quintana Minerals Corporation are as follows (in thousands): For the Year Ended 2015 2014 2013 Operating and maintenance expenses—affiliates, net 16,031 10,770 8,821 General and administrative—affiliates 5,312 3,258 3,286 The Partnership also leases an office building in Huntington, West Virginia from WPPLP and pays $0.6 million in lease payments each year through December 31, 2018. Cline Affiliates Various companies controlled by Chris Cline, including Foresight Energy LP, lease coal reserves from the Partnership, and the Partnership also leases coal transportation assets to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest (unaudited) in the NRP's general partner, as well as approximately 0.5 million of NRP's common units (unaudited) at December 31, 2015. Coal related revenues from Foresight Energy totaled $86.6 million , $81.5 million and $88.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015 and 2014, the Partnership had Accounts receivable—affiliates from Foresight Energy of $6.4 million and $9.2 million , respectively. As of December 31, 2015, the Partnership had received $82.6 million in minimum royalty payments to date that have been recorded as Deferred revenue—affiliates since they have not been recouped by Foresight Energy. The Partnership owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy's Sugar Camp mine. The lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at December 31, 2015 were $81.2 million with unearned income of $35.4 million , and the net amount receivable was $45.9 million , of which $2.0 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets. Minimum lease payments are $5.0 million per year for the next five years and represent a $1.25 million per quarter in deficiency payment. Total projected remaining payments under the lease at December 31, 2014 were $86.3 million with unearned income of $39.0 million and the net amount receivable was $47.3 million , of which $1.8 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates on the accompanying Consolidated Balance Sheets. The Partnership holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of December 31, 2015 was $4.9 million , of which $1.5 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 2014 was $5.6 million , of which $1.1 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets. During the years ended December 31, 2015, 2014 and 2013, the Partnership recognized a gain of $9.3 million , $5.7 million and $8.1 million , respectively on a reserve swap at Foresight Energy's Williamson mine. The gain is included in Coal, hard mineral royalty and other—affiliates revenues on the Consolidated Statements of Comprehensive Income. The Level 3 fair value of the reserves was estimated using a discounted cash flow model. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates. Long-Term Debt—Affiliate Donald R. Holcomb, one of the Partnership’s directors, is a manager of Cline Trust Company, LLC, which owns approximately 0.54 million of the Partnership’s common units and $20.0 million in principal amount of the Partnership’s 9.125% Senior Notes due 2018. The members of the Cline Trust Company are four trusts for the benefit of the children of Chris Cline, each of which owns an approximately equal membership interest in the Cline Trust Company. Mr. Holcomb also serves as trustee of each of the four trusts. Cline Trust Company, LLC purchased the $20.0 million of the Partnership’s 9.125% Senior Notes due 2018 in the Partnership’s offering of $125.0 million additional principal amount of such notes in October 2014 at the same price as the other purchasers in that offering. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million as of December 31, 2015 and 2014 and is included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet. Quintana Capital Group GP, Ltd. Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in the Partnership's conflicts policy. At December 31, 2015, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp ("Corsa")., a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Coal related revenues from Corsa totaled $3.1 million , $3.0 million and $4.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015, the Partnership had recorded $0.3 million in minimum royalty payments to date as Deferred revenue—affiliates since they have not been recouped by Corsa. The Partnership also had Accounts receivable—affiliates totaling $0.2 million and $0.3 million from Corsa at December 31, 2015 and 2014, respectively. A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. In 2013, Taggart was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. The Partnership owns and leases preparation plants to Forge, which operates the plants. The lease payments were based on the sales price for the coal that was processed through the facilities. The revenues from Taggart prior to the sale to Forge were $1.8 million for the year ended December 31, 2013. WPPLP Production Royalty and Overriding Royalty For the year ended December 31, 2015, the Partnership recorded $0.4 million in operating and maintenance expenses—affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007. These charges were zero for the years ended December 31, 2014 and 2013. The Partnership had Other assets—affiliate from WPPLP of $1.1 million and $0.0 million at December 31, 2015 and December 31, 2014, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The Partnership accrues a liability for legal asset retirement obligations based on an estimate of the timing and amount of settlement. The Partnership accrues for costs involving the ultimate closure of certain of its aggregate mining operations in accordance with its operating permits. These charges include costs of land reclamation, water drainage, and incremental direct administration cost of closing the operations. The Partnership also accrues for estimated costs relating to plugging wells in which it has a non-operation working interest. Upon initial recognition of an asset retirement obligation the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion, and amortization and the initial costs are depleted over the useful lives of the related assets. The following table presents a reconciliation (in thousands) of the beginning and ending carrying amounts of the Partnership’s asset retirement obligations. The short-term balance of $0.0 million and $0.1 million at December 31, 2015 and 2014, respectively, is included in Accrued liabilities and the remaining balance is included in Other non-current liabilities in the Consolidated Balance Sheets. The Partnership does not have any assets that are legally restricted for purposes of settling these obligations. For the Years Ended December 31, 2015 2014 Balance, January 1 $ 4,973 $ 39 Liabilities incurred in current period, including aquisitions 5 4,697 Accretion expense 284 237 Acquisition related purchase price adjustments (2,280 ) — Balance, December 31 $ 2,982 $ 4,973 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Legal The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations. The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming, formerly OCI Wyoming, requires the Partnership to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement are met at Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014 and 2015, the Partnership paid $0.5 million and $3.8 million , respectively, in contingent consideration to Anadarko. As of December 31, 2015, the Partnership has estimated and recorded $7.2 million as an accrued liability on its consolidated Balance Sheet, payable in the first quarter of 2016 with respect to 2015. The Partnership has no obligation to pay contingent consideration with respect to any period after 2015. In March 2014, Anadarko gave the Partnership written notice that it believed certain reorganization transactions conducted in 2013 within the OCI organization triggered an acceleration of the Partnership’s obligation under the purchase agreement with Anadarko to pay the additional contingent consideration in full and demanded immediate payment of such amount. The Partnership disagreed with Anadarko’s position in a written response provided to them in April 2014. In April 2015, Anadarko sent a written request for additional information regarding the OCI reorganization and indicated that they were still considering this claim against the Partnership. The Partnership responded in writing in May 2015 and does not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration. The Partnership will continue to engage in discussions with Anadarko to resolve the issue to the extent necessary. However, if Anadarko were to pursue and prevail on such a claim, the Partnership would be required to pay an amount to Anadarko in excess of the amounts already paid, together with the $7.2 million accrual described above, up to the maximum amount of the additional contingent consideration, minus a deductible. Under the purchase agreement, the maximum cumulative amount of additional contingent consideration is an amount equal to the net present value of $50.0 million . Any additional amount paid by the Partnership would be considered to be additional acquisition consideration and added to Equity and other unconsolidated investments. Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property had been closed, the property had been reclaimed, and the state reclamation bond had been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations. A subsidiary of the Partnership has been named as a defendant in one of these lawsuits. Given the early stage of this ongoing litigation, the Partnership currently cannot reasonably estimate a range of potential loss, if any, related to this matter. Hillsboro/Deer Run On November 24, 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled. In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. The effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with respect to the second, third and fourth quarters of 2015 resulted in a $16.2 million cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected. Environmental Compliance The operations the Partnership’s lessees’ conduct on its properties, as well as the aggregates/industrial minerals and oil and gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. See "Item 1. Business—Regulation and Environmental Matters." As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership makes regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. The Partnership believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply with environmental laws and regulations to have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31, 2015. The Partnership is not associated with any environmental contamination that may require remediation costs. However, the Partnership’s lessees do conduct reclamation work on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, the Partnership is not responsible for the costs associated with these reclamation operations. As an owner of working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities, including environmental liabilities, arising from uninsured and underinsured events. The Partnership is also responsible for losses and liabilities, including environmental liabilities that may arise from uninsured and underinsured events at its VantaCore operations. |
Major Lessees
Major Lessees | 12 Months Ended |
Dec. 31, 2015 | |
Leases [Abstract] | |
Major Lessees | Major Lessees Revenues from lessees that exceeded ten percent of total revenues and other income for any of the periods presented below are as follows (in thousands except for percentages): For the Years Ended December 31, 2015 2014 2013 Revenues Percent Revenues Percent Revenues Percent Foresight Energy $ 86,614 17.7 % $ 81,546 20.4 % $ 88,432 24.7 % Alpha Natural Resources $ 34,364 7.0 % $ 48,783 12.2 % $ 55,147 15.4 % All of the revenue related to the customers above is included in revenues of the Coal, Hard Mineral Royalty and Other segment. The Partnership had a significant concentration of revenues with Foresight Energy and Alpha Natural Resources. The exposure is currently spread out over a number of different mining operations and leases. During the year ended December 31, 2015, total revenues and other income from Alpha Natural Resources included a $6.0 million non-recurring lease assignment fee. |
Long-Term Incentive Plans
Long-Term Incentive Plans | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Long-Term Incentive Plans | Long-Term Incentive Plans GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the "Long-Term Incentive Plan") for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant. Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a unit of our common units upon each vesting. The Partnership records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted quarterly for any changes in the Partnership’s unit price. Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise. In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting. A summary of activity in the outstanding grants during 2015 is as follows (in thousands): Phantom Units Outstanding grants at January 1, 2015 115 Grants during the period 52 Grants vested and paid during the period (29 ) Forfeitures during the period (12 ) Outstanding grants at December 31, 2015 126 Grants typically vest at the end of a four -year period and are paid in cash upon vesting. The Partnership recorded a credit to general and administrative expenses related to its Long-Term Incentive Plan of $3.4 million for the year ended December 31, 2015, due to the decline in the market price of the Partnership's common units during 2015. For the years ended December 31, 2014 and 2013 the Partnership recorded G&A expenses of $1.0 million and $9.6 million , respectively. In connection with the Long-Term Incentive Plans, payments are typically made during the first quarter of the year. Payments of $4.4 million , $6.5 million and $7.0 million were made during the years ended December 31, 2015, 2014, and 2013, respectively. The grant date fair value was $4.2 million , $6.6 million and $7.8 million for awards in 2015, 2014 and 2013, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at December 31, 2015 and December 31, 2014, was $0.7 million and $5.2 million , respectively. |
Supplementary Unrestricted Subs
Supplementary Unrestricted Subsidiary Information | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Supplementary Unrestricted Subsidiary Information | Supplementary Unrestricted Subsidiary Information The following is presented as supplementary data as required by the Indenture governing the NRP Senior Notes due 2018 (the "Indenture"). As described in Note 2. Summary of Significant Accounting Policies, in February 2016, the Partnership designated NRP Oil and Gas, a wholly owned subsidiary of NRP, as an Unrestricted Subsidiary for purposes of the Indenture. In addition, the Partnership has designated BRP LLC, a joint venture in which the Partnership owns a 51% interest, and Coval Leasing Company, LLC, a wholly owned subsidiary of BRP LLC, as Unrestricted Subsidiaries for purposes of the Indenture. The information below may not necessarily be indicative of the results of operations, or financial position had the subsidiaries operated as independent entities. There were no transactions between the Partnership and its Restricted Subsidiaries and its Unrestricted Subsidiaries. In accordance with the requirements of the Indenture, the following condensed consolidating financial information presents the financial condition and results of operations of the Partnership and its Restricted Subsidiaries and its Unrestricted Subsidiaries: CONDENSED CONSOLIDATING BALANCE SHEETS (in thousands) December 31, 2015 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total ASSETS Current assets (including affiliates) $ 21,540 $ 99,589 $ 121,129 Mineral rights, net 134,445 959,582 1,094,027 Equity in unconsolidated investment — 261,942 261,942 Other non-current assets (including affiliates) 2,287 204,690 206,977 Total assets $ 158,272 $ 1,525,803 $ 1,684,075 LIABILITIES AND CAPITAL Current portion of long-term debt, net — 80,983 80,983 Other current liabilities (including affiliates) 7,351 48,313 55,664 Long-term debt, net (including affiliate) 85,000 1,219,013 1,304,013 Other non-current liabilities (including affiliates) 4,703 165,770 170,473 Partners' capital 64,663 11,673 76,336 Non-controlling interest (3,445 ) 51 (3,394 ) Total liabilities and capital $ 158,272 $ 1,525,803 $ 1,684,075 December 31, 2014 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total ASSETS Current assets (including affiliates) $ 23,842 $ 112,276 $ 136,118 Mineral rights, net 446,938 1,334,914 1,781,852 Equity in unconsolidated investment — 264,020 264,020 Other non-current assets (including affiliates) 4,156 258,578 262,734 Total assets $ 474,936 $ 1,969,788 $ 2,444,724 LIABILITIES AND CAPITAL Current portion of long-term debt, net — 80,983 80,983 Other current liabilities (including affiliates) 16,212 50,736 66,948 Long-term debt, net (including affiliate) 110,000 1,284,240 1,394,240 Other non-current liabilities (including affiliates) 5,193 177,205 182,398 Partners' capital 344,232 376,573 720,805 Non-controlling interest (701 ) 51 (650 ) Total liabilities and capital $ 474,936 $ 1,969,788 $ 2,444,724 CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) Year Ended December 31, 2015 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total Revenues $ 56,091 $ 432,758 $ 488,849 Operating expenses 361,166 605,594 966,760 Loss from operations (305,075 ) (172,836 ) (477,911 ) Other expense 4,065 89,744 93,809 Net loss (309,140 ) (262,580 ) (571,720 ) Add: comprehensive loss from unconsolidated investment and other — (1,693 ) (1,693 ) Comprehensive loss $ (309,140 ) $ (264,273 ) $ (573,413 ) Year Ended December 31, 2014 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total Revenues $ 56,840 $ 342,912 $ 399,752 Operating expenses 41,754 169,079 210,833 Income from operations 15,086 173,833 188,919 Other expense 662 79,427 80,089 Net income 14,424 94,406 108,830 Add: comprehensive loss from unconsolidated investment and other — (81 ) (81 ) Comprehensive income $ 14,424 $ 94,325 $ 108,749 Year Ended December 31, 2013 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total Revenues $ 14,386 $ 343,731 $ 358,117 Operating expenses 8,812 113,069 121,881 Income from operations 5,574 230,662 236,236 Other expense 39 64,119 64,158 Net income 5,535 166,543 172,078 Add: comprehensive income from unconsolidated investment and other — 65 65 Comprehensive income $ 5,535 $ 166,608 $ 172,143 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events The following represents material events that have occurred subsequent to December 31, 2015 through the time of the Partnership’s filing of its Annual Report on Form 10-K with the SEC: Distribution Declared On February 12, 2016, the Partnership paid a distribution of $0.45 per unit to unitholders of record on February 5, 2016. Reverse Unit Split On January 26, 2016, the board of directors of our general partner approved a 1-for- 10 reverse split on our common units, effective following market close on February 18, 2016. Pursuant to the authorization provided, the Partnership completed the 1-for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange on February 18, 2016. As a result of the reverse unit split, every 10 units of issued and outstanding common units were combined into one issued and outstanding common unit, without any change in the par value per unit. The reverse unit split reduced the number of common units outstanding from 122.3 million units to approximately 12.2 million units. All units and per unit data included in these consolidated financial statements have been retroactively restated to reflect the reverse unit split. Oil and Gas Royalty Properties Sale In February 2016, the Partnership sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $36.6 million in net cash proceeds and recorded a gain of $20.3 million . The sale included royalty and overriding royalty interests in approximately 765 gross producing wells as of December 31, 2015 and approximately 10% of our estimated proved reserves as of December 31, 2015, or 1,094 MBoe. The effective date of the sale was January 1, 2016. Aggregate Royalty Properties Sale In February 2016, we sold the aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee, which comprised approximately 27% , or 139 million tons, of our estimated aggregates reserves as of December 31, 2015 for $9.8 million in net cash proceeds and recorded a gain of $1.6 million . The effective date of the sale was February 1, 2016. |
Supplemental Information on Oil
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) | The Partnership prepared the following oil and gas information in accordance with the authoritative guidance for oil and gas extractive activities. Capitalized Costs (in thousands): For the Years Ended 2015 2014 Proven properties $ 199,404 $ 392,153 Unproven properties — 46,400 Total property, plant, and equipment 199,404 438,553 Accumulated depreciation, depletion, and amortization (60,542 ) (18,993 ) Net capitalized costs $ 138,862 $ 419,560 Costs incurred for property acquisitions, exploration, and development (in thousands): For the Years Ended 2015 2014 Property acquisitions Proven properties $ — $ 298,627 Unproven properties — 40,800 Development 29,080 5,340 Total $ 29,080 $ 344,767 Results of Operations for Producing Activities (in thousands): For the Years Ended 2015 2014 Production revenue $ 49,201 $ 48,834 Royalty and overriding royalty revenue (1) 4,364 10,732 Total oil and gas related revenue 53,565 59,566 Operating costs and expense: Depreciation, depletion and amortization 40,772 23,936 Property, franchise and other taxes 5,210 5,529 Production costs 12,871 12,544 Impairment of oil and gas properties 367,576 — Total operating costs and expense 426,429 42,009 Total income from operations $ (372,864 ) $ 17,557 (1) Includes $0.4 million and $1.9 million for the years ended December 31, 2015 and 2014, respectively of nonproduction revenues including lease bonus payments Estimated Proved Reserves Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term "reasonable certainty" implies a high degree of confidence that the quantities of crude oil, natural gas liquids and/or natural gas actually recovered will equal or exceed the estimate. The Partnership estimated proved reserves as of December 31, 2015 and 2014 were prepared by Netherland, Sewell & Associates, Inc., the Partnership’s independent reserve engineer. To achieve reasonable certainty, Netherland Sewell employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the Partnership’s proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole and production data and well test data. Netherland Sewell prepared its report covering properties representing 100% of the Partnership’s estimated proved reserves as of December 31 2015 and 2014. Prices were calculated using the unweighted average of the first-day-of-the-month pricing for the twelve months ended December 31, 2015 and 2014. These prices were then adjusted for transportation and other costs. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reserve engineers often arrive at different estimates for the same properties. A copy of Netherland Sewell’s summary report is included as Exhibit 99.2 to this Annual Report on Form 10-K. The following tables shows our estimated domestic proved reserves and reserve additions and revisions: Crude Oil (MBbl) NGLs (MBbl) Natural Gas (MMcf)(2) Total Proved Reserves (MBoe)(3) December 31, 2014 9,983 1,229 14,370 13,607 Revisions of previous estimates (1,451 ) 89 701 (1,244 ) Extensions, discoveries and other additions 776 60 541 926 Sales of properties (98 ) — (62 ) (108 ) Production (1,136 ) (156 ) (2,226 ) (1,663 ) December 31, 2015 (1) 8,074 1,222 13,324 11,518 Proved developed reserves as of December 31, 2015 7,862 1,196 13,157 11,251 Proved undeveloped reserves as of December 31, 2015 212 26 167 267 Proved developed reserves as of December 31, 2014 8,930 1,098 13,161 12,221 Proved undeveloped reserves as of December 31, 2014 1,053 131 1,209 1,386 (1) Includes reserves attributable to the Partnership's 51% member interest in BRP LLC. (2) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. (3) Includes 10,063 MBoe of estimated proved reserves attributable to the Partnership’s non-operated working interests in oil and natural gas properties in the Williston Basin, approximately 3% of which were proved undeveloped reserves. The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows (in thousands): For the Years Ended 2015 2014 Future cash inflows $ 364,352 $ 920,454 Less related future: Production costs (164,649 ) (312,666 ) Development and abandonment costs (7,826 ) (20,072 ) Future net cash flows before 10% discount 191,877 587,716 Discount to present value at a 10% annual rate (75,524 ) (282,519 ) Total standardized measure of discounted net cash flows $ 116,353 $ 305,197 The table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during the year ended December 31, 2015 (in thousands): Beginning of the period $ 305,197 Revisions to previous estimates: Changes in prices and costs (188,946 ) Changes in quantities (11,750 ) Changes in future development costs (12,202 ) Previously estimated development costs incurred during the period 29,080 Additions to proved reserves from extensions, discoveries and improved recovery, less related costs 11,928 Purchases and sales of reserves in place, net (3,851 ) Accretion of discount 31,795 Sales of oil and gas, net of production costs (35,112 ) Production timing and other (9,786 ) Net increase (decrease) (188,844 ) End of period $ 116,353 |
Supplemental Quarterly Informat
Supplemental Quarterly Information (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Supplemental Quarterly Information (Unaudited) | Quarterly Financial Data The following table summarizes quarterly financial data for 2015 and 2014 (in thousands, except per unit data): 2015 First Second Third Fourth Total Total revenues and other income $ 109,677 $ 137,630 $ 125,479 $ 116,063 $ 488,849 Depreciation, depletion and amortization $ 25,392 $ 30,660 $ 26,624 $ 18,152 $ 100,828 Asset impairment $ — $ 3,803 (1) $ 626,838 (2) $ 50,953 (3) $ 681,594 Income (loss) from operations $ 40,417 $ 55,920 $ (576,290 ) $ 2,042 $ (477,911 ) Net income (loss) $ 17,489 $ 32,578 $ (600,001 ) $ (21,786 ) $ (571,720 ) Net income (loss) per limited partner unit $ 1.40 $ 2.50 $ (47.90 ) $ (1.75 ) $ (45.75 ) Weighted average number of common units outstanding 12,230 12,230 12,230 12,230 12,230 2014 First Second Third Fourth Total Total revenues and other income $ 80,309 $ 90,561 $ 91,609 $ 137,273 $ 399,752 Depreciation, depletion and amortization $ 14,647 $ 16,350 $ 18,621 $ 30,258 $ 79,876 Asset impairment $ — $ 5,624 (4) $ — $ 20,585 (5) 26,209 Income from operations $ 52,439 $ 50,403 $ 55,027 $ 31,050 $ 188,919 Net income $ 32,605 $ 31,407 $ 36,173 $ 8,645 $ 108,830 Net income per limited partner unit $ 2.90 $ 2.80 $ 3.20 $ 0.70 $ 9.42 Weighted average number of common units outstanding 10,985 11,040 11,124 12,145 11,326 (1) During the second quarter of 2015 we recorded a $2.3 million impairment expense related to a coal preparation plant and a $1.5 million impairment expense related to coal mineral rights. (2) During the third quarter of 2015 we recorded $335.7 million of oil and gas property impairment, $247.8 million of coal property impairment and $43.4 million of aggregates property impairment. (3) During the fourth quarter of 2015 we recorded $31.9 million of oil and gas property impairment, $8.2 million of coal property impairment, $5.5 million of goodwill impairment, $4.7 million related to coal processing and transportation assets as well as obsolete equipment at our Logan office as well as a $0.7 million impairment expense related to obsolete plant and equipment at VantaCore. (4) During the second quarter of 2014, we recorded $5.6 million of intangible asset impairment related to an aggregates lease. (5) During the fourth quarter of 2014, we recorded $16.8 million of coal property impairment and $3.0 million of aggregates property impairment as well as $0.8 million in impairment expense related to a coal preparation plant. that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with International Paper Company controlled by the Partnership. The Partnership has an equity investment through which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the investee’s activities which is accounted for using the equity method. Intercompany transactions and balances have been eliminated. |
Recasting of Certain Prior Period Information | Recasting of Certain Prior Period Information Due to the acquisitions that diversified our natural resource asset base, effective for the quarter ended December 31, 2015, management revised the Partnership's operating segments to align with its management structure and organizational responsibilities and revised the information that its chief operating decision maker regularly reviews for purposes of allocating resources and assessing performance. As a result, effective for the quarter ended December 31, 2015, we report our financial performance based on new segments as described in "Note 3. Segment Information". We recast certain prior period amounts to conform to the way we internally manage and monitor segment performance. This change had no impact on the Partnership's consolidated financial position, net income (loss) or cash flows. In addition, certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation. Prior year general and administrative charges that were allocated to the operating segments have been reclassified to Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. |
Reverse Unit Split | Reverse Unit Split On January 26, 2016, the board of directors of our general partner approved a 1-for-10 reverse split on our common units, effective following market close on February 17, 2016. Pursuant to the authorization provided, the Partnership completed the 1-for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange on February 18, 2016. As a result of the reverse unit split, every 10 outstanding common units were combined into one common unit. The reverse unit split reduced the number of common units outstanding from 122.3 million units to approximately 12.2 million units. All units and per unit data included in these consolidated financial statements have been retroactively restated to reflect the reverse unit split. |
Use of Estimates | Use of Estimates Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income during the reporting period. Actual results could differ from those estimates. |
Business Combinations | Business Combinations For purchase acquisitions accounted for as business combinations, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. |
Fair Value | Fair Value The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See "Note 11. Fair Value Measurements." There are three levels of inputs that may be used to measure fair value: • Level 1—Quoted prices in active markets for identical assets or liabilities. • Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. • Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents. |
Accounts Receivable | Accounts Receivable Accounts receivable from the Partnership’s lessees and customers do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying Consolidated Balance Sheets. The Partnership evaluates the collectability of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its accounts receivable and when it becomes aware of a specific lessee’s or customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s or customer’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. The reserve is recognized as a reduction in the accounts receivable and an increase in operating and maintenance expenses or operating and maintenance expenses—affiliates. Accounts are charged off when collection efforts are complete and future recovery is doubtful. |
Inventory | Inventory Inventories are stated at the lower of cost or market. The cost of aggregates and asphalt components such as stone, sand, and recycled and liquid asphalt is determined by the first-in, first-out (FIFO) method. Cost includes all direct materials, direct labor and related production overheads based on normal operating capacity. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Partnership’s aggregates operations. |
Plant and Equipment | Plant and Equipment Plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the asset acquired and consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at cost and are depreciated on a straight-line basis over their useful lives generally as follows: Years Buildings and improvements 20 to 40 Machinery and equipment 5 to 12 Leasehold improvements Life of Lease The Partnership begins capitalizing mine development costs at its aggregates operations at a point when reserves are determined to be proven or probable, economically mineable and when demand supports investment in the market. Capitalization of these costs ceases when production commences. Mine development costs are amortized based on production over the estimated life of mineral reserves and amortization is included as a component of depreciation expense. |
Mineral Rights | Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein. The Partnership owns royalty and non-operated working interests in oil and natural gas reserves, all of which are located in the U.S. The Partnership does not determine whether or when to develop reserves. The Partnership uses the successful efforts method to account for its working interest in oil and gas properties. Oil and gas non-operated working interests are depleted on a unit-of-production basis. The depletion rate is adjusted annually based upon the amount of remaining reserves as determined by independent third party petroleum engineers. Oil and gas royalty interests are depleted on a straight-line basis over 30 years or the life of the asset, whichever is shorter. |
Intangible Assets | Intangible Assets The Partnership’s intangible assets consist primarily of contracts that at acquisition were more favorable for the Partnership than prevailing market rates, known as above-market contracts. The estimated fair values of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis except that a minimum amortization is calculated on a straight-line basis for temporarily idled assets. |
Asset Impairment | Asset Impairment We have developed procedures to periodically evaluate our long-lived assets for possible impairment. These procedures are performed throughout the year and are based on historic, current and future performance and are designed to be early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property. As a result of the continued weakness in the coal markets and the potential for further declines in oil and natural gas prices, we intend to closely monitor our coal and oil and gas assets, and the impairment evaluation process may be completed more frequently if deemed necessary. Future impairment analyses could result in downward adjustments to the carrying value of our assets. During 2015, we recorded impairment expense of $676.1 million on certain of our mineral rights within our Coal, Hard Mineral Royalty and Other and Oil and Gas segments as well as plant and equipment within our Coal, Hard Mineral Royalty and Other and VantaCore segments. We evaluate our equity investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. In accordance with FASB accounting and disclosure guidance for goodwill, we test our recorded goodwill for impairment annually or more often if indicators of potential impairment exist, by determining if the carrying value of a reporting unit exceeds its estimated fair value. Factors that could trigger an interim impairment test include, but are not limited to, underperformance relative to historical or projected future operating results or significant changes in our overall business, industry, or economic trends. |
Revenue Recognition | Revenue Recognition Coal, Hard Mineral Royalty and Other Revenues. Coal and hard mineral royalty revenues are recognized on the basis of tons of mineral sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons of material processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, we receive a fixed price per ton for all material transported on the beltlines. Most of the Partnership’s coal and aggregates lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments. Soda Ash Revenues. We account for non-marketable investments using the equity method of accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for our investment in Ciner Wyoming using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of the fair value of the underlying net assets of equity method investees is hypothetically allocated first to identified tangible assets and liabilities, then to finite-lived intangibles or indefinite-lived intangibles and the balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived intangibles, if any, and goodwill are not amortized. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income. Our carrying value in Ciner Wyoming is reflected in the caption "Equity in unconsolidated investments" in our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity in earnings of Ciner Wyoming." These earnings are generated from natural resources, which are considered part of our core business activities consistent with its directly owned revenue generating activities. Investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the proportionate share of the investee’s book value, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets. VantaCore Revenues. Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to the estimated total costs for each contract. That method is used since we consider total cost to be the best available measure of progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred. Oil and Gas Revenues . Oil and gas related revenues consist of revenues from our non-operated working interests, royalties and overriding royalties. Revenues related to our non-operated working interests in oil and gas assets are recognized on the basis of our net revenue interests in hydrocarbons produced. Our revenues fluctuate based on changes in the market prices for oil and natural gas, the decline in production from producing wells, and other factors affecting the third-party oil and natural gas exploration and production companies that operate our wells, including the cost of development and production. Oil and gas royalty revenues are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Also, included within oil and gas royalties are lease bonus payments, which are generally paid upon the execution of a lease. |
Property Taxes | Property Taxes The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in Coal, Hard Mineral Royalty and Other revenues and in Operating and maintenance expenses, respectively, in the Consolidated Statements of Comprehensive Income. |
Transportation Revenue and Expense | Transportation Revenue and Expense The Company records transportation revenue and pays transportation costs to a Foresight affiliate to operate equipment on behalf of the Company. The revenue and expenses related to these transactions are recorded as Coal, Hard Mineral Royalty and Other—affiliates revenues and Operating and maintenance expenses—affiliates in the Consolidated Statements of Comprehensive Income. Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as Coal, Hard Mineral Royalty and Other revenues and Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income. |
Asset Retirement Costs and Obligations | Asset Retirement Costs and Obligations The Partnership accrues for mine closure, reclamation as well as plugging and abandonment of its oil and gas non-operated working interests in accordance with authoritative guidance related to accounting for asset retirement costs and obligations. This guidance requires the fair value of an obligation be recognized in the period it is incurred, if the fair value can be reasonably estimated. The Partnership recognizes an asset and liability related to the present value of future estimated costs. Depreciation or depletion of the capitalized asset retirement cost is determined based upon the underlying asset being retired in the future. Accretion of the asset retirement obligation is recognized over time and will increase as the obligation becomes more near term. It is reasonably possible that the estimates related to asset retirement and environmental obligations may change in the future. See "Note 13. Asset Retirement Obligations." |
Unit-Based Compensation | Unit-Based Compensation We have awarded unit-based compensation in the form of phantom units that are more fully described in Note 16. Long-Term Incentive Plans." A summary of our accounting policy for unit-based awards follows. The Partnership accounts for awards relating to its Long-Term Incentive Plan using the fair value method, which requires the Partnership to estimate the fair value of the grant, and charge or credit the estimated fair value to expense over the requisite service period of the grant based on fluctuations in the Partnership’s common unit price. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability and the fair value is recalculated at each reporting date over the service or vesting period of the grant. See "Note 16. Long-Term Incentive Plans." |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These costs are amortized over the term of the debt. Deferred financing costs are included in Other Assets on the Partnership's Consolidated Balance Sheets. |
Income Taxes | Income Taxes No provision for income taxes related to the operations of the Partnership has been included in the accompanying financial statements because, as a partnership, it is not subject to federal or material state income taxes and the tax effect of its activities accrues to the unitholders. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities. |
Lessee Audits and Inspections | Lessee Audits and Inspections The Partnership periodically audits lessee information by examining certain records and internal reports of its lessees. The Partnership’s regional managers also perform periodic mine inspections to verify that the information that has been reported to the Partnership is accurate. The audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to the Partnership and the actual results from each property. Audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the revenue was initially recorded. Typically there are no material adjustments from this process. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board ("FASB") amended its guidance on revenue recognition. The core principle of this amendment is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted for reporting periods beginning after December 15, 2016, including interim reporting periods within that period. This guidance can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows. In August 2014, the FASB issued guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance, but will not impact the Partnership's financial position or results of operations. The Partnership is reviewing its policies and processes to ensure compliance with this new guidance. In April 2015, the FASB issued authoritative guidance which intended to simplify the presentation of debt issuance costs in financial statements. This guidance requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This guidance is effective for annual reporting periods beginning after December 15, 2016. Early adoption is permitted. This guidance will be applied retrospectively to each prior period presented. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated balance sheets. In July 2015, the FASB issued authoritative guidance which intended to simplify the measurement of inventory. This guidance requires an entity to measure inventory at the lower of cost or net realizable value. The amendments do not apply to inventory that is measured using last-in, first-out or the retail inventory method. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with early adoption permitted. This guidance should be applied on a prospective basis. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows. In February 2016, FASB issued authoritative lease guidance that establishes a right-of-use ("ROU") model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The main difference between the current requirement under GAAP and the ROU model is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows. |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Plant and Equipment Useful Lives | These assets are recorded at cost and are depreciated on a straight-line basis over their useful lives generally as follows: Years Buildings and improvements 20 to 40 Machinery and equipment 5 to 12 Leasehold improvements Life of Lease |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands): Operating Segments For the Year Ended Coal, Hard Mineral Royalty and Other Soda Ash VantaCore Oil and Gas Corporate and Financing Total December 31, 2015 Revenues (including affiliates) $ 246,353 $ 49,918 $ 139,013 $ 53,565 $ — $ 488,849 Intersegment revenues (expenses) 21 — (21 ) — — — Depreciation, depletion and amortization 44,478 — 15,578 40,772 — 100,828 Asset impairment 307,800 — 6,218 367,576 — 681,594 Interest expense, net — — — — (93,809 ) (93,809 ) Net income (loss) (138,388 ) 49,918 272 (377,365 ) (106,157 ) (571,720 ) Capital expenditures 428 — 14,039 30,457 — 44,924 Total assets at December 31, 2015 1,047,922 261,942 200,348 158,862 15,001 1,684,075 December 31, 2014 Revenues (including affiliates) $ 256,719 $ 41,416 $ 42,051 $ 59,566 $ — $ 399,752 Depreciation, depletion and amortization 52,645 — 3,296 23,935 — 79,876 Asset impairment 26,209 — — — — 26,209 Interest expense, net — — — — (80,089 ) (80,089 ) Net income (loss) 143,678 41,416 32 14,338 (90,634 ) 108,830 Capital expenditures 5,351 — 171,116 359,851 — 536,318 Total assets at December 31, 2014 1,403,762 264,020 219,658 540,713 16,571 2,444,724 December 31, 2013 Revenues (including affiliates) $ 306,851 $ 34,186 $ — $ 17,080 $ — $ 358,117 Depreciation, depletion and amortization 58,502 — — 5,875 — 64,377 Asset impairment 734 — — — — 734 Interest expense, net — — — — (64,158 ) (64,158 ) Net income (loss) 211,590 34,186 — 5,198 (78,896 ) 172,078 Capital expenditures — 293,085 — 75,019 — 368,104 Total assets at December 31, 2013 1,520,428 269,338 — 189,211 12,879 1,991,856 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisition Pro Forma Financial Information | The following unaudited pro forma financial information (in thousands) presents a summary of the Partnership’s consolidated revenues, net income and net income per common unit for the twelve months ended December 31, 2014 and 2013 assuming the VantaCore and Sanish Field acquisitions had been completed as of January 1, 2013, including adjustments to reflect the values assigned to the net assets acquired: For the Years ended December 31, 2014 2013 Total revenues and other income $ 533,517 $ 579,933 Net income $ 122,319 $ 197,164 Basic and diluted net income per common unit $ 9.90 $ 16.00 |
VantaCore Partners LP | |
Schedule of Adjustments to the Estimated Fair Value | The accounting for the VantaCore acquisition is summarized as follows (in thousands): October 1, 2014 Consideration Cash $ 168,978 NRP common units 31,604 Total consideration given $ 200,582 Allocation of Purchase Price Current assets $ 37,222 Land, property and equipment 59,946 Mineral rights 111,500 Other assets 4,347 Current liabilities (16,953 ) Asset retirement obligation (1,005 ) Goodwill 5,525 Fair value of net assets acquired $ 200,582 |
Sanish Field [Member] | |
Schedule of Adjustments to the Estimated Fair Value | The accounting for the Sanish Field acquisition was completed in the second quarter of 2015 without significant changes during the measurement period and is summarized as follows (in thousands): November 12, 2014 Consideration Cash $ 339,093 Allocation of Purchase Price Mineral rights - proven oil and gas properties 298,293 Mineral rights - probable and possible oil and gas resources 40,800 Fair value of net assets acquired $ 339,093 |
Equity Investment (Tables)
Equity Investment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of Summarized Financial Information | Our equity in the earnings of Ciner Wyoming is summarized as follows (in thousands): For the Year Ended December 31, 2015 2014 2013 Income allocation to NRP’s equity interests $ 54,709 $ 47,354 $ 37,036 Amortization of basis difference (4,791 ) (5,938 ) (2,850 ) Equity in earnings of unconsolidated investment $ 49,918 $ 41,416 $ 34,186 The results of Ciner Wyoming’s operations are summarized as follows (in thousands): For the Year Ended December 31, 2015 2014 2013 Sales $ 486,393 $ 465,032 $ 442,132 Gross profit 131,493 118,439 94,299 Net Income 111,650 96,640 79,655 The financial position of Ciner Wyoming is summarized as follows (in thousands): For the Year Ended December 31, 2015 2014 Current assets $ 144,695 $ 179,851 Noncurrent assets 233,845 223,053 Current liabilities 43,018 47,704 Noncurrent liabilities 116,808 149,192 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Inventory Disclosure [Abstract] | |
Components of Inventories | The components of inventories at December 31, 2015 and 2014 are as follows (in thousands): December 31, December 31, Aggregates $ 7,056 $ 4,596 Supplies and parts 779 1,218 Total inventory $ 7,835 $ 5,814 |
Plant and Equipment (Tables)
Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Plant and Equipment | The Partnership’s plant and equipment consist of the following (in thousands): December 31, 2015 December 31, 2014 Plant and equipment at cost $ 92,203 $ 89,759 Construction in process 1,074 457 Less accumulated depreciation (32,038 ) (30,123 ) Total plant and equipment, net $ 61,239 $ 60,093 |
Mineral Rights (Tables)
Mineral Rights (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Mineral Rights | The Partnership’s mineral rights consist of the following (in thousands): For the Year Ended December 31, 2015 Carrying Value Accumulated Depletion Net Book Value Coal, Hard Mineral Royalty and Other $ 1,278,274 $ (432,260 ) $ 846,014 VantaCore 112,700 (3,082 ) 109,618 Oil and Gas 155,293 (16,898 ) 138,395 Total $ 1,546,267 $ (452,240 ) $ 1,094,027 For the Year Ended December 31, 2014 Carrying Value Accumulated Depletion Net Book Value Coal, Hard Mineral Royalty and Other $ 1,680,169 $ (505,582 ) $ 1,174,587 VantaCore 87,907 (482 ) 87,425 Oil and Gas 560,395 (40,555 ) 519,840 Total $ 2,328,471 $ (546,619 ) $ 1,781,852 |
Schedule of Impairment Expense | During the years ended December 31, 2015, 2014 and 2013, the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense as follows (in thousands): For the years ended December 31, Impaired Asset Description 2015 2014 2013 Oil and gas properties $ 367,576 (1 ) $ — $ — Coal properties 257,468 (2 ) 16,793 (4 ) 734 Hard mineral royalty properties 43,402 (3 ) 3,013 (4 ) Total $ 668,446 $ 19,806 $ 734 (1) We recorded $335.7 million of oil and gas property impairment during the third quarter 2015 and $31.9 million during the fourth quarter of 2015. The fair value measurement of these impaired assets recorded at fair value were $108.0 million at the end of the reporting period. These impairments primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on our acreage. NRP compared net capitalized costs of its oil and natural gas properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and natural gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials. (2) We recorded $1.5 million of coal property impairment during the second quarter of 2015, $247.8 million of coal property impairment during the third quarter of 2015 and $8.2 million during the fourth quarter of 2015. The fair value measurement of these impaired assets recorded at fair value were $0.4 million at the end of the reporting period. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. (3) We recorded $43.4 million of aggregates property impairment during the third quarter of 2015. The fair value measurement of these impaired assets recorded at fair value was $0.0 million at the end of the reporting period. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. (4) We recorded $16.8 million of coal property impairment and $3.0 million impairment of our aggregates properties during the fourth quarter of 2014. Management concluded certain unleased properties were impaired due primarily to the ongoing regulatory environment and continued depressed coal markets with little indications of improvement in the near term. The fair values for those unleased properties were determined for the associated reserves using Level 2 market approaches based upon recent comparable sales and Level 3 expected cash flows. |
Goodwill and Intangible Assets
Goodwill and Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | The Partnership's intangible assets consist of the following (in thousands): December 31, 2015 December 31, 2014 Contract intangibles $ 81,109 $ 82,972 Other intangibles 5,076 3,004 Less accumulated amortization (29,258 ) (25,243 ) Total intangible assets, net $ 56,927 $ 60,733 |
Estimated Amortization Expense | The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods. For the Year Ended December 31, Estimated Amortization Expense (in thousands) 2016 $ 3,544 2017 3,095 2018 3,108 2019 3,108 2020 3,108 |
Debt and Debt - Affiliate (Tabl
Debt and Debt - Affiliate (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | As of December 31, 2015 and 2014, Debt and debt—affiliate consisted of the following (in thousands): December 31, 2015 December 31, 2014 NRP LP Debt: $425 million 9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% $ 422,923 $ 422,167 Opco Debt: $300 million floating rate revolving credit facility, due October 2017 290,000 — $300 million floating rate revolving credit facility, due August 2016 — 200,000 $200 million floating rate term loan, due January 2016 — 75,000 4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018 13,850 18,467 8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019 85,714 107,143 5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020 38,462 46,154 5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021 1,153 1,345 5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 21,600 24,300 4.73% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 60,000 67,500 5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 135,000 150,000 8.92% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 40,909 45,455 5.03% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 148,077 161,538 5.18% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 42,308 46,154 NRP Oil and Gas Debt: Reserve-based revolving credit facility due November 2019 85,000 110,000 Total debt and debt—affiliate 1,384,996 1,475,223 Less: current portion of long-term debt, net (80,983 ) (80,983 ) Total long-term debt and debt—affiliate $ 1,304,013 $ 1,394,240 |
Principal Payments Due | The consolidated principal payments due are set forth below (in thousands): NRP LP Opco NRP Oil and Gas Senior Notes Senior Notes Credit Facility Credit Facility Total 2016 $ — $ 80,983 $ — $ — $ 80,983 2017 — 80,983 290,000 — 370,983 2018 425,000 (1 ) 80,983 — — 505,983 2019 — 76,366 — 85,000 161,366 2020 — 54,938 — — 54,938 Thereafter — 212,820 — — 212,820 $ 425,000 $ 587,073 $ 290,000 $ 85,000 $ 1,387,073 (1) The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2015 were carried at $422.9 million . |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Contractual Override, Note Receivable and Long-Term Debt | The following table (in thousands) shows the carrying amount and estimated fair value of our other financial instruments: December 31, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Assets Contracts receivable—affiliate, current and long-term (1) $ 4,891 $ 4,158 $ 4,870 $ 5,162 Debt and debt—affiliate NRP LP senior notes (2) $ 422,923 $ 277,313 $ 422,167 $ 423,780 Opco senior notes and utility local improvement obligation (1) $ 587,073 $ 383,065 $ 668,056 $ 672,740 Opco revolving credit facility and term loan facility (3) $ 290,000 $ 290,000 $ 275,000 $ 275,000 NRP Oil and Gas revolving credit facility (3) $ 85,000 $ 85,000 $ 110,000 $ 110,000 (1) The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing trading prices near year end. (2) The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near year end. (3) The Level 3 fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Summary of Reimbursements | Direct general and administrative expenses charged to the Partnership by its general partner for services performed by WPPLP and Quintana Minerals Corporation are as follows (in thousands): For the Year Ended 2015 2014 2013 Operating and maintenance expenses—affiliates, net 16,031 10,770 8,821 General and administrative—affiliates 5,312 3,258 3,286 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Summary of Reconciliation of Beginning and Ending Carrying Amounts of the Partnership's Asset Retirement Obligations | The following table presents a reconciliation (in thousands) of the beginning and ending carrying amounts of the Partnership’s asset retirement obligations. The short-term balance of $0.0 million and $0.1 million at December 31, 2015 and 2014, respectively, is included in Accrued liabilities and the remaining balance is included in Other non-current liabilities in the Consolidated Balance Sheets. The Partnership does not have any assets that are legally restricted for purposes of settling these obligations. For the Years Ended December 31, 2015 2014 Balance, January 1 $ 4,973 $ 39 Liabilities incurred in current period, including aquisitions 5 4,697 Accretion expense 284 237 Acquisition related purchase price adjustments (2,280 ) — Balance, December 31 $ 2,982 $ 4,973 |
Major Lessees (Tables)
Major Lessees (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Leases [Abstract] | |
Revenues from Lessees that Exceeded Ten Percent of Total Revenues and Other Income | Revenues from lessees that exceeded ten percent of total revenues and other income for any of the periods presented below are as follows (in thousands except for percentages): For the Years Ended December 31, 2015 2014 2013 Revenues Percent Revenues Percent Revenues Percent Foresight Energy $ 86,614 17.7 % $ 81,546 20.4 % $ 88,432 24.7 % Alpha Natural Resources $ 34,364 7.0 % $ 48,783 12.2 % $ 55,147 15.4 % |
Long-Term Incentive Plans (Tabl
Long-Term Incentive Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of Activity in Outstanding Grants | A summary of activity in the outstanding grants during 2015 is as follows (in thousands): Phantom Units Outstanding grants at January 1, 2015 115 Grants during the period 52 Grants vested and paid during the period (29 ) Forfeitures during the period (12 ) Outstanding grants at December 31, 2015 126 |
Supplementary Unrestricted Su42
Supplementary Unrestricted Subsidiary Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | |
Condensed Balance Sheet | CONDENSED CONSOLIDATING BALANCE SHEETS (in thousands) December 31, 2015 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total ASSETS Current assets (including affiliates) $ 21,540 $ 99,589 $ 121,129 Mineral rights, net 134,445 959,582 1,094,027 Equity in unconsolidated investment — 261,942 261,942 Other non-current assets (including affiliates) 2,287 204,690 206,977 Total assets $ 158,272 $ 1,525,803 $ 1,684,075 LIABILITIES AND CAPITAL Current portion of long-term debt, net — 80,983 80,983 Other current liabilities (including affiliates) 7,351 48,313 55,664 Long-term debt, net (including affiliate) 85,000 1,219,013 1,304,013 Other non-current liabilities (including affiliates) 4,703 165,770 170,473 Partners' capital 64,663 11,673 76,336 Non-controlling interest (3,445 ) 51 (3,394 ) Total liabilities and capital $ 158,272 $ 1,525,803 $ 1,684,075 December 31, 2014 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total ASSETS Current assets (including affiliates) $ 23,842 $ 112,276 $ 136,118 Mineral rights, net 446,938 1,334,914 1,781,852 Equity in unconsolidated investment — 264,020 264,020 Other non-current assets (including affiliates) 4,156 258,578 262,734 Total assets $ 474,936 $ 1,969,788 $ 2,444,724 LIABILITIES AND CAPITAL Current portion of long-term debt, net — 80,983 80,983 Other current liabilities (including affiliates) 16,212 50,736 66,948 Long-term debt, net (including affiliate) 110,000 1,284,240 1,394,240 Other non-current liabilities (including affiliates) 5,193 177,205 182,398 Partners' capital 344,232 376,573 720,805 Non-controlling interest (701 ) 51 (650 ) Total liabilities and capital $ 474,936 $ 1,969,788 $ 2,444,724 |
Condensed Income Statement | CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) Year Ended December 31, 2015 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total Revenues $ 56,091 $ 432,758 $ 488,849 Operating expenses 361,166 605,594 966,760 Loss from operations (305,075 ) (172,836 ) (477,911 ) Other expense 4,065 89,744 93,809 Net loss (309,140 ) (262,580 ) (571,720 ) Add: comprehensive loss from unconsolidated investment and other — (1,693 ) (1,693 ) Comprehensive loss $ (309,140 ) $ (264,273 ) $ (573,413 ) Year Ended December 31, 2014 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total Revenues $ 56,840 $ 342,912 $ 399,752 Operating expenses 41,754 169,079 210,833 Income from operations 15,086 173,833 188,919 Other expense 662 79,427 80,089 Net income 14,424 94,406 108,830 Add: comprehensive loss from unconsolidated investment and other — (81 ) (81 ) Comprehensive income $ 14,424 $ 94,325 $ 108,749 Year Ended December 31, 2013 Unrestricted Subsidiaries of NRP NRP and its Restricted Subsidiaries Total Revenues $ 14,386 $ 343,731 $ 358,117 Operating expenses 8,812 113,069 121,881 Income from operations 5,574 230,662 236,236 Other expense 39 64,119 64,158 Net income 5,535 166,543 172,078 Add: comprehensive income from unconsolidated investment and other — 65 65 Comprehensive income $ 5,535 $ 166,608 $ 172,143 |
Supplemental Information on O43
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Summary of Capitalized Costs | Capitalized Costs (in thousands): For the Years Ended 2015 2014 Proven properties $ 199,404 $ 392,153 Unproven properties — 46,400 Total property, plant, and equipment 199,404 438,553 Accumulated depreciation, depletion, and amortization (60,542 ) (18,993 ) Net capitalized costs $ 138,862 $ 419,560 |
Costs Incurred for Property Acquisition Exploration and Development | Costs incurred for property acquisitions, exploration, and development (in thousands): For the Years Ended 2015 2014 Property acquisitions Proven properties $ — $ 298,627 Unproven properties — 40,800 Development 29,080 5,340 Total $ 29,080 $ 344,767 |
Results of Operations for Producing Activities | Results of Operations for Producing Activities (in thousands): For the Years Ended 2015 2014 Production revenue $ 49,201 $ 48,834 Royalty and overriding royalty revenue (1) 4,364 10,732 Total oil and gas related revenue 53,565 59,566 Operating costs and expense: Depreciation, depletion and amortization 40,772 23,936 Property, franchise and other taxes 5,210 5,529 Production costs 12,871 12,544 Impairment of oil and gas properties 367,576 — Total operating costs and expense 426,429 42,009 Total income from operations $ (372,864 ) $ 17,557 (1) Includes $0.4 million and $1.9 million for the years ended December 31, 2015 and 2014, respectively of nonproduction revenues including lease bonus payments |
Summary of Estimated Proved Reserves and Related Standardized Measure of Discounted Cash Flows by Reserve Category | The following tables shows our estimated domestic proved reserves and reserve additions and revisions: Crude Oil (MBbl) NGLs (MBbl) Natural Gas (MMcf)(2) Total Proved Reserves (MBoe)(3) December 31, 2014 9,983 1,229 14,370 13,607 Revisions of previous estimates (1,451 ) 89 701 (1,244 ) Extensions, discoveries and other additions 776 60 541 926 Sales of properties (98 ) — (62 ) (108 ) Production (1,136 ) (156 ) (2,226 ) (1,663 ) December 31, 2015 (1) 8,074 1,222 13,324 11,518 Proved developed reserves as of December 31, 2015 7,862 1,196 13,157 11,251 Proved undeveloped reserves as of December 31, 2015 212 26 167 267 Proved developed reserves as of December 31, 2014 8,930 1,098 13,161 12,221 Proved undeveloped reserves as of December 31, 2014 1,053 131 1,209 1,386 (1) Includes reserves attributable to the Partnership's 51% member interest in BRP LLC. (2) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. (3) Includes 10,063 MBoe of estimated proved reserves attributable to the Partnership’s non-operated working interests in oil and natural gas properties in the Williston Basin, approximately 3% of which were proved undeveloped reserves. |
Standardized Measure of Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows (in thousands): For the Years Ended 2015 2014 Future cash inflows $ 364,352 $ 920,454 Less related future: Production costs (164,649 ) (312,666 ) Development and abandonment costs (7,826 ) (20,072 ) Future net cash flows before 10% discount 191,877 587,716 Discount to present value at a 10% annual rate (75,524 ) (282,519 ) Total standardized measure of discounted net cash flows $ 116,353 $ 305,197 The table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during the year ended December 31, 2015 (in thousands): Beginning of the period $ 305,197 Revisions to previous estimates: Changes in prices and costs (188,946 ) Changes in quantities (11,750 ) Changes in future development costs (12,202 ) Previously estimated development costs incurred during the period 29,080 Additions to proved reserves from extensions, discoveries and improved recovery, less related costs 11,928 Purchases and sales of reserves in place, net (3,851 ) Accretion of discount 31,795 Sales of oil and gas, net of production costs (35,112 ) Production timing and other (9,786 ) Net increase (decrease) (188,844 ) End of period $ 116,353 |
Supplemental Quarterly Inform44
Supplemental Quarterly Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Information | The following table summarizes quarterly financial data for 2015 and 2014 (in thousands, except per unit data): 2015 First Second Third Fourth Total Total revenues and other income $ 109,677 $ 137,630 $ 125,479 $ 116,063 $ 488,849 Depreciation, depletion and amortization $ 25,392 $ 30,660 $ 26,624 $ 18,152 $ 100,828 Asset impairment $ — $ 3,803 (1) $ 626,838 (2) $ 50,953 (3) $ 681,594 Income (loss) from operations $ 40,417 $ 55,920 $ (576,290 ) $ 2,042 $ (477,911 ) Net income (loss) $ 17,489 $ 32,578 $ (600,001 ) $ (21,786 ) $ (571,720 ) Net income (loss) per limited partner unit $ 1.40 $ 2.50 $ (47.90 ) $ (1.75 ) $ (45.75 ) Weighted average number of common units outstanding 12,230 12,230 12,230 12,230 12,230 2014 First Second Third Fourth Total Total revenues and other income $ 80,309 $ 90,561 $ 91,609 $ 137,273 $ 399,752 Depreciation, depletion and amortization $ 14,647 $ 16,350 $ 18,621 $ 30,258 $ 79,876 Asset impairment $ — $ 5,624 (4) $ — $ 20,585 (5) 26,209 Income from operations $ 52,439 $ 50,403 $ 55,027 $ 31,050 $ 188,919 Net income $ 32,605 $ 31,407 $ 36,173 $ 8,645 $ 108,830 Net income per limited partner unit $ 2.90 $ 2.80 $ 3.20 $ 0.70 $ 9.42 Weighted average number of common units outstanding 10,985 11,040 11,124 12,145 11,326 (1) During the second quarter of 2015 we recorded a $2.3 million impairment expense related to a coal preparation plant and a $1.5 million impairment expense related to coal mineral rights. (2) During the third quarter of 2015 we recorded $335.7 million of oil and gas property impairment, $247.8 million of coal property impairment and $43.4 million of aggregates property impairment. (3) During the fourth quarter of 2015 we recorded $31.9 million of oil and gas property impairment, $8.2 million of coal property impairment, $5.5 million of goodwill impairment, $4.7 million related to coal processing and transportation assets as well as obsolete equipment at our Logan office as well as a $0.7 million impairment expense related to obsolete plant and equipment at VantaCore. (4) During the second quarter of 2014, we recorded $5.6 million of intangible asset impairment related to an aggregates lease. (5) During the fourth quarter of 2014, we recorded $16.8 million of coal property impairment and $3.0 million of aggregates property impairment as well as $0.8 million in impairment expense related to a coal preparation plant. that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. |
Organization and Nature of Op45
Organization and Nature of Operations - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2015quarrycoal_reservecompanyplantterminal | Oct. 01, 2014quarryplantterminal | |
Collaborative Arrangements Non collaborative Arrangements And Business Acquisitions Transactions [Line Items] | ||
Number of coal producing regions | coal_reserve | 3 | |
Number of operating companies owned | company | 2 | |
Ciner Wyoming | ||
Collaborative Arrangements Non collaborative Arrangements And Business Acquisitions Transactions [Line Items] | ||
Percentage of partnership interest owned (percent) | 49.00% | |
VantaCore Partners LP | ||
Collaborative Arrangements Non collaborative Arrangements And Business Acquisitions Transactions [Line Items] | ||
Number of hard rock quarries | quarry | 4 | 3 |
Number of sand and gravel plants | 6 | 6 |
Number of asphalt plants | 2 | 2 |
Number of marine terminal | terminal | 2 | 1 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Additional Information (Detail) shares in Millions | Feb. 18, 2016shares | Dec. 31, 2015USD ($)shares | Dec. 31, 2015USD ($)shares | Mar. 01, 2016shares | Feb. 17, 2016shares | Dec. 31, 2014USD ($)shares | Oct. 31, 2014 | Sep. 30, 2013 |
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Rate of senior notes | 9.125% | 9.125% | ||||||
Long-term debt | $ 1,384,996,000 | $ 1,384,996,000 | $ 1,475,223,000 | |||||
Common units outstanding (in shares) | shares | 12.2 | 12.2 | 12.2 | |||||
Common units outstanding (in shares) | shares | 12.2 | |||||||
Allowance for doubtful accounts | $ 5,300,000 | $ 5,300,000 | $ 700,000 | |||||
Oil and gas royalty interests useful life (in years) | 30 years | |||||||
Asset impairment | $ 676,100,000 | |||||||
Impairment loss | $ 5,500,000 | |||||||
Minimum [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Ownership interest of Partnership with significant influence (percent) | 20.00% | 20.00% | ||||||
Maximum [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Ownership interest of Partnership with significant influence (percent) | 50.00% | 50.00% | ||||||
Restatement Adjustment [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Depletion | $ (3,800,000) | |||||||
Subsequent Event [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Common units outstanding (in shares) | shares | 12.2 | 122.3 | ||||||
NRP LP | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Rate of senior notes | 9.125% | 9.125% | ||||||
NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Debt Instrument, face Amount | $ 425,000,000 | $ 425,000,000 | ||||||
Rate of senior notes | 9.125% | 9.125% | ||||||
Long-term debt | $ 422,923,000 | $ 422,923,000 | 422,167,000 | |||||
NRP LP | Senior Notes | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Rate of senior notes | 9.125% | 9.125% | ||||||
Long-term debt | $ 422,900,000 | $ 422,900,000 | ||||||
Opco | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 4 | |||||||
Opco | $300 million floating rate revolving credit facility, due October 2017 | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Long-term debt | 290,000,000 | $ 290,000,000 | 0 | |||||
Opco | Senior Notes | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Long-term debt | 585,900,000 | $ 585,900,000 | ||||||
NRP Oil and Gas | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Leverage ratio, maximum | 3.5 | |||||||
Revolving Credit Facility | Opco | Fiscal Quarter Ending on or Before March 31, 2016 [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 4 | |||||||
Revolving Credit Facility | Opco | Fiscal Quarter Ending on or Before March 31, 2017 [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 3.75 | |||||||
Revolving Credit Facility | Opco | Fiscal Quarter Ending on or After June 30, 2017 [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 3.5 | |||||||
Revolving Credit Facility | NRP Oil and Gas | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Borrowings outstanding | $ 85,000,000 | $ 85,000,000 | $ 110,000,000 | |||||
Leverage ratio, maximum | 3.5 | |||||||
Common Stock [Member] | Subsequent Event [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Reverse split ratio, common units | 0.1 | |||||||
VantaCore | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Impairment loss | $ 5,500,000 | |||||||
Brp Llc [Member] | ||||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||||
Percentage of partnership interest owned (percent) | 51.00% | 51.00% |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Summary of Plant and Equipment Useful Lives (Detail) | 12 Months Ended |
Dec. 31, 2015 | |
Buildings and Improvements [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Period of assets which are depreciated on straight line basis over their useful lives | 20 years |
Buildings and Improvements [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Period of assets which are depreciated on straight line basis over their useful lives | 40 years |
Machinery and Equipment [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Period of assets which are depreciated on straight line basis over their useful lives | 5 years |
Machinery and Equipment [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Period of assets which are depreciated on straight line basis over their useful lives | 12 years |
Leasehold Improvements [Member] | |
Property, Plant and Equipment [Line Items] | |
Period of assets which are depreciated on straight line basis over their useful lives | Life of Lease |
Segment Information - Additiona
Segment Information - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2015segment | |
Segment Reporting Information [Line Items] | |
Number of operating segments | 4 |
Ciner Wyoming | |
Segment Reporting Information [Line Items] | |
Percentage of partnership interest owned (percent) | 49.00% |
Segment Information - Schedule
Segment Information - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||||||||||
Revenues | $ 116,063 | $ 125,479 | $ 137,630 | $ 109,677 | $ 137,273 | $ 91,609 | $ 90,561 | $ 80,309 | $ 488,849 | $ 399,752 | $ 358,117 |
Depreciation, depletion and amortization | 18,152 | 26,624 | 30,660 | 25,392 | 30,258 | 18,621 | 16,350 | 14,647 | 100,828 | 79,876 | 64,377 |
Asset impairment | 50,953 | 626,838 | 3,803 | 0 | 20,585 | 0 | 5,624 | 0 | 681,594 | 26,209 | 734 |
Interest expense, net | (93,809) | (80,089) | (64,158) | ||||||||
Net income (loss) | (21,786) | $ (600,001) | $ 32,578 | $ 17,489 | 8,645 | $ 36,173 | $ 31,407 | $ 32,605 | (571,720) | 108,830 | 172,078 |
Capital expenditures | 44,924 | 536,318 | 368,104 | ||||||||
Total assets | 1,684,075 | 2,444,724 | 1,684,075 | 2,444,724 | 1,991,856 | ||||||
Corporate and Financing | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Depreciation, depletion and amortization | 0 | 0 | 0 | ||||||||
Asset impairment | 0 | 0 | 0 | ||||||||
Interest expense, net | (93,809) | (80,089) | (64,158) | ||||||||
Net income (loss) | (106,157) | (90,634) | (78,896) | ||||||||
Capital expenditures | 0 | 0 | 0 | ||||||||
Total assets | 15,001 | 16,571 | 15,001 | 16,571 | 12,879 | ||||||
Intersegment Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 0 | ||||||||||
Coal, Hard Mineral Royalty and Other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 156,638 | 172,160 | 213,825 | ||||||||
Coal, Hard Mineral Royalty and Other | Operating Segments | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 246,353 | 256,719 | 306,851 | ||||||||
Depreciation, depletion and amortization | 44,478 | 52,645 | 58,502 | ||||||||
Asset impairment | 307,800 | 26,209 | 734 | ||||||||
Interest expense, net | 0 | 0 | 0 | ||||||||
Net income (loss) | (138,388) | 143,678 | 211,590 | ||||||||
Capital expenditures | 428 | 5,351 | 0 | ||||||||
Total assets | 1,047,922 | 1,403,762 | 1,047,922 | 1,403,762 | 1,520,428 | ||||||
Coal, Hard Mineral Royalty and Other | Intersegment Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 21 | ||||||||||
Soda Ash | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 49,918 | 41,416 | 34,186 | ||||||||
Soda Ash | Operating Segments | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 49,918 | 41,416 | 34,186 | ||||||||
Depreciation, depletion and amortization | 0 | 0 | 0 | ||||||||
Asset impairment | 0 | 0 | 0 | ||||||||
Interest expense, net | 0 | 0 | 0 | ||||||||
Net income (loss) | 49,918 | 41,416 | 34,186 | ||||||||
Capital expenditures | 0 | 0 | 293,085 | ||||||||
Total assets | 261,942 | 264,020 | 261,942 | 264,020 | 269,338 | ||||||
Soda Ash | Intersegment Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 0 | ||||||||||
VantaCore | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 139,013 | 42,051 | 0 | ||||||||
VantaCore | Operating Segments | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 139,013 | 42,051 | 0 | ||||||||
Depreciation, depletion and amortization | 15,578 | 3,296 | 0 | ||||||||
Asset impairment | 6,218 | 0 | 0 | ||||||||
Interest expense, net | 0 | 0 | 0 | ||||||||
Net income (loss) | 272 | 32 | 0 | ||||||||
Capital expenditures | 14,039 | 171,116 | 0 | ||||||||
Total assets | 200,348 | 219,658 | 200,348 | 219,658 | 0 | ||||||
VantaCore | Intersegment Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | (21) | ||||||||||
Oil and Gas | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 53,565 | 59,566 | 17,080 | ||||||||
Oil and Gas | Operating Segments | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | 53,565 | 59,566 | 17,080 | ||||||||
Depreciation, depletion and amortization | 40,772 | 23,935 | 5,875 | ||||||||
Asset impairment | 367,576 | 0 | 0 | ||||||||
Interest expense, net | 0 | 0 | 0 | ||||||||
Net income (loss) | (377,365) | 14,338 | 5,198 | ||||||||
Capital expenditures | 30,457 | 359,851 | 75,019 | ||||||||
Total assets | $ 158,862 | $ 540,713 | 158,862 | $ 540,713 | $ 189,211 | ||||||
Oil and Gas | Intersegment Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Revenues | $ 0 |
Acquisitions - Additional Info
Acquisitions - Additional Information (Detail) $ in Thousands | Nov. 12, 2014USD ($) | Oct. 01, 2014USD ($)quarryplantmineterminal | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($)quarryplantterminal | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Aug. 31, 2013USD ($) |
VantaCore Partners LP | ||||||||
Business Acquisition [Line Items] | ||||||||
Aggregate acquisition cost | $ 200,582 | |||||||
Number of hard rock quarries | quarry | 3 | 4 | ||||||
Number of sand and gravel plants | plant | 6 | 6 | ||||||
Number of asphalt plants | plant | 2 | 2 | ||||||
Number of underground limestone mine | mine | 1 | |||||||
Number of marine terminal | terminal | 1 | 2 | ||||||
Increase in plant and equipment | $ 22,500 | |||||||
Increase to mineral rights and intangible assets | $ 24,700 | |||||||
Acquisition related purchase price adjustments | $ (2,300) | |||||||
Revenue from acquired entity | $ 42,100 | |||||||
Operating income from acquired entity | 100 | |||||||
Transaction costs of acquisition | 2,900 | |||||||
Purchase price allocation for assets acquired | $ 59,946 | |||||||
Sanish Field [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Aggregate acquisition cost | $ 339,100 | |||||||
Revenue from acquired entity | 12,800 | |||||||
Operating income from acquired entity | 3,700 | |||||||
Transaction costs of acquisition | $ 1,800 | |||||||
Sundance Energy Inc [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Purchase price allocation for assets acquired | $ 29,400 | |||||||
Abraxas Petroleum [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Purchase price allocation for assets acquired | $ 38,000 | |||||||
Abraxas and Sundance [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Operating income from acquired entity | 2,500 | |||||||
Combined revenues | $ 5,400 |
Acquisitions - Schedule of Adj
Acquisitions - Schedule of Adjustments to the Estimated Fair Value (Detail) - USD ($) $ in Thousands | Nov. 12, 2014 | Oct. 01, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Consideration | |||||
Cash paid | $ 0 | $ 168,978 | $ 0 | ||
Allocation of Purchase Price | |||||
Mineral rights - proven oil and gas properties | 0 | 298,627 | |||
Mineral rights - probable and possible oil and gas resources | 0 | 40,800 | |||
Goodwill | $ 0 | $ 52,012 | |||
VantaCore Partners LP | |||||
Consideration | |||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents | $ 168,978 | ||||
NRP common units | 31,604 | ||||
Total consideration given | 200,582 | ||||
Allocation of Purchase Price | |||||
Current assets | 37,222 | ||||
Land, property and equipment | 59,946 | ||||
Mineral rights | 111,500 | ||||
Other assets | 4,347 | ||||
Current liabilities | (16,953) | ||||
Asset retirement obligation | (1,005) | ||||
Goodwill | 5,525 | ||||
Fair value of net assets acquired | $ 200,582 | ||||
Sanish Field [Member] | |||||
Consideration | |||||
Cash paid | $ 339,093 | ||||
Total consideration given | 339,100 | ||||
Allocation of Purchase Price | |||||
Mineral rights - proven oil and gas properties | 298,293 | ||||
Mineral rights - probable and possible oil and gas resources | 40,800 | ||||
Fair value of net assets acquired | $ 339,093 |
Acquisitions - Business Acquis
Acquisitions - Business Acquisition Pro Forma Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Business Combinations [Abstract] | ||
Total revenues and other income | $ 533,517 | $ 579,933 |
Net income | $ 122,319 | $ 197,164 |
Basic and diluted net income per common unit | $ 9.90 | $ 16 |
Equity Investment - Additional
Equity Investment - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Equity Method Investments [Line Items] | |||
Distributions from equity method Investment | $ 46,795 | $ 43,005 | $ 24,113 |
Weighted average useful life of assets (in years) | 28 years | ||
Ciner Wyoming | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of partnership interest owned (percent) | 49.00% | ||
Ciner Wyoming | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of partnership interest owned (percent) | 49.00% | ||
Distributions from equity method Investment | $ 46,800 | 46,600 | $ 72,900 |
Increase in fair value of property, plant and equipment | $ 154,800 | $ 162,700 |
Equity Investment - Schedule o
Equity Investment - Schedule of Summarized Financial Information of Unaudited Financial Statements (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Equity Method Investments [Line Items] | |||||||||||
Net income (loss) | $ (21,786) | $ (600,001) | $ 32,578 | $ 17,489 | $ 8,645 | $ 36,173 | $ 31,407 | $ 32,605 | $ (571,720) | $ 108,830 | $ 172,078 |
Current assets | 121,129 | 136,118 | 121,129 | 136,118 | |||||||
Current liabilities | 136,647 | 147,931 | 136,647 | 147,931 | |||||||
Ciner Wyoming | |||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||
Income allocation to NRP’s equity interests | 54,709 | 47,354 | 37,036 | ||||||||
Amortization of basis difference | (4,791) | (5,938) | (2,850) | ||||||||
Equity in earnings of unconsolidated investment | 49,918 | 41,416 | 34,186 | ||||||||
Sales | 486,393 | 465,032 | 442,132 | ||||||||
Gross profit | 131,493 | 118,439 | 94,299 | ||||||||
Net income (loss) | 111,650 | 96,640 | $ 79,655 | ||||||||
Current assets | 144,695 | 179,851 | 144,695 | 179,851 | |||||||
Noncurrent assets | 233,845 | 223,053 | 233,845 | 223,053 | |||||||
Current liabilities | 43,018 | 47,704 | 43,018 | 47,704 | |||||||
Noncurrent liabilities | $ 116,808 | $ 149,192 | $ 116,808 | $ 149,192 |
Inventory - Components of Inven
Inventory - Components of Inventories (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Inventory Disclosure [Abstract] | ||
Aggregates | $ 7,056 | $ 4,596 |
Supplies and parts | 779 | 1,218 |
Total inventory | $ 7,835 | $ 5,814 |
Plant and Equipment - Plant and
Plant and Equipment - Plant and Equipment (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment [Abstract] | ||
Plant and equipment at cost | $ 92,203 | $ 89,759 |
Construction in process | 1,074 | 457 |
Less accumulated depreciation | (32,038) | (30,123) |
Total plant and equipment, net | $ 61,239 | $ 60,093 |
Plant and Equipment - Additiona
Plant and Equipment - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment [Line Items] | |||||||||||
Depreciation expense on plant and equipment | $ 15,900 | $ 7,600 | $ 6,000 | ||||||||
Asset impairment expenses | $ 50,953 | $ 626,838 | $ 3,803 | $ 0 | $ 20,585 | $ 0 | $ 5,624 | $ 0 | 681,594 | $ 26,209 | $ 734 |
Coal Plant and Coal Related Assets [Member] | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Fair value of impaired assets | 0 | $ 0 | |||||||||
Coal Plant | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | $ 2,300 | $ 800 | |||||||||
Coal Processing and Transportation Assets, and Obsolete Equipment of Logan Office [Member] | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | 4,700 | ||||||||||
VantaCore Partners LP | Obsolete Plant and Equipment | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | $ 700 |
Mineral Rights - Mineral Rights
Mineral Rights - Mineral Rights (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||
Carrying Value | $ 1,546,267 | $ 2,328,471 |
Accumulated Depletion | (452,240) | (546,619) |
Net Book Value | 1,094,027 | 1,781,852 |
Coal, Hard Mineral Royalty and Other | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||
Carrying Value | 1,278,274 | 1,680,169 |
Accumulated Depletion | (432,260) | (505,582) |
Net Book Value | 846,014 | 1,174,587 |
VantaCore | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||
Carrying Value | 112,700 | 87,907 |
Accumulated Depletion | (3,082) | (482) |
Net Book Value | 109,618 | 87,425 |
Oil and Gas | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||
Carrying Value | 155,293 | 560,395 |
Accumulated Depletion | (16,898) | (40,555) |
Net Book Value | $ 138,395 | $ 519,840 |
Mineral Rights - Additional Inf
Mineral Rights - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Extractive Industries [Abstract] | |||
Total depletion and amortization expense on mineral interests | $ 80.3 | $ 68.6 | $ 54.6 |
Mineral Rights Schedule of Impa
Mineral Rights Schedule of Impairment Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | $ 50,953 | $ 626,838 | $ 3,803 | $ 0 | $ 20,585 | $ 0 | $ 5,624 | $ 0 | $ 681,594 | $ 26,209 | $ 734 |
Oil And Gas Mineral Rights | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | 31,900 | 335,700 | 367,576 | 0 | 0 | ||||||
Fair value of impaired assets | 108,000 | 108,000 | |||||||||
Coal Mineral Rights | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | 8,200 | 247,800 | $ 1,500 | 16,800 | 257,468 | 16,793 | 734 | ||||
Fair value of impaired assets | 400 | 400 | |||||||||
Hard Mineral Royalty | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | $ 43,400 | 43,402 | 3,013 | ||||||||
Fair value of impaired assets | $ 0 | 0 | |||||||||
Mining Properties and Mineral Rights | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | $ 668,446 | $ 19,806 | $ 734 | ||||||||
Aggregate Mineral Rights | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment expenses | $ 3,000 |
Goodwill and Intangible Asset61
Goodwill and Intangible Assets - Intangible Assets (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Goodwill and Intangible Assets Disclosure [Abstract] | ||
Contract intangibles | $ 81,109 | $ 82,972 |
Other intangibles | 5,076 | 3,004 |
Less accumulated amortization | (29,258) | (25,243) |
Total intangible assets, net | $ 56,927 | $ 60,733 |
Goodwill and Intangible Asset62
Goodwill and Intangible Assets - Estimated Amortization Expense (Detail) $ in Thousands | Dec. 31, 2015USD ($) |
Goodwill and Intangible Assets Disclosure [Abstract] | |
2,016 | $ 3,544 |
2,017 | 3,095 |
2,018 | 3,108 |
2,019 | 3,108 |
2,020 | $ 3,108 |
Goodwill and Intangible Asset63
Goodwill and Intangible Assets - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 01, 2014 | |
Intangible Assets [Line Items] | |||||||
Total amortization expense on intangible assets | $ 4,600 | $ 3,600 | $ 3,800 | ||||
Impairment of intangible assets | $ 5,600 | ||||||
Goodwill | $ 0 | $ 52,012 | $ 0 | $ 52,012 | |||
Goodwill impairment loss | 5,500 | ||||||
Contractual Rights [Member] | |||||||
Intangible Assets [Line Items] | |||||||
Remaining amortization period for intangibles (in years) | 14 years | ||||||
Other Intangible Assets [Member] | |||||||
Intangible Assets [Line Items] | |||||||
Remaining amortization period for intangibles (in years) | 31 years | ||||||
VantaCore Partners LP | |||||||
Intangible Assets [Line Items] | |||||||
Acquisition of goodwill | $ 52,000 | ||||||
Increase (decrease) in goodwill | $ (46,500) | ||||||
Goodwill | $ 5,525 | ||||||
Goodwill impairment loss | $ 5,500 |
Debt and Debt - Affiliate - Add
Debt and Debt - Affiliate - Additional Information (Detail) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Oct. 31, 2014USD ($) | Sep. 30, 2013USD ($) | Aug. 31, 2013USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2013USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2013USD ($) | Oct. 31, 2015USD ($) | Apr. 30, 2015USD ($) | Nov. 30, 2014USD ($) | |
Debt Instrument [Line Items] | ||||||||||||
Rate of senior notes | 9.125% | |||||||||||
Term Loan [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Repayment of principal amount | $ 75,000,000 | $ 24,000,000 | $ 101,000,000 | |||||||||
Amount received from debt issuance | $ 200,000,000 | |||||||||||
Weighted average interest rate for the debt outstanding (percent) | 2.22% | 2.19% | ||||||||||
Nrp Lp Senior Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Redemption price percentage (percent) | 109.125% | |||||||||||
Redemption price at change of control event (percent) | 101.00% | |||||||||||
Ciner Wyoming | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Percentage of partnership interest owned (percent) | 49.00% | |||||||||||
Ciner Wyoming | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Percentage of partnership interest owned (percent) | 49.00% | |||||||||||
Maximum [Member] | Nrp Lp Senior Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Percentage of principal amount redeemed (up to) | 35.00% | |||||||||||
Redemption period (in days) | 180 days | |||||||||||
Minimum [Member] | Nrp Lp Senior Notes [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Redemption price percentage of principal remaining after redemption (percent) | 65.00% | |||||||||||
NRP LP | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Rate of senior notes | 9.125% | 9.125% | 9.125% | |||||||||
Floating rate revolving credit facility | $ 125,000,000 | $ 300,000,000 | $ 300,000,000 | |||||||||
Senior Note issue percentage | 99.50% | 99.007% | 99.007% | |||||||||
Repayment of principal amount | $ 122,600,000 | |||||||||||
NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Rate of senior notes | 9.125% | |||||||||||
Debt Instrument, face Amount | $ 425,000,000 | |||||||||||
NRP LP | Senior Notes | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Rate of senior notes | 9.125% | |||||||||||
NRP LP | Maximum [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Fixed charge coverage ratio | 2 | |||||||||||
NRP LP | Minimum [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Fixed charge coverage ratio | 1 | |||||||||||
Opco | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Repayment of principal amount | $ 289,000,000 | |||||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 4 | |||||||||||
Ratio of consolidated EBITDDA to consolidated fixed charges | 3.5 | |||||||||||
Principal payments on its senior notes | $ 80,800,000 | |||||||||||
Percentage of consolidated net tangible assets debt of subsidiaries not permitted to exceed | 10.00% | |||||||||||
Opco | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Weighted average interest rate (percent) | 1.98% | 2.91% | ||||||||||
Commitment fee on the unused portion of the borrowing base under the credit facility (percent) | 0.50% | |||||||||||
Ratio of consolidated EBITDDA to consolidated fixed charges | 3.5 | |||||||||||
Secured Debt | $ 709,900,000 | |||||||||||
Opco | $300 million floating rate revolving credit facility, due October 2017 | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Floating rate revolving credit facility | $ 300,000,000 | 300,000,000 | ||||||||||
Opco | $300 million floating rate revolving credit facility, due October 2017 | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Revolving credit facility maturity date | Oct. 2, 2017 | |||||||||||
Opco | $300 million floating rate revolving credit facility, due August 2016 | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Floating rate revolving credit facility | $ 300,000,000 | $ 300,000,000 | ||||||||||
Opco | 8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Rate of senior notes | 8.38% | |||||||||||
Opco | 8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Rate of senior notes | 8.92% | |||||||||||
Opco | Senior Notes | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Partnership leverage ratio | 3.75 | |||||||||||
Additional interest accrue | 2.00% | |||||||||||
Opco | Fiscal Quarter Ending on or Before March 31, 2016 [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 4 | |||||||||||
Opco | Fiscal Quarter Ending on or Before March 31, 2017 [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 3.75 | |||||||||||
Opco | Fiscal Quarter Ending on or After June 30, 2017 [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 3.5 | |||||||||||
Opco | Federal Funds Rate [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Basis spread on variable rate (percent) | 0.50% | 0.50% | ||||||||||
Opco | London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Basis spread on variable rate (percent) | 1.00% | 1.00% | ||||||||||
Opco | London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility Basis Spread Condition One [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 2.375% | |||||||||||
Opco | London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility Basis Spread Condition Two [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 3.375% | |||||||||||
Opco | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility Basis Spread Condition One [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 2.50% | |||||||||||
Opco | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility Basis Spread Condition Two [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 3.50% | |||||||||||
Opco | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility Basis Spread Condition One [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 1.50% | |||||||||||
Opco | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility Basis Spread Condition Two [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 2.50% | |||||||||||
NRP Oil and Gas | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Leverage ratio, maximum | 3.5 | |||||||||||
Current ratio, minimum | 1 | |||||||||||
NRP Oil and Gas | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Floating rate revolving credit facility | $ 105,000,000 | |||||||||||
Repayment of principal amount | $ 25,000,000 | |||||||||||
Weighted average interest rate for the debt outstanding (percent) | 2.37% | 2.50% | ||||||||||
Borrowings outstanding | $ 110,000,000 | $ 85,000,000 | ||||||||||
Term of credit facility | 5 years | |||||||||||
Senior secured revolving credit facility | $ 100,000,000 | |||||||||||
Maximum increase in aggregate commitment | $ 88,000,000 | $ 105,000,000 | $ 137,000,000 | |||||||||
Debt Instrument maturities date | 2019-11 | |||||||||||
Leverage ratio, maximum | 3.5 | |||||||||||
NRP Oil and Gas | Amended On November 2014 [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Maximum increase in aggregate commitment | $ 500,000,000 | |||||||||||
NRP Oil and Gas | Maximum [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Commitment fee on the unused portion of the borrowing base under the credit facility (percent) | 0.50% | |||||||||||
NRP Oil and Gas | Minimum [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Commitment fee on the unused portion of the borrowing base under the credit facility (percent) | 0.375% | |||||||||||
NRP Oil and Gas | Federal Funds Rate [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Basis spread on variable rate (percent) | 0.50% | |||||||||||
NRP Oil and Gas | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility Basis Spread Condition One [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 1.50% | |||||||||||
NRP Oil and Gas | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility Basis Spread Condition Two [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 2.50% | |||||||||||
NRP Oil and Gas | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility Basis Spread Condition One [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 0.50% | |||||||||||
NRP Oil and Gas | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility Basis Spread Condition Two [Member] | Revolving Credit Facility | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Additional basis spread (percent) | 1.50% |
Debt and Debt - Affiliate - Lon
Debt and Debt - Affiliate - Long-Term Debt (Detail) - USD ($) | Dec. 31, 2015 | Jun. 30, 2015 | Dec. 31, 2014 | Oct. 31, 2014 | Sep. 30, 2013 |
Debt Instrument [Line Items] | |||||
Total debt | $ 1,384,996,000 | $ 1,475,223,000 | |||
Less - current portion of long term debt | (80,983,000) | (80,983,000) | |||
Long-term debt, net | $ 1,304,013,000 | 1,394,240,000 | |||
Rate of senior notes | 9.125% | ||||
NRP LP | |||||
Debt Instrument [Line Items] | |||||
Floating rate revolving credit facility | $ 125,000,000 | $ 300,000,000 | |||
Senior Note issue percentage | 99.50% | 99.007% | |||
Rate of senior notes | 9.125% | 9.125% | |||
NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 422,923,000 | 422,167,000 | |||
Debt Instrument, face Amount | $ 425,000,000 | ||||
Rate of senior notes | 9.125% | ||||
Opco | $300 million floating rate revolving credit facility, due October 2017 | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 290,000,000 | 0 | |||
Floating rate revolving credit facility | 300,000,000 | $ 300,000,000 | |||
Opco | $300 million floating rate revolving credit facility, due August 2016 | |||||
Debt Instrument [Line Items] | |||||
Total debt | 0 | 200,000,000 | |||
Floating rate revolving credit facility | 300,000,000 | $ 300,000,000 | |||
Opco | $200 million floating rate term loan, due January 2016 | |||||
Debt Instrument [Line Items] | |||||
Total debt | 0 | 75,000,000 | |||
Floating rate revolving credit facility | 200,000,000 | ||||
Opco | 4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018 | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 13,850,000 | 18,467,000 | |||
Rate of senior notes | 4.91% | ||||
Opco | 8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 85,714,000 | 107,143,000 | |||
Rate of senior notes | 8.38% | ||||
Opco | 5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 38,462,000 | 46,154,000 | |||
Rate of senior notes | 5.05% | ||||
Opco | 5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 1,153,000 | 1,345,000 | |||
Rate of senior notes | 5.31% | ||||
Opco | 5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 21,600,000 | 24,300,000 | |||
Rate of senior notes | 5.55% | ||||
Opco | 4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 60,000,000 | 67,500,000 | |||
Rate of senior notes | 4.73% | ||||
Opco | 5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 135,000,000 | 150,000,000 | |||
Rate of senior notes | 5.82% | ||||
Opco | 8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 40,909,000 | 45,455,000 | |||
Rate of senior notes | 8.92% | ||||
Opco | 5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 148,077,000 | 161,538,000 | |||
Rate of senior notes | 5.03% | ||||
Opco | 5.18% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 42,308,000 | 46,154,000 | |||
Rate of senior notes | 5.18% | ||||
NRP Oil and Gas | Reserve Based Revolving Credit Facility Due 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Total debt | $ 85,000,000 | $ 110,000,000 | |||
Senior Notes Offering Price Two [Member] | NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 | |||||
Debt Instrument [Line Items] | |||||
Floating rate revolving credit facility | $ 125,000,000 | ||||
Senior Note issue percentage | 99.50% | ||||
Senior Notes Offering Price One [Member] | NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 | |||||
Debt Instrument [Line Items] | |||||
Floating rate revolving credit facility | $ 300,000,000 | ||||
Senior Note issue percentage | 99.007% |
Debt and Debt - Affiliate - Pri
Debt and Debt - Affiliate - Principal Payments Due (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Oct. 31, 2014 | Sep. 30, 2013 |
Debt Instrument [Line Items] | ||||
2,016 | $ 80,983 | |||
2,017 | 370,983 | |||
2,018 | 505,983 | |||
2,019 | 161,366 | |||
2,020 | 54,938 | |||
Thereafter | 212,820 | |||
Principal Payments | $ 1,387,073 | |||
Rate of senior notes | 9.125% | |||
Long-term debt | $ 1,384,996 | $ 1,475,223 | ||
NRP LP | ||||
Debt Instrument [Line Items] | ||||
Rate of senior notes | 9.125% | 9.125% | ||
NRP LP | Senior Notes | ||||
Debt Instrument [Line Items] | ||||
2,016 | 0 | |||
2,017 | 0 | |||
2,018 | 425,000 | |||
2,019 | 0 | |||
2,020 | 0 | |||
Thereafter | 0 | |||
Principal Payments | $ 425,000 | |||
Rate of senior notes | 9.125% | |||
Long-term debt | $ 422,900 | |||
Opco | Senior Notes | ||||
Debt Instrument [Line Items] | ||||
2,016 | 80,983 | |||
2,017 | 80,983 | |||
2,018 | 80,983 | |||
2,019 | 76,366 | |||
2,020 | 54,938 | |||
Thereafter | 212,820 | |||
Principal Payments | 587,073 | |||
Long-term debt | 585,900 | |||
Opco | Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
2,016 | 0 | |||
2,017 | 290,000 | |||
2,018 | 0 | |||
2,019 | 0 | |||
2,020 | 0 | |||
Thereafter | 0 | |||
Principal Payments | 290,000 | |||
NRP Oil and Gas | Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
2,016 | 0 | |||
2,017 | 0 | |||
2,018 | 0 | |||
2,019 | 85,000 | |||
2,020 | 0 | |||
Thereafter | 0 | |||
Principal Payments | $ 85,000 |
Fair Value Measurements - Contr
Fair Value Measurements - Contractual Override, Note Receivable and Long-Term Debt (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Contracts receivable—affiliate, current and long-term | $ 4,891 | $ 4,870 |
Fair Value, Inputs, Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Contracts receivable—affiliate, current and long-term | 4,158 | 5,162 |
Nrp Lp Senior Notes [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 422,923 | 422,167 |
Estimated Fair Value | 277,313 | 423,780 |
Opco Senior Notes | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 587,073 | 668,056 |
Estimated Fair Value | 383,065 | 672,740 |
Opco Revolving Credit Facility And Term Loan Facility | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 290,000 | 275,000 |
Estimated Fair Value | 290,000 | 275,000 |
Nrp Oil And Gas Revolving Credit Facility | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Carrying Amount | 85,000 | 110,000 |
Estimated Fair Value | $ 85,000 | $ 110,000 |
Related Party Transactions - Su
Related Party Transactions - Summary of Reimbursements (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transactions [Abstract] | |||
Operating and maintenance expenses—affiliates, net | $ 16,031 | $ 10,770 | $ 8,821 |
General and administrative—affiliates | $ 5,312 | $ 3,258 | $ 3,286 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) shares in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Oct. 31, 2014 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction [Line Items] | ||||||||||||
Amount payable to related parties | $ 1,464,000 | $ 950,000 | $ 1,464,000 | $ 950,000 | ||||||||
Lease expenses | 600,000 | |||||||||||
Revenues | 116,063,000 | $ 125,479,000 | $ 137,630,000 | $ 109,677,000 | 137,273,000 | $ 91,609,000 | $ 90,561,000 | $ 80,309,000 | 488,849,000 | 399,752,000 | $ 358,117,000 | |
Unrecouped minimum royalty payments | 82,600,000 | |||||||||||
Contracts receivable—affiliate, current and long-term | 4,891,000 | 4,870,000 | 4,891,000 | 4,870,000 | ||||||||
Accounts receivable | $ 6,864,000 | 9,494,000 | 6,864,000 | 9,494,000 | ||||||||
Gain on reserve swaps | $ 9,300,000 | 5,700,000 | 8,100,000 | |||||||||
Rate of senior notes | 9.125% | 9.125% | ||||||||||
Deferred revenue—affiliates | $ 82,853,000 | 87,053,000 | $ 82,853,000 | 87,053,000 | ||||||||
Operating and maintenance expenses—affiliates, net | 16,031,000 | 10,770,000 | 8,821,000 | |||||||||
Quintana Minerals | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Amount payable to related parties | 1,100,000 | 600,000 | 1,100,000 | 600,000 | ||||||||
Western Pocahontas Properties | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Amount payable to related parties | 300,000 | 400,000 | $ 300,000 | 400,000 | ||||||||
Cline Affiliates [Member] | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Rate of interest in the partnerships general partner | 31.00% | |||||||||||
Related party transaction number of units hold by the related party in partnerships' general partner | 500 | |||||||||||
Accounts receivable | 6,400,000 | 9,200,000 | $ 6,400,000 | 9,200,000 | ||||||||
Net amount receivable | 5,600,000 | 5,600,000 | ||||||||||
Accounts receivable | 1,100,000 | 1,100,000 | ||||||||||
Cline Affiliates [Member] | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Net amount receivable | 4,900,000 | 4,900,000 | ||||||||||
Accounts receivable | 1,500,000 | 1,500,000 | ||||||||||
Foresight Energy Lp [Member] | Affiliated Entity | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Lease receivable, next year | 5,000,000 | 5,000,000 | ||||||||||
Deficiency payment | 1,250,000 | 1,250,000 | ||||||||||
Foresight Energy Lp [Member] | Coal Sales [Member] | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Revenues | 86,600,000 | 81,500,000 | 88,400,000 | |||||||||
Sugar Camp [Member] | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Contracts receivable—affiliate, current and long-term | 81,200,000 | 86,300,000 | 81,200,000 | 86,300,000 | ||||||||
Unearned income | 35,400,000 | 39,000,000 | 35,400,000 | 39,000,000 | ||||||||
Net amount receivable | 45,900,000 | 47,300,000 | 45,900,000 | 47,300,000 | ||||||||
Accounts receivable | 2,000,000 | 1,800,000 | 2,000,000 | 1,800,000 | ||||||||
Sugar Camp [Member] | Affiliated Entity | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Lease receivable, year two | 5,000,000 | 5,000,000 | ||||||||||
Lease receivable, year three | 5,000,000 | 5,000,000 | ||||||||||
Lease receivable, year four | 5,000,000 | 5,000,000 | ||||||||||
Lease receivable, year five | 5,000,000 | 5,000,000 | ||||||||||
Corsa [Member] | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Accounts receivable | 200,000 | 300,000 | 200,000 | 300,000 | ||||||||
Royalty Revenue from Coal | 3,100,000 | 3,000,000 | 4,600,000 | |||||||||
Deferred revenue—affiliates | 300,000 | 300,000 | ||||||||||
Forge Group [Member] | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Coal, hard mineral royalty and other—affiliates | 1,800,000 | |||||||||||
Western Pocahontas Properties Limited Partnership [Member] | Affiliated Entity | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Operating and maintenance expenses—affiliates, net | 400,000 | 0 | $ 0 | |||||||||
Other assets—affiliate | $ 1,100,000 | 0 | $ 1,100,000 | 0 | ||||||||
Senior Notes Due Two Zero One Eight [Member] | Cline Trust Company [Member] | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Partnership common units owned | 540 | 540 | ||||||||||
Principal amount of partnership purchased | $ 20,000,000 | $ 20,000,000 | ||||||||||
Rate of senior notes | 9.125% | 9.125% | 9.125% | |||||||||
Aggregate principal amount of senior notes | $ 125,000,000 | |||||||||||
Senior notes due | $ 19,900,000 | $ 19,900,000 | $ 19,900,000 | $ 19,900,000 |
Asset Retirement Obligations -
Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Asset Retirement Obligation Disclosure [Abstract] | ||
Accounts payable and accrued liabilities | $ 0 | $ 0.1 |
Asset Retirement Obligations 71
Asset Retirement Obligations - Schedule of Reconciliation of Beginning and Ending Carrying Amounts of Partnership's Asset Retirement Obligations (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance, January 1 | $ 4,973 | $ 39 |
Liabilities incurred in current period, including aquisitions | 5 | 4,697 |
Accretion expense | 284 | 237 |
Acquisition related purchase price adjustments | (2,280) | 0 |
Balance, December 31 | $ 2,982 | $ 4,973 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2015 | |
Ciner Wyoming | |||
Commitments And Contingencies [Line Items] | |||
Contingent consideration accrued | $ 7.2 | ||
Anadarko Holding Company | |||
Commitments And Contingencies [Line Items] | |||
Contingent consideration accrued | 7.2 | ||
Net present value payable of contingent consideration under the agreement | 50 | ||
Anadarko Holding Company | Ciner Wyoming | |||
Commitments And Contingencies [Line Items] | |||
Contingent consideration paid | $ 3.8 | $ 0.5 | |
Lawsuit Against Hillsboro Energy LLC | |||
Commitments And Contingencies [Line Items] | |||
Minimum quarterly deficiency payments | 7.5 | ||
Minimum deficiency payments | 30 | ||
Loss contingency | $ 16.2 |
Major Lessees - Revenues from L
Major Lessees - Revenues from Lessees that Exceeded Ten Percent of Total Revenues and Other Income (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Foresight Energy | |||
Operating Leased Assets [Line Items] | |||
Revenues | $ 86,614 | $ 81,546 | $ 88,432 |
Percent | 17.70% | 20.40% | 24.70% |
Alpha Natural Resources | |||
Operating Leased Assets [Line Items] | |||
Revenues | $ 34,364 | $ 48,783 | $ 55,147 |
Percent | 7.00% | 12.20% | 15.40% |
Major Lessees - Additional Info
Major Lessees - Additional Information (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Alpha Natural Resources | |
Operating Leased Assets [Line Items] | |
Non-recurring lease assignment fee | $ 6 |
Long-Term Incentive Plans - Add
Long-Term Incentive Plans - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of Grants (in years) | 4 years | ||
Payments made in connection with Long-Term Incentive Plan | $ 4,400,000 | $ 6,500,000 | $ 7,000,000 |
Grant date fair value | 4,200,000 | 6,600,000 | 7,800,000 |
Unaccrued cost associated with outstanding grants and related DERs | 700,000 | 5,200,000 | |
General Partner [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expenses related to Incentive Plan to be reimbursed to general partner | $ 3,400,000 | $ 1,000,000 | $ 9,600,000 |
Phantom Share Units (PSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of trading days (in days) | 20 days |
Long-Term Incentive Plans - Su
Long-Term Incentive Plans - Summary of Activity in Outstanding Grants (Detail) | 12 Months Ended |
Dec. 31, 2015shares | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |
Outstanding grants at beginning of period (in shares) | 115,300 |
Grants during the period (in shares) | 51,900 |
Grants vested and paid during the period (in shares) | (29,000) |
Forfeitures during the period (in shares) | (12,000) |
Outstanding grants at the end of the period (in shares) | 126,000 |
Supplementary Unrestricted Su77
Supplementary Unrestricted Subsidiary Information - CONDENSED CONSOLIDATING BALANCE SHEETS (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
ASSETS | |||
Current assets (including affiliates) | $ 121,129 | $ 136,118 | |
Mineral rights, net | 1,094,027 | 1,781,852 | |
Equity in unconsolidated investment | 261,942 | 264,020 | |
Other non-current assets (including affiliates) | 206,977 | 262,734 | |
Total assets | 1,684,075 | 2,444,724 | $ 1,991,856 |
LIABILITIES AND CAPITAL | |||
Current portion of long-term debt, net | 80,983 | 80,983 | |
Other current liabilities (including affiliates) | 55,664 | 66,948 | |
Long-term debt, net (including affiliate) | 1,304,013 | 1,394,240 | |
Other non-current liabilities (including affiliates) | 170,473 | 182,398 | |
Partners' capital | 76,336 | 720,805 | |
Non-controlling interest | (3,394) | (650) | |
Total liabilities and capital | 1,684,075 | 2,444,724 | |
Unrestricted Subsidiaries of NRP | |||
ASSETS | |||
Current assets (including affiliates) | 21,540 | 23,842 | |
Mineral rights, net | 134,445 | 446,938 | |
Equity in unconsolidated investment | 0 | 0 | |
Other non-current assets (including affiliates) | 2,287 | 4,156 | |
Total assets | 158,272 | 474,936 | |
LIABILITIES AND CAPITAL | |||
Current portion of long-term debt, net | 0 | 0 | |
Other current liabilities (including affiliates) | 7,351 | 16,212 | |
Long-term debt, net (including affiliate) | 85,000 | 110,000 | |
Other non-current liabilities (including affiliates) | 4,703 | 5,193 | |
Partners' capital | 64,663 | 344,232 | |
Non-controlling interest | (3,445) | (701) | |
Total liabilities and capital | 158,272 | 474,936 | |
NRP and its Restricted Subsidiaries | |||
ASSETS | |||
Current assets (including affiliates) | 99,589 | 112,276 | |
Mineral rights, net | 959,582 | 1,334,914 | |
Equity in unconsolidated investment | 261,942 | 264,020 | |
Other non-current assets (including affiliates) | 204,690 | 258,578 | |
Total assets | 1,525,803 | 1,969,788 | |
LIABILITIES AND CAPITAL | |||
Current portion of long-term debt, net | 80,983 | 80,983 | |
Other current liabilities (including affiliates) | 48,313 | 50,736 | |
Long-term debt, net (including affiliate) | 1,219,013 | 1,284,240 | |
Other non-current liabilities (including affiliates) | 165,770 | 177,205 | |
Partners' capital | 11,673 | 376,573 | |
Non-controlling interest | 51 | 51 | |
Total liabilities and capital | $ 1,525,803 | $ 1,969,788 |
Supplementary Unrestricted Su78
Supplementary Unrestricted Subsidiary Information - CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Condensed Income Statements, Captions [Line Items] | |||||||||||
Revenues | $ 116,063 | $ 125,479 | $ 137,630 | $ 109,677 | $ 137,273 | $ 91,609 | $ 90,561 | $ 80,309 | $ 488,849 | $ 399,752 | $ 358,117 |
Operating expenses | 966,760 | 210,833 | 121,881 | ||||||||
Income (loss) from operations | 2,042 | (576,290) | 55,920 | 40,417 | 31,050 | 55,027 | 50,403 | 52,439 | (477,911) | 188,919 | 236,236 |
Other expense | 93,809 | 80,089 | 64,158 | ||||||||
Net income (loss) | $ (21,786) | $ (600,001) | $ 32,578 | $ 17,489 | $ 8,645 | $ 36,173 | $ 31,407 | $ 32,605 | (571,720) | 108,830 | 172,078 |
Add: comprehensive income (loss) from unconsolidated investment and other | (1,693) | (81) | 65 | ||||||||
Comprehensive income (loss) | (573,413) | 108,749 | 172,143 | ||||||||
Unrestricted Subsidiaries of NRP | |||||||||||
Condensed Income Statements, Captions [Line Items] | |||||||||||
Revenues | 56,091 | 56,840 | 14,386 | ||||||||
Operating expenses | 361,166 | 41,754 | 8,812 | ||||||||
Income (loss) from operations | (305,075) | 15,086 | 5,574 | ||||||||
Other expense | 4,065 | 662 | 39 | ||||||||
Net income (loss) | (309,140) | 14,424 | 5,535 | ||||||||
Add: comprehensive income (loss) from unconsolidated investment and other | 0 | 0 | 0 | ||||||||
Comprehensive income (loss) | (309,140) | 14,424 | 5,535 | ||||||||
NRP and its Restricted Subsidiaries | |||||||||||
Condensed Income Statements, Captions [Line Items] | |||||||||||
Revenues | 432,758 | 342,912 | 343,731 | ||||||||
Operating expenses | 605,594 | 169,079 | 113,069 | ||||||||
Income (loss) from operations | (172,836) | 173,833 | 230,662 | ||||||||
Other expense | 89,744 | 79,427 | 64,119 | ||||||||
Net income (loss) | (262,580) | 94,406 | 166,543 | ||||||||
Add: comprehensive income (loss) from unconsolidated investment and other | (1,693) | (81) | 65 | ||||||||
Comprehensive income (loss) | $ (264,273) | $ 94,325 | $ 166,608 |
Supplementary Unrestricted Su79
Supplementary Unrestricted Subsidiary Information - Additional Information (Details) | Dec. 31, 2015 |
Brp Llc [Member] | |
Related Party Transaction [Line Items] | |
Percentage of partnership interest owned (percent) | 51.00% |
Subsequent Events - Additional
Subsequent Events - Additional Information (Detail) $ / shares in Units, shares in Millions, T in Millions, $ in Millions | Feb. 18, 2016shares | Feb. 12, 2016$ / shares | Feb. 01, 2016USD ($) | Feb. 29, 2016USD ($)MBoeoperationWellsT | Dec. 31, 2015MBoeshares | Feb. 17, 2016shares | Dec. 31, 2014shares |
Subsequent Event [Line Items] | |||||||
Common units outstanding (in shares) | shares | 12.2 | 12.2 | |||||
Sales of properties (in MBoe) | MBoe | 108 | ||||||
Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Distribution paid (in dollar per share) | $ / shares | $ 0.45 | ||||||
Common units outstanding (in shares) | shares | 12.2 | 122.3 | |||||
Common Stock [Member] | Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Reverse split ratio, common units | 0.1 | ||||||
Appalachian Basin [Member] | Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Proceeds from sale of royalty and overriding royalty interests | $ 36.6 | ||||||
Gain on sale | $ 20.3 | ||||||
Number of gross producing wells | Wells | 765 | ||||||
Percent of estimated proved reserves | 10.00% | ||||||
Sales of properties (in MBoe) | MBoe | 1,094 | ||||||
Texas, Georgia, Tennessee [Member] | Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Proceeds from sale of royalty and overriding royalty interests | $ 9.8 | ||||||
Gain on sale | $ 1.6 | ||||||
Disposition of reserves and related royalty rights, number of operations | operation | 3 | ||||||
Percent of proved reserves and related royalty rights sold | 27.00% | ||||||
Disposition of proved reserves (in tons) | T | 139 |
Supplemental Information on O81
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) - Summary of Capitalized Costs (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Extractive Industries [Abstract] | ||
Proven properties | $ 199,404 | $ 392,153 |
Unproven properties | 0 | 46,400 |
Total property, plant, and equipment | 199,404 | 438,553 |
Accumulated depreciation, depletion, and amortization | (60,542) | (18,993) |
Net capitalized costs | $ 138,862 | $ 419,560 |
Supplemental Information on O82
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) - Costs Incurred for Property Acquisition Exploration and Development (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Property acquisitions | ||
Proven properties | $ 0 | $ 298,627 |
Unproven properties | 0 | 40,800 |
Development | 29,080 | 5,340 |
Total | $ 29,080 | $ 344,767 |
Supplemental Information on O83
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) - Results of Operations for Producing Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Results of Operations, Expense from Oil and Gas Producing Activities [Abstract] | ||
Production revenue | $ 49,201 | $ 48,834 |
Royalty and overriding royalty revenue | 4,364 | 10,732 |
Total oil and gas related revenue | 53,565 | 59,566 |
Depreciation, depletion and amortization | 40,772 | 23,936 |
Property, franchise and other taxes | 5,210 | 5,529 |
Production costs | 12,871 | 12,544 |
Impairment of oil and gas properties | 367,576 | 0 |
Total operating costs and expense | 426,429 | 42,009 |
Total income from operations | (372,864) | 17,557 |
Nonproduction revenue | $ 400 | $ 1,900 |
Supplemental Information on O84
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Details) | 12 Months Ended | |
Dec. 31, 2015MBoeMMcfMBbls | Dec. 31, 2014MBoeMMcfMBbls | |
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward] | ||
Beginning of period | MBoe | 13,607 | |
Revisions of previous estimates | MBoe | (1,244) | |
Extensions, discoveries and other additions | MBoe | 926 | |
Sales of properties | MBoe | (108) | |
Production | MBoe | (1,663) | |
End of period | MBoe | 11,518 | |
Proved developed reserves | MBoe | 11,251 | 12,221 |
Proved undeveloped reserves | MBoe | 267 | 1,386 |
Williston Basin | ||
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward] | ||
End of period | MBoe | 10,063 | |
Proved Undeveloped Reserves | Williston Basin | ||
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward] | ||
Concentration risk, percentage | 3.00% | |
Brp Llc [Member] | ||
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward] | ||
Percentage of partnership interest owned (percent) | 51.00% | |
Crude Oil (MBbl) | ||
Proved Developed and Undeveloped Reserves [Roll Forward] | ||
Begging of period | 9,983 | |
Revisions of previous estimates | (1,451) | |
Extensions, discoveries and other additions | 776 | |
Sales of properties | (98) | |
Production | (1,136) | |
End of period | 8,074 | |
Proved developed reserves | 7,862 | 8,930 |
Proved undeveloped reserves | 212 | 1,053 |
NGLs (MBbl) | ||
Proved Developed and Undeveloped Reserves [Roll Forward] | ||
Begging of period | 1,229 | |
Revisions of previous estimates | 89 | |
Extensions, discoveries and other additions | 60 | |
Sales of properties | 0 | |
Production | (156) | |
End of period | 1,222 | |
Proved developed reserves | 1,196 | 1,098 |
Proved undeveloped reserves | 26 | 131 |
Natural Gas (MMcf) | ||
Proved Developed and Undeveloped Reserves [Roll Forward] | ||
Begging of period | MMcf | 14,370 | |
Revisions of previous estimates | MMcf | 701 | |
Extensions, discoveries and other additions | MMcf | 541 | |
Sales of properties | MMcf | (62) | |
Production | MMcf | (2,226) | |
End of period | MMcf | 13,324 | |
Proved developed reserves | MMcf | 13,157 | 13,161 |
Proved undeveloped reserves | MMcf | 167 | 1,209 |
Supplemental Information on O85
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Future Cash Flows: | ||
Future cash inflows | $ 364,352 | $ 920,454 |
Production costs | (164,649) | (312,666) |
Development and abandonment costs | (7,826) | (20,072) |
Future net cash flows before 10% discount | 191,877 | 587,716 |
Discount to present value at a 10% annual rate | (75,524) | (282,519) |
Total standardized measure of discounted net cash flows | $ 116,353 | $ 305,197 |
Supplemental Information on O86
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows Oil and Gas (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract] | |
Beginning of the period | $ 305,197 |
Changes in prices and costs | (188,946) |
Changes in quantities | (11,750) |
Changes in future development costs | (12,202) |
Previously estimated development costs incurred during the period | 29,080 |
Additions to proved reserves from extensions, discoveries and improved recovery, less related costs | 11,928 |
Purchases and sales of reserves in place, net | (3,851) |
Accretion of discount | 31,795 |
Sales of oil and gas, net of production costs | (35,112) |
Production timing and other | (9,786) |
Net increase (decrease) | (188,844) |
End of period | $ 116,353 |
Supplemental Information on O87
Supplemental Information on Oil and Gas Exploration and Productions Activities (Unaudited) - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Extractive Industries [Abstract] | ||
Estimated proved reserves (percent) | 100.00% | 100.00% |
Supplemental Quarterly Inform88
Supplemental Quarterly Information (Unaudited) - Selected Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment [Line Items] | |||||||||||
Total revenues and other income | $ 116,063 | $ 125,479 | $ 137,630 | $ 109,677 | $ 137,273 | $ 91,609 | $ 90,561 | $ 80,309 | $ 488,849 | $ 399,752 | $ 358,117 |
Depreciation, depletion and amortization | 18,152 | 26,624 | 30,660 | 25,392 | 30,258 | 18,621 | 16,350 | 14,647 | 100,828 | 79,876 | 64,377 |
Asset impairment | 50,953 | 626,838 | 3,803 | 0 | 20,585 | 0 | 5,624 | 0 | 681,594 | 26,209 | 734 |
Income (loss) from operations | 2,042 | (576,290) | 55,920 | 40,417 | 31,050 | 55,027 | 50,403 | 52,439 | (477,911) | 188,919 | 236,236 |
Net income (loss) | $ (21,786) | $ (600,001) | $ 32,578 | $ 17,489 | $ 8,645 | $ 36,173 | $ 31,407 | $ 32,605 | $ (571,720) | $ 108,830 | $ 172,078 |
Net income per limited partner unit (in dollars per share) | $ (1.75) | $ (47.90) | $ 2.50 | $ 1.40 | $ 0.70 | $ 3.20 | $ 2.80 | $ 2.90 | $ (45.75) | $ 9.42 | $ 15.39 |
Weighted average number of common units outstanding (in shares) | 12,230 | 12,230 | 12,230 | 12,230 | 12,145 | 11,124 | 11,040 | 10,985 | 12,230 | 11,326 | 10,958 |
Goodwill impairment loss | $ 5,500 | ||||||||||
Impairment of intangible assets | $ 5,600 | ||||||||||
Coal Mineral Rights | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment | 8,200 | $ 247,800 | $ 1,500 | $ 16,800 | $ 257,468 | $ 16,793 | $ 734 | ||||
Oil And Gas Mineral Rights | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment | 31,900 | 335,700 | 367,576 | 0 | $ 0 | ||||||
Aggregate Mineral Rights | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment | 3,000 | ||||||||||
Hard Mineral Royalty | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment | $ 43,400 | $ 43,402 | $ 3,013 | ||||||||
Coal Plant | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment | $ 2,300 | $ 800 | |||||||||
Coal Processing and Transportation Assets, and Obsolete Equipment of Logan Office [Member] | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment | 4,700 | ||||||||||
VantaCore Partners LP | Obsolete Plant and Equipment | |||||||||||
Property, Plant and Equipment [Line Items] | |||||||||||
Asset impairment | $ 700 |