Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Billions, except Share data, unless otherwise specified | Dec. 31, 2014 | Feb. 27, 2015 | Jun. 30, 2014 |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | NRP | ||
Entity Registrant Name | NATURAL RESOURCE PARTNERS LP | ||
Entity Central Index Key | 1171486 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 122,299,825 | ||
Entity Public Float | $1.30 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $50,076 | $92,513 |
Accounts receivable, net of allowance for doubtful accounts | 66,455 | 33,737 |
Accounts receivable - affiliates | 9,494 | 7,666 |
Inventory | 5,814 | |
Other | 4,279 | 1,691 |
Total current assets | 136,118 | 135,607 |
Land | 25,243 | 24,340 |
Plant and equipment, net | 60,093 | 26,435 |
Mineral rights, net | 1,781,852 | 1,405,455 |
Intangible assets, net | 60,733 | 66,950 |
Equity and other unconsolidated investments | 264,020 | 269,338 |
Loan financing costs, net | 13,905 | 11,502 |
Long-term contracts receivable - affiliates | 50,008 | 51,732 |
Goodwill | 52,012 | |
Other assets | 740 | 497 |
Total assets | 2,444,724 | 1,991,856 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 32,416 | 8,659 |
Accounts payable - affiliates | 950 | 391 |
Current portion of long-term debt | 80,983 | 80,983 |
Accrued incentive plan expenses - current portion | 7,048 | 8,341 |
Property, franchise and other taxes payable | 8,318 | 7,830 |
Accrued interest | 18,216 | 17,184 |
Total current liabilities | 147,931 | 123,388 |
Deferred revenue | 160,260 | 142,586 |
Accrued incentive plan expenses | 6,554 | 10,526 |
Asset retirement obligation | 4,905 | |
Other non-current liabilities | 10,679 | 14,341 |
Long-term debt | 1,394,240 | 1,084,226 |
Partners' capital: | ||
Common units outstanding: (122,299,825 and 109,812,408) | 709,019 | 606,774 |
General partner's interest | 12,245 | 10,069 |
Non-controlling interest | -650 | 324 |
Accumulated other comprehensive loss | -459 | -378 |
Total partners' capital | 720,155 | 616,789 |
Total liabilities and partners' capital | $2,444,724 | $1,991,856 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Statement of Financial Position [Abstract] | ||
Common units outstanding | 122,299,825 | 109,812,408 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues and other income: | |||
Coal related revenues | $226,724 | $274,194 | $343,352 |
Aggregates related revenues | 54,124 | 13,479 | 9,524 |
Oil and gas related revenues | 59,566 | 17,080 | 9,561 |
Equity and other unconsolidated investment income | 41,416 | 34,186 | |
Property taxes | 13,609 | 15,416 | 15,273 |
Other | 4,313 | 3,762 | 1,437 |
Total revenues and other income | 399,752 | 358,117 | 379,147 |
Operating expenses: | |||
Depreciation, depletion and amortization | 79,876 | 64,377 | 58,221 |
Asset impairments | 26,209 | 734 | 2,568 |
General and administrative | 36,437 | 36,821 | 29,714 |
Property, franchise and other taxes | 21,279 | 16,463 | 17,678 |
Oil and gas lease operating expenses | 9,144 | 739 | |
Aggregates operating expenses | 32,309 | ||
Transportation costs | 1,604 | 1,644 | 1,944 |
Coal royalty and override payments | 3,975 | 1,103 | 1,857 |
Total operating expenses | 210,833 | 121,881 | 111,982 |
Income from operations | 188,919 | 236,236 | 267,165 |
Other income (expense) | |||
Interest expense | -80,185 | -64,396 | -53,972 |
Interest income | 96 | 238 | 162 |
Income before non-controlling interest | 108,830 | 172,078 | 213,355 |
Non-controlling interest | 0 | 0 | 0 |
Net income | 108,830 | 172,078 | 213,355 |
Net income attributable to: | |||
General partner | 2,177 | 3,442 | 4,267 |
Limited partners | 106,653 | 168,636 | 209,088 |
Basic and diluted net income per limited partner unit | $0.94 | $1.54 | $1.97 |
Weighted average number of common units outstanding | 113,262 | 109,584 | 106,028 |
Comprehensive income | $108,749 | $172,143 | $213,405 |
Consolidated_Statements_of_Par
Consolidated Statements of Partners' Capital (USD $) | Total | General Partner [Member] | Common Stock [Member] | Non-Controlling Interest [Member] | Accumulated Other Comprehensive Income (Loss) [Member] |
In Thousands, except Share data | |||||
Balance at Dec. 31, 2011 | $644,915 | $10,517 | $629,253 | $5,638 | ($493) |
Balance, units at Dec. 31, 2011 | 106,027,836 | ||||
Distributions to unitholders | -238,021 | -4,758 | -233,263 | ||
Distributions to non-controlling interests | -2,793 | -2,793 | |||
Cost associated with equity transactions | -59 | -59 | |||
Net income | 213,355 | 4,267 | 209,088 | ||
Loss on interest hedge | 50 | 50 | |||
Comprehensive income | 213,405 | 50 | |||
Balance at Dec. 31, 2012 | 617,447 | 10,026 | 605,019 | 2,845 | -443 |
Balance, units at Dec. 31, 2012 | 106,027,836 | ||||
Issuance of common units | 75,000 | 75,000 | |||
Issuance of common units, shares | 3,784,572 | ||||
Distributions to unitholders | -246,518 | -4,930 | -241,588 | ||
Distributions to non-controlling interests | -2,521 | -2,521 | |||
Capital contribution | 1,531 | 1,531 | |||
Cost associated with equity transactions | -293 | -293 | |||
Net income | 172,078 | 3,442 | 168,636 | ||
Interest rate swap from unconsolidated investments | 13 | 13 | |||
Loss on interest hedge | 52 | 52 | |||
Comprehensive income | 172,143 | 65 | |||
Balance at Dec. 31, 2013 | 616,789 | 10,069 | 606,774 | 324 | -378 |
Balance, units at Dec. 31, 2013 | 109,812,408 | ||||
Issuance of common units | 127,202 | 127,202 | |||
Issuance of common units, shares | 10,059,914 | ||||
Distributions to unitholders | -162,042 | -3,241 | -158,801 | ||
Issuance of common units for acquisitions | 31,604 | 31,604 | |||
Distributions to non-controlling interests | -974 | -974 | |||
Issuance of common units for acquisitions, shares | 2,427,503 | ||||
Capital contribution | 3,240 | 3,240 | |||
Cost associated with equity transactions | -4,413 | -4,413 | |||
Net income | 108,830 | 2,177 | 106,653 | ||
Interest rate swap from unconsolidated investments | -96 | -96 | |||
Unrealized loss on investments | -25 | -25 | |||
Loss on interest hedge | 40 | 40 | |||
Comprehensive income | 108,749 | -81 | |||
Balance at Dec. 31, 2014 | $720,155 | $12,245 | $709,019 | ($650) | ($459) |
Balance, units at Dec. 31, 2014 | 122,299,825 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities: | |||
Net income | $108,830 | $172,078 | $213,355 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 79,876 | 64,377 | 58,221 |
Non-cash interest charge | 3,328 | 2,200 | 605 |
Non-cash gain on reserve swap | -5,690 | -8,149 | |
Equity and other unconsolidated investment income | -41,416 | -34,186 | |
Distributions of earnings from unconsolidated investments | 43,005 | 24,113 | |
Gain on sale of assets | -1,386 | -10,921 | -13,575 |
Asset impairment | 26,209 | 734 | 2,568 |
Change in operating assets and liabilities (net of effects of acquisitions): | |||
Inventory | 748 | ||
Accounts receivable | -10,693 | 6,826 | -802 |
Other assets | -795 | -516 | -236 |
Accounts payable and accrued liabilities | -4,411 | 2,197 | 1,909 |
Accrued interest | 1,032 | 6,919 | -496 |
Deferred revenue | 17,674 | 19,240 | 11,684 |
Accrued incentive plan expenses | -5,265 | 2,284 | -3,461 |
Property, franchise and other taxes payable | -291 | -122 | 1,636 |
Net cash provided by operating activities | 210,755 | 247,074 | 271,408 |
Cash flows from investing activities: | |||
Acquisition of land, coal, other mineral rights and related intangibles | -339,768 | -72,000 | -180,534 |
Acquisition of equity interests | -293,085 | ||
Acquisition of aggregates business | -168,978 | ||
Oil and gas capital expenditures | -16,258 | ||
Distributions from unconsolidated investments | 3,633 | 48,833 | |
Acquisition of plant and equipment | -2,454 | -681 | |
Proceeds from sale of assets | 1,418 | 10,929 | 24,822 |
Return on direct financing lease and contractual override | 1,904 | 2,558 | 2,669 |
Investment in direct financing lease | -59,009 | ||
Net cash used in investing activities | -520,503 | -302,765 | -212,733 |
Cash flows from financing activities: | |||
Proceeds from loans | 637,375 | 567,020 | 148,000 |
Proceeds from issuance of common units | 127,202 | 75,000 | |
Deferred financing costs | -5,094 | -9,209 | |
Repayments of loans | -327,983 | -386,230 | -30,800 |
Payment of obligation related to acquisitions | -500 | ||
Costs associated with equity transactions | -4,413 | -293 | -59 |
Distributions to unitholders | -162,042 | -246,518 | -238,021 |
Distributions to non-controlling interests | -974 | -2,521 | -2,793 |
Capital contribution by general partner | 3,240 | 1,531 | |
Net cash provided by (used in) financing activities | 267,311 | -1,220 | -124,173 |
Net (decrease) in cash and cash equivalents | -42,437 | -56,911 | -65,498 |
Cash and cash equivalents at beginning of period | 92,513 | 149,424 | 214,922 |
Cash and cash equivalents at end of period | 50,076 | 92,513 | 149,424 |
Supplemental cash flow information: | |||
Cash paid during the period for interest | 76,155 | 55,191 | 53,842 |
Non-cash investing activities: | |||
Units issued for acquisition of aggregate operations | 31,604 | ||
Note receivable related to sale of assets | 1,808 | ||
Non-cash contingent consideration on equity investments | $15,000 |
Basis_of_Presentation_and_Orga
Basis of Presentation and Organization | 12 Months Ended |
Dec. 31, 2014 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Organization | 1. Basis of Presentation and Organization |
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, 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. | |
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, which was acquired in October 2014. VantaCore specializes in the construction materials industry and operates three hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal. VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. | |
The Partnership also owns a 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. OCI 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 the 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 and NRP Oil and Gas LLC. NRP GP has sole responsibility for conducting its 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, five of whom must be independent 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_Account
Summary of Significant Accounting Policies | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||||||||||
Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies | ||||||||||||||||||||||||||||
Reclassification | |||||||||||||||||||||||||||||
Certain reclassifications have been made to the Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s coal royalties, processing fees, transportation fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item “Coal related revenues” on this year’s Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s aggregates royalties, processing fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item “Aggregates related revenues” on this year’s Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s oil and gas revenues and minimums recognized as revenue have been reclassified into a single line item “Oil and gas related revenues” on this year’s Consolidated Statements of Comprehensive Income. The following is reclassification reconciliation: | |||||||||||||||||||||||||||||
For The Year Ended | For The Year Ended | ||||||||||||||||||||||||||||
December 31, 2013 | December 31, 2012 | ||||||||||||||||||||||||||||
As | As | As | As | ||||||||||||||||||||||||||
Reported | Reclassified | Reported | Reclassified | ||||||||||||||||||||||||||
Total | Coal | Aggregates | Total | Coal | Aggregates | Oil & Gas | |||||||||||||||||||||||
Related | Related | Related | Related | Related | |||||||||||||||||||||||||
Revenues | Revenues | Revenues | Revenues | Revenues | |||||||||||||||||||||||||
Revenues: | |||||||||||||||||||||||||||||
Coal royalties | $ | 212,663 | $ | 212,663 | $ | — | $ | 260,734 | $ | 260,734 | $ | — | $ | — | |||||||||||||||
Equity and other unconsolidated investment income | 34,186 | — | — | — | — | — | — | ||||||||||||||||||||||
Aggregate royalties | 7,643 | — | 7,643 | 6,598 | — | 6,598 | — | ||||||||||||||||||||||
Processing fees | 5,049 | 4,542 | 507 | 8,299 | 7,841 | 458 | — | ||||||||||||||||||||||
Transportation fees | 17,977 | 17,977 | — | 19,513 | 19,513 | — | — | ||||||||||||||||||||||
Oil and gas royalties | 17,080 | — | — | 9,160 | — | — | 9,160 | ||||||||||||||||||||||
Property taxes | 15,416 | — | — | 15,273 | — | — | — | ||||||||||||||||||||||
Minimums recognized as revenue | 8,285 | 6,528 | 1,757 | 23,956 | 23,029 | 526 | 401 | ||||||||||||||||||||||
Override royalties | 13,499 | 10,372 | 3,127 | 15,527 | 13,979 | 1,548 | — | ||||||||||||||||||||||
Other | 26,319 | 22,112 | 445 | 20,087 | 18,256 | 394 | — | ||||||||||||||||||||||
Total revenues | $ | 358,117 | $ | 274,194 | $ | 13,479 | $ | 379,147 | $ | 343,352 | $ | 9,524 | $ | 9,561 | |||||||||||||||
Principles of Consolidation | |||||||||||||||||||||||||||||
The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC, a joint venture with International Paper Company controlled by the Partnership. Intercompany transactions and balances have been eliminated. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
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. Accounts are charged off when collection efforts are complete and future recovery is doubtful. | |||||||||||||||||||||||||||||
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 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 initially recorded using the FASB’s business combination and asset purchase authoritative guidance depending on circumstances. 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 minerals, 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. | |||||||||||||||||||||||||||||
Equity Investments | |||||||||||||||||||||||||||||
The Partnership accounts for non-marketable investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if the Partnership has an ownership interest representing between 20% and 50% of the voting stock of the investee. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
The Partnership’s carrying value in an equity method investee company is reflected in the caption “Equity and other unconsolidated investments” in the Partnership’s Consolidated Balance Sheets. The Partnership’s adjusted share of the earnings or losses of the investee company is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity and other unconsolidated investment income.” These earnings are generated from natural resources, which are considered part of the Partnership’s 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. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
Asset Impairment | |||||||||||||||||||||||||||||
The Partnership has developed procedures to periodically evaluate its 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. 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, the Partnership intends to closely monitor its coal and oil and gas assets and the impairment evaluation process may be completed more frequently if deemed necessary by the Partnership. Future impairment analyses could result in downward adjustments to the carrying value of the Partnership’s assets. | |||||||||||||||||||||||||||||
The Partnership evaluates its 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. No impairment losses have been recognized for equity investments as of December 31, 2014. | |||||||||||||||||||||||||||||
In accordance with accounting and disclosure guidance for goodwill, the Partnership tests its 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 the reporting units, business, industry, or economic trends. | |||||||||||||||||||||||||||||
Share-Based Payment | |||||||||||||||||||||||||||||
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 service or vesting 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. Incentive Plans.” | |||||||||||||||||||||||||||||
Deferred Revenue | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
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 and environmental 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.” | |||||||||||||||||||||||||||||
Revenues | |||||||||||||||||||||||||||||
Coal related revenues. Coal related revenue consist primarily of royalties as well as transportation and processing fees. Royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership 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 the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to the Partnership 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. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, the Partnership receives a fixed price per ton for all material transported on the beltlines. | |||||||||||||||||||||||||||||
Oil and Gas Revenues. Oil and gas related revenues consist of non-operated working interests, royalties and overriding royalties. Revenues related to the Partnership’s non-operated working interests in oil and gas assets are recognized based on the amount actually sold. The Partnership also has capital expenditure and operating expenditure obligations associated with the non-operated working interests. The Partnership’s 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 the 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. Some leases are subject to minimum annual payments or delay rentals. | |||||||||||||||||||||||||||||
Aggregates and Industrial Minerals Related Revenues. Aggregates and industrial minerals related revenues consist primarily of revenues generated by VantaCore’s construction aggregates business, royalties and overriding royalties. 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 at either market or contractual prices. Aggregates royalty and overriding royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. 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 the Partnership considers 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. | |||||||||||||||||||||||||||||
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 Property taxes revenue and in Property, franchise and other taxes expense, respectively, in the Consolidated Statements of Comprehensive Income. | |||||||||||||||||||||||||||||
Transportation Revenue and Expense | |||||||||||||||||||||||||||||
Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as Aggregate related revenues and Aggregates operating expenses in the Consolidated Statements of Comprehensive Income. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
New Accounting Standards | |||||||||||||||||||||||||||||
In May 2014, the FASB amended revenue recognition topics and created a new topic relating to revenue recognition that will supersede existing guidance under U.S. GAAP. The core principle of the new guidance is to recognize revenue when promised goods or services are transferred to the customer and in an amount that reflects the consideration expected in exchange for those goods or services. To achieve this core principle, an entity should (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when each performance obligation is satisfied. The guidance also specifies the accounting for some costs to obtain or fulfill a contract with a customer. Disclosure requirements include sufficient qualitative and quantitative information to enable financial statement users to understand the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. The new topic is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The guidance allows for either full adoption or a modified retrospective adoption. The Partnership is currently evaluating the requirements to determine the impact, if any, of this new topic on its financial position, results of operations and cash flows. | |||||||||||||||||||||||||||||
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows. |
Significant_Acquisitions
Significant Acquisitions | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Business Combinations [Abstract] | |||||||||
Significant Acquisitions | 3. Significant Acquisitions | ||||||||
VantaCore. Consistent with the Partnership’s diversification plan, on October 1, 2014, the Partnership completed its acquisition of VantaCore Partners LLC (“VantaCore”), a privately held company specializing in the construction materials industry, for $201 million in cash and common units. Headquartered in Philadelphia, Pennsylvania, VantaCore operates three hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal. VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. | |||||||||
Transaction costs through December 31, 2014 associated with this acquisition were $2.9 million and were expensed as incurred. These expenses are reflected in General and administrative expense on the Consolidated Statements of Comprehensive Income. Included in the consolidated statements of comprehensive income for the year ended December 31, 2014 were revenue of $42.1 million and operating expenses of $32.3 million, including depreciation and depletion of $3.2 million. | |||||||||
The Partnership accounted for the transaction in accordance with the authoritative guidance for business combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 1, 2014. The following table summarizes the purchase price and the preliminary estimated values of assets acquired and liabilities assumed and are subject to revision as the Partnership continues to complete appraisals of the fair value of the assets acquired and liabilities assumed. The preliminary allocation was based on the book values of the assets and liabilities assumed with the excess of purchase price over net book value allocated to goodwill. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition. | |||||||||
Preliminary Purchase Price Allocation—VantaCore Partners LLC Acquisition | |||||||||
October 1, 2014 | |||||||||
(In thousands) | |||||||||
Consideration | |||||||||
Cash | $ | 168,978 | |||||||
NRP common units(1) | 31,604 | ||||||||
Total consideration given | $ | 200,582 | |||||||
Preliminary Allocation of Purchase Price | |||||||||
Current assets | $ | 37,222 | |||||||
Land, property and equipment | 40,411 | ||||||||
Mineral rights | 87,907 | ||||||||
Other assets | 3,268 | ||||||||
Current liabilities | (16,953 | ) | |||||||
Asset retirement obligation | (3,285 | ) | |||||||
Goodwill | 52,012 | ||||||||
Fair value of net assets acquired | $ | 200,582 | |||||||
-1 | Includes 2,426,690 units issued on October 1, 2014 at $13.02, closing price on that day and 813 units issued for a post-closing adjustment on December 4, 2014 at $10.48. | ||||||||
Sanish Field. Consistent with the Partnership’s diversification plans, in November 2014, the Partnership completed the purchase of a 40% member interest in Kaiser-Whiting, LLC (“Kaiser LLC”) for $339 million, subject to customary post-closing purchase price adjustments. Effective November 13, 2014, NRP Oil and Gas withdrew as a member of Kaiser LLC and an undivided 40% interest in Kaiser LLC’s assets was distributed out of Kaiser LLC, and assigned directly to the Partnership. The assets distributed to the Partnership included non-operated working interests in approximately 6,086 net acres with an average working interest of approximately 14.5%. The assets, located in the Sanish Field in Mountrail County, North Dakota, are all held by production and include 192 producing wells. | |||||||||
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 General and administrative expense on the Consolidated Statements of Comprehensive Income. Included in the consolidated statements of comprehensive income for the year ended December 31, 2014, was revenue of $12.8 million and operating costs of $9.1 million including depletion expense of $6.7 million related to the Sanish Field acquisition. | |||||||||
The Partnership accounted for the transaction in accordance with the authoritative guidance for business combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 12, 2014. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and are subject to revision as the Partnership continues to complete appraisals of the fair value of the assets and liabilities assumed. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition. | |||||||||
Preliminary Purchase Price Allocation—Sanish Field Acquisition | |||||||||
November 12, 2014 | |||||||||
(In thousands) | |||||||||
Mineral rights | |||||||||
Proven oil and gas properties | $ | 298,627 | |||||||
Probable and possible resources | 40,800 | ||||||||
Total fair value of oil and gas properties acquired | 339,427 | ||||||||
Asset retirement obligation | (427 | ) | |||||||
Fair value of net assets acquired | $ | 339,000 | |||||||
Pending the final purchase price adjustments and allocation, the net assets acquired of approximately $339.4 million are included in Mineral Rights in the accompanying Consolidated Balance Sheet. The acquisition qualifies as a business combination, and as such, the Partnership estimated the fair value of each asset acquired and liability assumed as of the acquisition date. Fair value measurements utilize assumptions of market participants. To determine the fair value of the oil and gas assets, the Partnership used an income approach based on a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. The Partnership determined the appropriate discount rates used for the discounted cash flow analyses by using a weighted average cost of capital from a market participant perspective plus reserve-specific risk premiums for the assets acquired. The Partnership estimated reserve-specific risk premiums taking into consideration that the related reserves are primarily oil, among other hydrocarbons. Given the unobservable nature of some of the significant inputs, they are deemed to be Level 3 in the fair value hierarchy. The initial estimate of asset retirement obligation liability was based upon historical information from Kaiser LLC. | |||||||||
Pro Forma Financial Information | |||||||||
As stated above, the Partnership completed the Sanish Field acquisition on November 13, 2014 and the VantaCore acquisition on October 1, 2014. Below are the combined results of operations for the twelve months ended December 31, 2014 and 2013 as if the acquisitions had occurred on January 1, 2013. | |||||||||
The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of Partnership units and debt and additional depletion expense as a result of the Kaiser and VantaCore acquisitions. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Partnership to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. | |||||||||
For the Years ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Revenue and other income except aggregate and oil and gas related revenues | $ | 286,062 | $ | 327,558 | |||||
Aggregates related revenues | 137,220 | 152,032 | |||||||
Oil and gas related revenues | 110,235 | 100,343 | |||||||
Total revenue | $ | 533,517 | $ | 579,933 | |||||
Net income | $ | 122,319 | $ | 197,164 | |||||
Basic and diluted net income per limited partner unit | $ | 0.99 | $ | 1.6 | |||||
Sundance. On December 19, 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. On August 9, 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 $36.1 million, capital expenditures of $22.9 and operating expenses of $12.3 million were included in the Consolidated Statements of Comprehensive Income and Consolidated Balance Sheet for the year ended December 31, 2014. For the year ended December 31, 2013, revenues and total operating expenses from the Abraxas and Sundance acquisitions were $5.4 million and $2.9 million, respectively. |
Equity_and_Other_Investments
Equity and Other Investments | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||
Equity and Other Investments | 4. Equity and Other Investments | ||||||||
The Partnership owns a 49% non-controlling equity interest in OCI Wyoming LLC (OCI Wyoming). The investment was acquired from Anadarko Holding Company (Anadarko) and its subsidiary, Big Island Trona Company for $292.5 million during 2013. OCI Wyoming’s operations consist of the mining of trona ore, which, when refined, become soda ash. All soda ash is sold through an affiliated sales agent to various domestic and European customers and to American Natural Soda Ash Corporation for export primarily to Asia and Latin America. Included in fair value adjustments, is an increase in the Partnership’s proportionate fair value of property, plant and equipment of $65.4 million, which will be depreciated using the straight-line method over a weighted average life of 28 years. Also, $132.7 million has been assigned to a right to mine asset which will be amortized using the units of production method. Under the equity method of accounting, these amounts are not reflected individually in the accompanying consolidated financial statements but are used to determine periodic charges to amounts reflected as income earned from the equity investment. | |||||||||
The acquisition agreement provides for a net present value of up to $50 million in cumulative additional contingent consideration payable by the Partnership should certain performance criteria as defined in the purchase and sale agreement be met by OCI Wyoming in any of the years 2013, 2014 or 2015. At December 31, 2014, the Partnership had accrued $14.5 million of contingent consideration that is included in Equity and other unconsolidated investments. The current portion of $3.8 million is included in Accounts payable and accrued liabilities and the long term portion of $10.7 million is included in Other non-current liabilities. During 2014 the Partnership paid a $0.5 million payment for contingent consideration. | |||||||||
The table below summarizes the differences between the carrying amount of the Partnership’s investment and the amount of the Partnership’s underlying equity in the net assets of OCI Wyoming. For both the twelve month periods ended December 31, 2014 and 2013, the Partnership derived approximately 10% of its revenues and other income from its equity investment in OCI Wyoming. | |||||||||
For the Year Ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Net book value of NRP’s equity interests | $ | 101,311 | $ | 96,692 | |||||
Equity and other unconsolidated investments | $ | 264,020 | $ | 269,338 | |||||
Excess of NRP’s investment over net book value of NRP’s equity interest | $ | 162,709 | $ | 172,646 | |||||
Income allocation to NRP’s equity interests | $ | 47,354 | $ | 37,036 | |||||
Amortization of basis difference | $ | (5,938 | ) | $ | (2850 | ) | |||
Equity and other unconsolidated investment income | $ | 41,416 | $ | 34,186 | |||||
The following summarized financial information was taken from the OCI Wyoming-prepared financial statements. | |||||||||
For the Year Ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Sales | $ | 465,032 | $ | 442,132 | |||||
Gross profit | $ | 118,439 | $ | 94,299 | |||||
Net Income | $ | 96,640 | $ | 79,655 | |||||
Current assets | $ | 200,622 | $ | 201,265 | |||||
Noncurrent assets | $ | 202,282 | $ | 194,508 | |||||
Current liabilities | $ | 47,704 | $ | 39,663 | |||||
Noncurrent liabilities | $ | 149,192 | $ | 158,779 |
Allowance_for_Doubtful_Account
Allowance for Doubtful Accounts | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Text Block [Abstract] | |||||||||||||
Allowance for Doubtful Accounts | 5. Allowance for Doubtful Accounts | ||||||||||||
Activity in the allowance for doubtful accounts for the years ended December 31, 2014, 2013 and 2012 was as follows: | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Balance, January 1 | $ | 275 | $ | 711 | $ | 393 | |||||||
Provision charged to operations: | |||||||||||||
Additions to the reserve | 774 | 278 | 318 | ||||||||||
Collections of previously reserved accounts | (373 | ) | — | — | |||||||||
Total charged (credited) to operations | 401 | 278 | 318 | ||||||||||
Non-recoverable balances written off | — | (714 | ) | — | |||||||||
Balance, December 31 | $ | 676 | $ | 275 | $ | 711 | |||||||
The Partnership acquired $0.5 million of allowances for doubtful accounts with its acquisition of VantaCore. |
Inventory
Inventory | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Inventory Disclosure [Abstract] | |||||
Inventory | 6. Inventory | ||||
The components of inventories at December 31, 2014 are as follows: | |||||
2014 | |||||
(In thousands) | |||||
Aggregates | $ | 4,596 | |||
Supplies and parts | 1,218 | ||||
$ | 5,814 | ||||
All of the Partnership’s inventory for 2014 was acquired with its acquisition of VantaCore. For the year ended December 31, 2013, the Partnership did not have inventory. |
Plant_and_Equipment
Plant and Equipment | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||
Plant and Equipment | 7. Plant and Equipment | ||||||||||||
The Partnership’s plant and equipment consist of the following: | |||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
(In thousands) | |||||||||||||
Construction in process | $ | 457 | $ | — | |||||||||
Plant and equipment at cost | 89,759 | 55,271 | |||||||||||
Less accumulated depreciation | (30,123 | ) | (28,836 | ) | |||||||||
Net book value | $ | 60,093 | $ | 26,435 | |||||||||
For the Years ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Total depreciation expense on plant and equipment | $ | 7,631 | $ | 5,966 | $ | 6,825 | |||||||
During the fourth quarter of 2014, the Partnership impaired a preparation plant. The impairment charge was $0.8 million and is included in Asset impairments in the Consolidated Statements of Comprehensive Income for the year ending December 31, 2014. |
Mineral_Rights
Mineral Rights | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Extractive Industries [Abstract] | |||||||||||||
Mineral Rights | 8. Mineral Rights | ||||||||||||
The Partnership’s mineral rights consist of the following: | |||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
(In thousands) | |||||||||||||
Coal | $ | 1,541,572 | $ | 1,574,914 | |||||||||
Oil and gas | 560,395 | 204,906 | |||||||||||
Aggregates | 211,490 | 100,080 | |||||||||||
Other | 15,014 | 15,020 | |||||||||||
Less accumulated depletion and amortization | (546,619 | ) | (489,465 | ) | |||||||||
Net book value | $ | 1,781,852 | $ | 1,405,455 | |||||||||
For the years ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Total depletion and amortization expense on mineral interests | $ | 68,603 | $ | 54,595 | $ | 47,042 | |||||||
During its annual impairment analysis, the Partnership 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. While these conditions affect the Partnership’s ability to lease properties, other events such as a lessee’s bankruptcy, a lease cancellation, lease modifications, a permanent idling of a property could result in triggering events warranting further analysis. 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. The resulting impairment expense of $19.8 million relating to coal and aggregates mineral properties is included in Asset impairments on the Consolidated Statements of Comprehensive Income. |
Intangible_Assets
Intangible Assets | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||
Intangible Assets | 9. Intangible Assets | ||||||||||||
Amounts recorded as intangible assets along with the balances and accumulated amortization at December 31, 2014 and 2013 are reflected in the table below: | |||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
(In thousands) | |||||||||||||
Contract intangibles | $ | 82,972 | $ | 89,421 | |||||||||
Other intangibles | 3,004 | — | |||||||||||
Less accumulated amortization | (25,243 | ) | (22,471 | ) | |||||||||
Net book value | $ | 60,733 | $ | 66,950 | |||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Total amortization expense on intangible assets | $ | 3,642 | $ | 3,816 | $ | 4,354 | |||||||
Included in intangible assets are certain contract intangibles with a net book value of $1.3 million at December 31, 2014 that were deemed held for sale. During the fourth quarter $52.0 million of goodwill was added relating to the VantaCore acquisition. This amount represents the preliminary residual value and will be adjusted as the Partnership continues complete appraisals of fair value relating to the acquisition. | |||||||||||||
During the second quarter of 2014, the Partnership and a lessee amended an aggregates lease, 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. | |||||||||||||
Estimated amortization expense (In thousands) | |||||||||||||
For year ended December 31, 2015 | $ | 3,486 | |||||||||||
For year ended December 31, 2016 | 3,743 | ||||||||||||
For year ended December 31, 2017 | 3,326 | ||||||||||||
For year ended December 31, 2018 | 3,126 | ||||||||||||
For year ended December 31, 2019 | 3,053 | ||||||||||||
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||
Long-Term Debt | 10. Long-Term Debt | ||||||||||||||||||||||||
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 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. | |||||||||||||||||||||||||
Long-term debt consists of the following: | |||||||||||||||||||||||||
December 31, | December 31, | ||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||
NRP LP Debt: | |||||||||||||||||||||||||
$425 million 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% | $ | 422,167 | $ | 297,170 | |||||||||||||||||||||
Opco Debt: | |||||||||||||||||||||||||
$300 million floating rate revolving credit facility, due August 2016 | 200,000 | 20,000 | |||||||||||||||||||||||
$200 million floating rate term loan, due January 2016 | 75,000 | 99,000 | |||||||||||||||||||||||
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018 | 18,467 | 23,084 | |||||||||||||||||||||||
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019 | 107,143 | 128,571 | |||||||||||||||||||||||
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020 | 46,154 | 53,846 | |||||||||||||||||||||||
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 | 1,345 | 1,538 | |||||||||||||||||||||||
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023 | 24,300 | 27,000 | |||||||||||||||||||||||
4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2023 | 67,500 | 75,000 | |||||||||||||||||||||||
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024 | 150,000 | 165,000 | |||||||||||||||||||||||
8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 | 45,455 | 50,000 | |||||||||||||||||||||||
5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 | 161,538 | 175,000 | |||||||||||||||||||||||
5.18% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 | 46,154 | 50,000 | |||||||||||||||||||||||
NRP Oil and Gas Debt: | |||||||||||||||||||||||||
Reserve-based revolving credit facility due 2019 | 110,000 | — | |||||||||||||||||||||||
Total debt | 1,475,223 | 1,165,209 | |||||||||||||||||||||||
Less—current portion of long term debt | (80,983 | ) | (80,983 | ) | |||||||||||||||||||||
Long-term debt | $ | 1,394,240 | $ | 1,084,226 | |||||||||||||||||||||
NRP LP Debt | |||||||||||||||||||||||||
Senior Notes. In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300 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 of approximately $289.0 million were used to repay all of the outstanding borrowings under Opco’s revolving credit facility and $91.0 million of Opco’s term loan. The senior notes call for semi-annual interest payments on April 1 and October 1 of each year, beginning on April 1, 2014. The notes will mature on October 1, 2018. | |||||||||||||||||||||||||
In October 2014, NRP LP, together with NRP Finance as co-issuer, issued an additional $125 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 after expenses from the issuance of the Senior Notes of approximately $122.6 million 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 as April 1 and October 1 of each year, beginning on April 1, 2015. The notes will mature on October 1, 2018. | |||||||||||||||||||||||||
The indenture for the senior notes contains covenants that, among other things, limit the ability of the 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. | |||||||||||||||||||||||||
Opco Debt | |||||||||||||||||||||||||
Senior Notes. Opco made principal payments of $80.8 million on its senior notes during the year ended December 31, 2014. The Opco senior note purchase agreement contains 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 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 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. | |||||||||||||||||||||||||
Revolving Credit Facility. The weighted average interest rates for the debt outstanding under Opco’s revolving credit facility for the twelve months ended December 31, 2014 and year ended December 31, 2013 were 1.98% and 2.23%, respectively. Opco incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.18% to 0.40% per annum. The facility includes an accordion feature whereby Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms. | |||||||||||||||||||||||||
Opco’s revolving credit facility contains covenants requiring Opco to maintain: | |||||||||||||||||||||||||
• | a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and, | ||||||||||||||||||||||||
• | a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent quarters. | ||||||||||||||||||||||||
Term Loan Facility. During 2013, Opco issued $200 million in term debt. The weighted average interest rates for the debt outstanding under the term loan for the twelve months ended December 31, 2014 and 2013 were 2.22% and 2.43% respectively. Opco repaid $101 million in principal under the term loan during the third quarter of 2013 and an additional $24 million during the fourth quarter of 2014. Repayment terms call for the remaining outstanding balance of $75 million to be paid on January 23, 2016. The debt is unsecured but guaranteed by the subsidiaries of Opco. | |||||||||||||||||||||||||
Opco’s term loan contains covenants requiring Opco to maintain: | |||||||||||||||||||||||||
• | a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and, | ||||||||||||||||||||||||
• | a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent quarters. | ||||||||||||||||||||||||
NRP Oil and Gas Debt | |||||||||||||||||||||||||
Revolving Credit Facility. In August 2013, NRP Oil and Gas entered into a 5-year, $100 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 be a $500 million facility with an initial borrowing base of $137 million and will mature on November 12, 2019. 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. At December 31, 2014, there was $110.0 million outstanding under the credit facility. The weighted average interest rate for the debt outstanding under the credit facility for the twelve months ended December 31, 2014 was 2.37%. | |||||||||||||||||||||||||
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. | ||||||||||||||||||||||||
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. | |||||||||||||||||||||||||
Consolidated Principal Payments | |||||||||||||||||||||||||
The consolidated principal payments due are set forth below: | |||||||||||||||||||||||||
NRP LP | Opco | NRP | |||||||||||||||||||||||
Oil and Gas | |||||||||||||||||||||||||
Senior Notes | Senior Notes | Credit Facility | Term Loan | Credit Facility | Total | ||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||
2015 | $ | — | $ | 80,983 | $ | — | $ | — | $ | — | $ | 80,983 | |||||||||||||
2016 | — | 80,983 | 200,000 | 75,000 | — | 355,983 | |||||||||||||||||||
2017 | — | 80,983 | — | — | — | 80,983 | |||||||||||||||||||
2018 | 425,000 | (1) | 80,983 | — | — | — | 505,983 | ||||||||||||||||||
2019 | — | 76,366 | — | — | 110,000 | 186,366 | |||||||||||||||||||
Thereafter | — | 267,758 | — | — | — | 267,758 | |||||||||||||||||||
$ | 425,000 | $ | 668,056 | $ | 200,000 | $ | 75,000 | $ | 110,000 | $ | 1,478,056 | ||||||||||||||
-1 | The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2014 were carried at $422.2 million. | ||||||||||||||||||||||||
NRP LP, Opco and NRP Oil and Gas were in compliance with all terms under their long-term debt as of December 31, 2014. Opco’s revolving credit facility and term loan facility both mature in 2016. While the Partnership believes it has sufficient liquidity to meet its current financial needs, the Partnership will be required to repay or refinance the amounts outstanding under Opco’s credit facilities prior to their maturity. While the Partnership believes it will be able to refinance these amounts, it may not be able to do so on terms acceptable to them, if at all, or the borrowing capacity under Opco’s revolving credit facility may be substantially reduced. The Partnership’s ability to refinance these amounts may depend in part on its ability to access the debt or equity capital markets, which will be challenging in the current commodity price environment. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Value Measurements | 11. Fair Value Measurements | ||||||||||||||||
The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of the Partnership’s financial instruments included in accounts receivable and accounts payable approximates their fair value due to their short-term nature except for the accounts receivable—affiliate relating to the Sugar Camp override that includes both current and long-term portions. The Partnership’s cash and cash equivalents include money market accounts and are considered a Level 1 measurement. The fair market value and carrying value of the contractual override and long-term senior notes are as follows: | |||||||||||||||||
Fair Value As Of | Carrying Value As Of | ||||||||||||||||
December 31, | December 31, | December 31, | December 31, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
(In thousands) | |||||||||||||||||
Assets | |||||||||||||||||
Sugar Camp override, current and long-term | $ | 5,162 | $ | 6,852 | $ | 4,870 | $ | 6,063 | |||||||||
Liabilities | |||||||||||||||||
Long-term debt, current and long-term | $ | 1,096,520 | $ | 1,071,880 | $ | 1,090,223 | $ | 1,046,209 | |||||||||
The fair value of the Sugar Camp override and long-term debt is estimated by discounting expected future cash flows at a comparable term risk-free treasury interest rate plus a market rate component comparable to the yield premium observed on debt securities of similar risk and maturity, which is a Level 3 measurement. Since the Partnership’s credit facilities and term loan are variable rate debt, their fair values approximate their carrying amounts. |
Related_Party_Transactions
Related Party Transactions | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Related Party Transactions [Abstract] | |||||||||||||
Related Party Transactions | 12. Related Party Transactions | ||||||||||||
Reimbursements to Affiliates of the Partnership’s 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. All 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. The Partnership had accounts payable of $0.4 million with Western Pocahontas Properties and $0.6 million with Quintana Minerals Corporation. | |||||||||||||
The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as follows: | |||||||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Reimbursement for services | $ | 11,798 | $ | 11,480 | $ | 9,791 | |||||||
The Partnership leases an office building in Huntington, West Virginia from Western Pocahontas Properties and pays $0.6 million in lease payments each year through December 31, 2018. | |||||||||||||
Transactions with Cline Affiliates | |||||||||||||
Various companies controlled by Chris Cline, including Foresight Energy LP, lease coal reserves from the Partnership, and the Partnership provides coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest (unaudited) in the Partnership’s general partner, as well as 4,917,548 common units (unaudited) at December 31, 2014. At December 31, 2014, the Partnership had accounts receivable totaling $9.2 million from Cline affiliates. In addition, the overriding royalty and the lease of the loadout facility at the Sugar Camp mine are classified as contracts receivable of $50.0 million on the Partnership’s Consolidated Balance Sheets. Revenues from the Cline affiliates are as follows: | |||||||||||||
For The Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Coal royalty revenues | $ | 52,415 | $ | 54,322 | $ | 48,567 | |||||||
Processing and transportation fees | 20,594 | 19,258 | 21,923 | ||||||||||
Minimums recognized as revenue | — | 3,477 | 17,785 | ||||||||||
Override revenue | 2,847 | 3,226 | 4,066 | ||||||||||
Other revenue | 5,690 | 8,149 | — | ||||||||||
$ | 81,546 | $ | 88,432 | $ | 92,341 | ||||||||
As of December 31, 2014, the Partnership had received $86.8 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $16.0 million was received during 2014. | |||||||||||||
During the fourth quarter of 2012, the Partnership recognized an asset impairment of $2.6 million related to the assets at the Gatling, WV location, a location leased to an affiliate of Chris Cline, due to receiving a termination notice in December 2012 that the lease was cancelled as of June 2013. | |||||||||||||
During 2014 and 2013, the Partnership recognized gains of $5.7 million and $8.1 million on reserve swaps in Illinois with Williamson Energy, a subsidiary of Foresight Energy LP. The gains are reflected in the table above in the “Other revenue” line. The fair value of the reserves was estimated using Level 3 cash flow approach. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates. The tons received during 2014 and 2013 were fully mined during each of those years, while the tons exchanged are not included in the current mine plans. The gains are located in Coal related revenues on the Consolidated Statements of Comprehensive Income. | |||||||||||||
The Partnership entered into a lease agreement related to the rail loadout and associated facilities at Sugar Camp that has been accounted for as a direct financing lease. Total projected remaining payments under the lease at December 31, 2014 are $86.3 million with unearned income of $39.0 million. The net amount receivable under the lease as of December 31, 2014 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—affiliate on the accompanying Consolidated Balance Sheets. | |||||||||||||
In a separate transaction, the Partnership acquired a contractual overriding royalty interest from a Cline affiliate that provides for payments based upon production from specific tons at the 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, 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. | |||||||||||||
Note to Cline Trust Company, LLC | |||||||||||||
Donald R. Holcomb, one of the Partnership’s directors, is a manager of Cline Trust Company, LLC, which owns approximately 5.35 million of the Partnership’s common units and $20 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 Christopher 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 million of the Partnership’s 9.125% Senior Notes due 2018 in the Partnership’s offering of $125 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, 2014 and is included with the Partnership’s long term debt. | |||||||||||||
Quintana Capital Group GP, Ltd. | |||||||||||||
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., 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 NRP’s conflicts policy. | |||||||||||||
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. | |||||||||||||
For the years ended December 31, 2014, 2013 and 2012, the revenues from Taggart prior to the sale to Forge were as follows: | |||||||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Processing revenue | $ | — | $ | 1,761 | $ | 5,580 | |||||||
During the third quarter of 2012, the Partnership sold a preparation plant back to Taggart Global for $12.3 million. The Partnership received $10.5 million in cash and a note receivable from Taggart, payable over three years for the balance. The Partnership recorded a gain of $4.7 million included in Coal related revenues on the Consolidated Statements of Income during 2012. The net book value of the asset sold was $7.6 million. During 2013, the note receivable that the Partnership held was paid in full. | |||||||||||||
At December 31, 2014, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp., 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. Revenues from Corsa are as follows: | |||||||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Coal royalty revenues | $ | 3,013 | $ | 4,594 | $ | 3,486 | |||||||
At each of December 31, 2013 and 2014, the Partnership also had accounts receivable totaling $ 0.3 million from Corsa. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||
Asset Retirement Obligations | 13 | 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 of the beginning and ending carrying amounts of the Partnership’s asset retirement obligations. The table does not include the short-term balance of $68,000, which is included in Accounts payable and accrued 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, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Balance, January 1 | $ | 39 | $ | 39 | |||||
Liabilities incurred in current period | 4,697 | — | |||||||
Accretion expense | 237 | — | |||||||
Balance, December 31 | $ | 4,973 | $ | 39 | |||||
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 14. 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. | |
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, 2014. 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. In addition, West Virginia has established a fund to satisfy any shortfall in reclamation obligations. 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. |
Major_Lessees
Major Lessees | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Risks and Uncertainties [Abstract] | |||||||||||||||||||||||||
Major Lessees | 15. Major Lessees | ||||||||||||||||||||||||
The Partnership has the following lessees that generated in excess of ten percent of total revenues in any one of the years ended December 31, 2014, 2013, and 2012. Revenues from these lessees are as follows: | |||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||
Revenues | Percent | Revenues | Percent | Revenues | Percent | ||||||||||||||||||||
(Dollars in thousands) | |||||||||||||||||||||||||
Foresight Energy and affiliates | $ | 81,546 | 20.4 | % | $ | 88,432 | 24.7 | % | $ | 92,341 | 24.4 | % | |||||||||||||
Alpha Natural Resources | $ | 48,783 | 12.2 | % | $ | 55,147 | 15.4 | % | $ | 81,077 | 21.4 | % | |||||||||||||
In 2014, the Partnership derived 32.6% of its revenue from the two companies listed above. As a result, the Partnership has a significant concentration of revenues with those lessees, although in most cases, with the exception of the Williamson mine operated by Foresight Energy, the exposure is spread over a number of different mining operations and leases. Foresight’s Williamson mine alone was responsible for approximately 10.2%, 13.0% and 12.4% of the Partnership’s total revenues for 2014, 2013 and 2012, respectively. | |||||||||||||||||||||||||
Approximately 50% of the Partnership’s accounts receivable result from amounts due from third-party companies in the coal industry, with approximately 30% of the Partnership’s total revenues being attributable to coal royalty revenues from Appalachia. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be collectively affected by the same changes in economic or other conditions. Receivables are generally not collateralized. |
Incentive_Plans
Incentive Plans | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||
Incentive Plans | 16. 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. | |||||
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. | |||||
A summary of activity in the outstanding grants for the year ended December 31, 2014 are as follows: | |||||
Outstanding grants at the beginning of the period | 1,012,984 | ||||
Grants during the period | 454,884 | ||||
Grants vested and paid during the period | (285,500 | ) | |||
Forfeitures during the period | (28,975 | ) | |||
Outstanding grants at the end of the period | 1,153,393 | ||||
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability fluctuates with the market value of the Partnership common units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and historical volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.26% to 1.06% and 33.40% to 43.43%, respectively at December 31, 2014. The Partnership’s cumulative average dividend rate of 7.46% was used in the calculation at December 31, 2014. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $1.0 million, $9.6 million and $2.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. In connection with the Long-Term Incentive Plans, cash payments of $6.5 million, $7.0 million and $6.6 million were paid during each of the years ended December 31, 2014, 2013, and 2012, respectively. The grant date fair value was $17.73, $25.27 and $33.38 per unit for awards in 2014, 2013 and 2012, respectively. | |||||
In connection with the phantom unit awards, the CNG committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting. | |||||
The unaccrued cost, associated with unvested outstanding grants and related DERs at December 31, 2014, was $5.2 million. |
Subsequent_Events_Unaudited
Subsequent Events (Unaudited) | 12 Months Ended |
Dec. 31, 2014 | |
Subsequent Events [Abstract] | |
Subsequent Events (Unaudited) | 17. Subsequent Events (Unaudited) |
The following represents material events that have occurred subsequent to December 31, 2014 through the time of the Partnership’s filing of its Annual Report on Form 10-K with the SEC: | |
Distributions | |
On January 20, 2015, the Partnership declared a distribution of $0.35 per unit that was paid on February 13, 2015 to unitholders of record on February 5, 2015. | |
Dividends and Distributions Received From Unconsolidated Equity and Other Investments | |
Subsequent to December 31, 2014, the Partnership received $10.9 million in cash distributions from OCI Wyoming. |
Supplemental_Financial_Data_Un
Supplemental Financial Data (Unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Supplemental Financial Data (Unaudited) | 18. Supplemental Financial Data (Unaudited) | ||||||||||||||||
Shown below are selected unaudited quarterly data. | |||||||||||||||||
Selected Quarterly Financial Information | |||||||||||||||||
(In thousands, except per unit data) | |||||||||||||||||
2014 | First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Total revenues and other income | $ | 80,309 | $ | 90,561 | $ | 91,609 | $ | 137,273 | |||||||||
Depreciation, depletion and amortization | $ | 14,647 | $ | 16,350 | $ | 18,621 | $ | 30,258 | |||||||||
Asset impairment | $ | — | $ | 5,624 | $ | — | $ | 20,585 | |||||||||
Income from operations | $ | 52,439 | $ | 50,403 | $ | 55,027 | $ | 31,050 | |||||||||
Net income | $ | 32,605 | $ | 31,407 | $ | 36,173 | $ | 8,645 | |||||||||
Net income per limited partner unit | $ | 0.29 | $ | 0.28 | $ | 0.32 | $ | 0.07 | |||||||||
Weighted average number of common units outstanding | 109,848 | 110,403 | 111,244 | 121,449 | |||||||||||||
2013 | First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Total revenues and other income | $ | 94,332 | $ | 86,804 | $ | 82,237 | $ | 94,744 | |||||||||
Depreciation, depletion and amortization | $ | 14,762 | $ | 17,411 | $ | 17,852 | $ | 14,352 | |||||||||
Income from operations | $ | 62,528 | $ | 55,332 | $ | 51,624 | $ | 66,752 | |||||||||
Asset impairment | $ | 291 | $ | 443 | $ | — | $ | — | |||||||||
Gain on Department of Highway condemnation | $ | — | $ | — | $ | — | $ | 10,370 | |||||||||
Net income | $ | 47,906 | $ | 41,065 | $ | 36,126 | $ | 46,981 | |||||||||
Net income per limited partner unit | $ | 0.43 | $ | 0.37 | $ | 0.32 | $ | 0.42 | |||||||||
Weighted average number of common units outstanding | 108,887 | 109,812 | 109,812 | 109,812 |
Supplemental_Oil_and_Gas_Data_
Supplemental Oil and Gas Data (Unaudited) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Extractive Industries [Abstract] | |||||||||||||||||||||
Supplemental Oil and Gas Data (Unaudited) | 19. Supplemental Oil and Gas Data (Unaudited) | ||||||||||||||||||||
The Partnership prepared the following oil and gas information in accordance with the authoritative guidance for oil and gas extractive activities. | |||||||||||||||||||||
Capitalized Costs: | |||||||||||||||||||||
For The Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Proven properties | $ | 361,554 | |||||||||||||||||||
Unproven properties | 46,400 | ||||||||||||||||||||
Intangible drilling costs | 25,217 | ||||||||||||||||||||
Wells and related equipment | 5,382 | ||||||||||||||||||||
Gathering assets | — | ||||||||||||||||||||
Well plugging | — | ||||||||||||||||||||
Total property, plant, and equipment | 438,553 | ||||||||||||||||||||
Accumulated depreciation, depletion, and amortization | (18,993 | ) | |||||||||||||||||||
Net capitalized costs | $ | 419,560 | |||||||||||||||||||
Costs incurred for property acquisition, exploration, and development: | |||||||||||||||||||||
For the | |||||||||||||||||||||
Year Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||
Property acquisitions | |||||||||||||||||||||
Proven properties | $ | 298,627 | |||||||||||||||||||
Unproven properties | 40,800 | ||||||||||||||||||||
Development | 5,340 | ||||||||||||||||||||
Exploration | — | ||||||||||||||||||||
Total | $ | 344,767 | |||||||||||||||||||
Results of Operations for Producing Activities: | |||||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||
Production revenue | $ | 48,834 | |||||||||||||||||||
Royalty and overriding royalty revenue(1) | 10,732 | ||||||||||||||||||||
Total oil and gas related revenue | 59,566 | ||||||||||||||||||||
Operating costs and expense: | |||||||||||||||||||||
Depreciation, depletion and amortization | 23,936 | ||||||||||||||||||||
General and administrative | 3,400 | ||||||||||||||||||||
Property, franchise and other taxes | 5,529 | ||||||||||||||||||||
Lease operating expenses | 9,144 | ||||||||||||||||||||
Total operating costs and expense | 42,009 | ||||||||||||||||||||
Total income from operations | $ | 17,557 | |||||||||||||||||||
-1 | Includes $1.9 million of nonproduction revenues including lease bonus payments. | ||||||||||||||||||||
Production and Price History | |||||||||||||||||||||
The following table sets forth summary information concerning the Partnership’s production results, average sales prices and production costs for the year ended December 31, 2014 for the Partnership’s Williston Basin properties. Production and price information for the years ended December 31, 2013 and 2012 is not included, as the Partnership’s oil and natural gas producing activities were not material to the Partnership’s results of operations for those years. | |||||||||||||||||||||
For The Year Ended December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
Williston | Royalty and | Total | |||||||||||||||||||
Basin(1) | Overriding | ||||||||||||||||||||
Royalty | |||||||||||||||||||||
Interests(2) | |||||||||||||||||||||
Net Production Volumes: | |||||||||||||||||||||
Crude oil (MBbl) | 578 | 33 | 611 | ||||||||||||||||||
NGLs (MBbl) | 53 | 18 | 71 | ||||||||||||||||||
Natural gas (MMcf) | 408 | 1,313 | 1,721 | ||||||||||||||||||
Average sales prices: | |||||||||||||||||||||
Crude oil ($/Bbl) | $ | 77.85 | $ | 82.91 | $ | 78.12 | |||||||||||||||
NGLs ($/Bbl) | $ | 33.64 | $ | 34.56 | $ | 33.87 | |||||||||||||||
Natural gas ($/Mcf) | $ | 5.04 | $ | 4.17 | $ | 4.37 | |||||||||||||||
Average costs ($/Boe): | |||||||||||||||||||||
Production expenses | $ | 13.08 | — | $ | 13.08 | ||||||||||||||||
Ad valorem and severance taxes | $ | 7.91 | — | $ | 7.91 | ||||||||||||||||
General and administrative expense | $ | 4.86 | — | $ | 4.86 | ||||||||||||||||
DD&A expense | $ | 25.73 | $ | 22.06 | $ | 24.7 | |||||||||||||||
-1 | Represents volume, price and cost information relating to the Partnership’s non-operated Williston Basin working interest properties. | ||||||||||||||||||||
-2 | Represents information relating to the Partnership’s royalty and overriding royalty interests in oil and gas properties. These interests are recorded net of costs. | ||||||||||||||||||||
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, 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. | |||||||||||||||||||||
The following tables set forth the Partnership’s estimated proved and related standardized measure of discounted cash flows by reserve category as of December 31, 2014. Netherland Sewell prepared its report covering properties representing 100% of the Partnership’s estimated proved reserves as of December 31, 2014. Prices were calculated using the unweighted average of the first-day-of-the-month pricing for the twelve months ended December 31, 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. | |||||||||||||||||||||
Estimated Proved Reserves as of December 31, 2014(1) | |||||||||||||||||||||
Crude | NGLs | Natural | Total | Standardized | |||||||||||||||||
Oil | (MBbl) | Gas | Proved | Measure of | |||||||||||||||||
(MBbl) | (MMcf) | Reserves | Discounted | ||||||||||||||||||
(MBoe)(2) | Cash Flows(3) | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Proved Developed Producing | 8,918 | 1,093 | 13,069 | 12,189 | $ | 286,179 | |||||||||||||||
Proved Developed Non-Producing | 12 | 5 | 92 | 32 | 655 | ||||||||||||||||
Proved Undeveloped | 1,053 | 131 | 1,209 | 1,386 | 18,363 | ||||||||||||||||
Total | 9,983 | 1,229 | 14,370 | 13,607 | (4) | $ | 305,197 | ||||||||||||||
-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 | Standardized measure of discounted cash flows represents the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. | ||||||||||||||||||||
-4 | Includes 12,144 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 10% of which were proved undeveloped reserves. | ||||||||||||||||||||
The following table represents the capitalized development well cost activity as indicated: | |||||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Costs pending the determination of proved reserves at December 31, 2014 | |||||||||||||||||||||
For a period one year or less | $ | 5,340 | |||||||||||||||||||
For a period greater than one year but less than five years | — | ||||||||||||||||||||
For a period greater than five years | — | ||||||||||||||||||||
Total | $ | 5,340 | |||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves | $ | 5,177 | |||||||||||||||||||
Costs expensed due to determination of dry hole or abandonment of project | — | ||||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows: | |||||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Future Cash Flows: | |||||||||||||||||||||
Revenues | $ | 920,454 | |||||||||||||||||||
Production costs | 312,666 | ||||||||||||||||||||
Development costs | 20,072 | ||||||||||||||||||||
Future Net Cash Flows | 587,716 | ||||||||||||||||||||
Discount to present value at a 10% annual rate | 282,519 | ||||||||||||||||||||
Total standardized measure of discounted net cash flows | $ | 305,197 | |||||||||||||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||||||||||
Reclassification | Reclassification | ||||||||||||||||||||||||||||
Certain reclassifications have been made to the Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s coal royalties, processing fees, transportation fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item “Coal related revenues” on this year’s Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s aggregates royalties, processing fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item “Aggregates related revenues” on this year’s Consolidated Statements of Comprehensive Income. Amounts relating to prior year’s oil and gas revenues and minimums recognized as revenue have been reclassified into a single line item “Oil and gas related revenues” on this year’s Consolidated Statements of Comprehensive Income. The following is reclassification reconciliation: | |||||||||||||||||||||||||||||
For The Year Ended | For The Year Ended | ||||||||||||||||||||||||||||
December 31, 2013 | December 31, 2012 | ||||||||||||||||||||||||||||
As | As | As | As | ||||||||||||||||||||||||||
Reported | Reclassified | Reported | Reclassified | ||||||||||||||||||||||||||
Total | Coal | Aggregates | Total | Coal | Aggregates | Oil & Gas | |||||||||||||||||||||||
Related | Related | Related | Related | Related | |||||||||||||||||||||||||
Revenues | Revenues | Revenues | Revenues | Revenues | |||||||||||||||||||||||||
Revenues: | |||||||||||||||||||||||||||||
Coal royalties | $ | 212,663 | $ | 212,663 | $ | — | $ | 260,734 | $ | 260,734 | $ | — | $ | — | |||||||||||||||
Equity and other unconsolidated investment income | 34,186 | — | — | — | — | — | — | ||||||||||||||||||||||
Aggregate royalties | 7,643 | — | 7,643 | 6,598 | — | 6,598 | — | ||||||||||||||||||||||
Processing fees | 5,049 | 4,542 | 507 | 8,299 | 7,841 | 458 | — | ||||||||||||||||||||||
Transportation fees | 17,977 | 17,977 | — | 19,513 | 19,513 | — | — | ||||||||||||||||||||||
Oil and gas royalties | 17,080 | — | — | 9,160 | — | — | 9,160 | ||||||||||||||||||||||
Property taxes | 15,416 | — | — | 15,273 | — | — | — | ||||||||||||||||||||||
Minimums recognized as revenue | 8,285 | 6,528 | 1,757 | 23,956 | 23,029 | 526 | 401 | ||||||||||||||||||||||
Override royalties | 13,499 | 10,372 | 3,127 | 15,527 | 13,979 | 1,548 | — | ||||||||||||||||||||||
Other | 26,319 | 22,112 | 445 | 20,087 | 18,256 | 394 | — | ||||||||||||||||||||||
Total revenues | $ | 358,117 | $ | 274,194 | $ | 13,479 | $ | 379,147 | $ | 343,352 | $ | 9,524 | $ | 9,561 | |||||||||||||||
Principles of Consolidation | Principles of Consolidation | ||||||||||||||||||||||||||||
The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC, a joint venture with International Paper Company controlled by the Partnership. Intercompany transactions and balances have been eliminated. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
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. 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 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 initially recorded using the FASB’s business combination and asset purchase authoritative guidance depending on circumstances. 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 minerals, 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. | |||||||||||||||||||||||||||||
Equity Investments | Equity Investments | ||||||||||||||||||||||||||||
The Partnership accounts for non-marketable investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if the Partnership has an ownership interest representing between 20% and 50% of the voting stock of the investee. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
The Partnership’s carrying value in an equity method investee company is reflected in the caption “Equity and other unconsolidated investments” in the Partnership’s Consolidated Balance Sheets. The Partnership’s adjusted share of the earnings or losses of the investee company is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity and other unconsolidated investment income.” These earnings are generated from natural resources, which are considered part of the Partnership’s 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. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
Asset Impairment | Asset Impairment | ||||||||||||||||||||||||||||
The Partnership has developed procedures to periodically evaluate its 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. 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, the Partnership intends to closely monitor its coal and oil and gas assets and the impairment evaluation process may be completed more frequently if deemed necessary by the Partnership. Future impairment analyses could result in downward adjustments to the carrying value of the Partnership’s assets. | |||||||||||||||||||||||||||||
The Partnership evaluates its 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. No impairment losses have been recognized for equity investments as of December 31, 2014. | |||||||||||||||||||||||||||||
In accordance with accounting and disclosure guidance for goodwill, the Partnership tests its 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 the reporting units, business, industry, or economic trends. | |||||||||||||||||||||||||||||
Share-Based Payment | Share-Based Payment | ||||||||||||||||||||||||||||
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 service or vesting 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. Incentive Plans.” | |||||||||||||||||||||||||||||
Deferred Revenue | Deferred Revenue | ||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
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 and environmental 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.” | |||||||||||||||||||||||||||||
Revenues | Revenues | ||||||||||||||||||||||||||||
Coal related revenues. Coal related revenue consist primarily of royalties as well as transportation and processing fees. Royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership 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 the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to the Partnership 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. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, the Partnership receives a fixed price per ton for all material transported on the beltlines. | |||||||||||||||||||||||||||||
Oil and Gas Revenues. Oil and gas related revenues consist of non-operated working interests, royalties and overriding royalties. Revenues related to the Partnership’s non-operated working interests in oil and gas assets are recognized based on the amount actually sold. The Partnership also has capital expenditure and operating expenditure obligations associated with the non-operated working interests. The Partnership’s 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 the 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. Some leases are subject to minimum annual payments or delay rentals. | |||||||||||||||||||||||||||||
Aggregates and Industrial Minerals Related Revenues. Aggregates and industrial minerals related revenues consist primarily of revenues generated by VantaCore’s construction aggregates business, royalties and overriding royalties. 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 at either market or contractual prices. Aggregates royalty and overriding royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. 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 the Partnership considers 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. | |||||||||||||||||||||||||||||
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 Property taxes revenue and in Property, franchise and other taxes expense, respectively, in the Consolidated Statements of Comprehensive Income. | |||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||
New Accounting Standards | New Accounting Standards | ||||||||||||||||||||||||||||
In May 2014, the FASB amended revenue recognition topics and created a new topic relating to revenue recognition that will supersede existing guidance under U.S. GAAP. The core principle of the new guidance is to recognize revenue when promised goods or services are transferred to the customer and in an amount that reflects the consideration expected in exchange for those goods or services. To achieve this core principle, an entity should (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when each performance obligation is satisfied. The guidance also specifies the accounting for some costs to obtain or fulfill a contract with a customer. Disclosure requirements include sufficient qualitative and quantitative information to enable financial statement users to understand the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. The new topic is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The guidance allows for either full adoption or a modified retrospective adoption. The Partnership is currently evaluating the requirements to determine the impact, if any, of this new topic on its financial position, results of operations and cash flows. | |||||||||||||||||||||||||||||
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows. | |||||||||||||||||||||||||||||
Transportation Revenue and Expense | Transportation Revenue and Expense | ||||||||||||||||||||||||||||
Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as Aggregate related revenues and Aggregates operating expenses in the Consolidated Statements of Comprehensive Income. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||||||||||
Summary of Reclassification Reconciliation | The following is reclassification reconciliation: | ||||||||||||||||||||||||||||
For The Year Ended | For The Year Ended | ||||||||||||||||||||||||||||
December 31, 2013 | December 31, 2012 | ||||||||||||||||||||||||||||
As | As | As | As | ||||||||||||||||||||||||||
Reported | Reclassified | Reported | Reclassified | ||||||||||||||||||||||||||
Total | Coal | Aggregates | Total | Coal | Aggregates | Oil & Gas | |||||||||||||||||||||||
Related | Related | Related | Related | Related | |||||||||||||||||||||||||
Revenues | Revenues | Revenues | Revenues | Revenues | |||||||||||||||||||||||||
Revenues: | |||||||||||||||||||||||||||||
Coal royalties | $ | 212,663 | $ | 212,663 | $ | — | $ | 260,734 | $ | 260,734 | $ | — | $ | — | |||||||||||||||
Equity and other unconsolidated investment income | 34,186 | — | — | — | — | — | — | ||||||||||||||||||||||
Aggregate royalties | 7,643 | — | 7,643 | 6,598 | — | 6,598 | — | ||||||||||||||||||||||
Processing fees | 5,049 | 4,542 | 507 | 8,299 | 7,841 | 458 | — | ||||||||||||||||||||||
Transportation fees | 17,977 | 17,977 | — | 19,513 | 19,513 | — | — | ||||||||||||||||||||||
Oil and gas royalties | 17,080 | — | — | 9,160 | — | — | 9,160 | ||||||||||||||||||||||
Property taxes | 15,416 | — | — | 15,273 | — | — | — | ||||||||||||||||||||||
Minimums recognized as revenue | 8,285 | 6,528 | 1,757 | 23,956 | 23,029 | 526 | 401 | ||||||||||||||||||||||
Override royalties | 13,499 | 10,372 | 3,127 | 15,527 | 13,979 | 1,548 | — | ||||||||||||||||||||||
Other | 26,319 | 22,112 | 445 | 20,087 | 18,256 | 394 | — | ||||||||||||||||||||||
Total revenues | $ | 358,117 | $ | 274,194 | $ | 13,479 | $ | 379,147 | $ | 343,352 | $ | 9,524 | $ | 9,561 | |||||||||||||||
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 |
Significant_Acquisitions_Table
Significant Acquisitions (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Business Acquisition Pro Forma Financial Information | The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. | ||||||||
For the Years ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Revenue and other income except aggregate and oil and gas related revenues | $ | 286,062 | $ | 327,558 | |||||
Aggregates related revenues | 137,220 | 152,032 | |||||||
Oil and gas related revenues | 110,235 | 100,343 | |||||||
Total revenue | $ | 533,517 | $ | 579,933 | |||||
Net income | $ | 122,319 | $ | 197,164 | |||||
Basic and diluted net income per limited partner unit | $ | 0.99 | $ | 1.6 | |||||
VantaCore Partners LP [Member] | |||||||||
Schedule of Adjustments to the Estimated Fair Value | Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition. | ||||||||
Preliminary Purchase Price Allocation—VantaCore Partners LLC Acquisition | |||||||||
October 1, 2014 | |||||||||
(In thousands) | |||||||||
Consideration | |||||||||
Cash | $ | 168,978 | |||||||
NRP common units(1) | 31,604 | ||||||||
Total consideration given | $ | 200,582 | |||||||
Preliminary Allocation of Purchase Price | |||||||||
Current assets | $ | 37,222 | |||||||
Land, property and equipment | 40,411 | ||||||||
Mineral rights | 87,907 | ||||||||
Other assets | 3,268 | ||||||||
Current liabilities | (16,953 | ) | |||||||
Asset retirement obligation | (3,285 | ) | |||||||
Goodwill | 52,012 | ||||||||
Fair value of net assets acquired | $ | 200,582 | |||||||
-1 | Includes 2,426,690 units issued on October 1, 2014 at $13.02, closing price on that day and 813 units issued for a post-closing adjustment on December 4, 2014 at $10.48. | ||||||||
Sanish Field [Member] | |||||||||
Schedule of Adjustments to the Estimated Fair Value | Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition. | ||||||||
Preliminary Purchase Price Allocation—Sanish Field Acquisition | |||||||||
November 12, 2014 | |||||||||
(In thousands) | |||||||||
Mineral rights | |||||||||
Proven oil and gas properties | $ | 298,627 | |||||||
Probable and possible resources | 40,800 | ||||||||
Total fair value of oil and gas properties acquired | 339,427 | ||||||||
Asset retirement obligation | (427 | ) | |||||||
Fair value of net assets acquired | $ | 339,000 | |||||||
Equity_and_Other_Investments_T
Equity and Other Investments (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||
Summary of Difference Between Carrying Amount and Underlying Equity | The table below summarizes the differences between the carrying amount of the Partnership’s investment and the amount of the Partnership’s underlying equity in the net assets of OCI Wyoming. For both the twelve month periods ended December 31, 2014 and 2013, the Partnership derived approximately 10% of its revenues and other income from its equity investment in OCI Wyoming. | ||||||||
For the Year Ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Net book value of NRP’s equity interests | $ | 101,311 | $ | 96,692 | |||||
Equity and other unconsolidated investments | $ | 264,020 | $ | 269,338 | |||||
Excess of NRP’s investment over net book value of NRP’s equity interest | $ | 162,709 | $ | 172,646 | |||||
Income allocation to NRP’s equity interests | $ | 47,354 | $ | 37,036 | |||||
Amortization of basis difference | $ | (5,938 | ) | $ | (2850 | ) | |||
Equity and other unconsolidated investment income | $ | 41,416 | $ | 34,186 | |||||
Schedule of Summarized Results of Operations | The following summarized financial information was taken from the OCI Wyoming-prepared financial statements. | ||||||||
For the Year Ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Sales | $ | 465,032 | $ | 442,132 | |||||
Gross profit | $ | 118,439 | $ | 94,299 | |||||
Net Income | $ | 96,640 | $ | 79,655 | |||||
Current assets | $ | 200,622 | $ | 201,265 | |||||
Noncurrent assets | $ | 202,282 | $ | 194,508 | |||||
Current liabilities | $ | 47,704 | $ | 39,663 | |||||
Noncurrent liabilities | $ | 149,192 | $ | 158,779 |
Allowance_for_Doubtful_Account1
Allowance for Doubtful Accounts (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Text Block [Abstract] | |||||||||||||
Allowance for Doubtful Accounts | Activity in the allowance for doubtful accounts for the years ended December 31, 2014, 2013 and 2012 was as follows: | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Balance, January 1 | $ | 275 | $ | 711 | $ | 393 | |||||||
Provision charged to operations: | |||||||||||||
Additions to the reserve | 774 | 278 | 318 | ||||||||||
Collections of previously reserved accounts | (373 | ) | — | — | |||||||||
Total charged (credited) to operations | 401 | 278 | 318 | ||||||||||
Non-recoverable balances written off | — | (714 | ) | — | |||||||||
Balance, December 31 | $ | 676 | $ | 275 | $ | 711 | |||||||
Inventory_Tables
Inventory (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Inventory Disclosure [Abstract] | |||||
Components of Inventories | The components of inventories at December 31, 2014 are as follows: | ||||
2014 | |||||
(In thousands) | |||||
Aggregates | $ | 4,596 | |||
Supplies and parts | 1,218 | ||||
$ | 5,814 | ||||
Plant_and_Equipment_Tables
Plant and Equipment (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||
Plant and Equipment | The Partnership’s plant and equipment consist of the following: | ||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
(In thousands) | |||||||||||||
Construction in process | $ | 457 | $ | — | |||||||||
Plant and equipment at cost | 89,759 | 55,271 | |||||||||||
Less accumulated depreciation | (30,123 | ) | (28,836 | ) | |||||||||
Net book value | $ | 60,093 | $ | 26,435 | |||||||||
For the Years ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Total depreciation expense on plant and equipment | $ | 7,631 | $ | 5,966 | $ | 6,825 | |||||||
Mineral_Rights_Tables
Mineral Rights (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Extractive Industries [Abstract] | |||||||||||||
Mineral Rights | The Partnership’s mineral rights consist of the following: | ||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
(In thousands) | |||||||||||||
Coal | $ | 1,541,572 | $ | 1,574,914 | |||||||||
Oil and gas | 560,395 | 204,906 | |||||||||||
Aggregates | 211,490 | 100,080 | |||||||||||
Other | 15,014 | 15,020 | |||||||||||
Less accumulated depletion and amortization | (546,619 | ) | (489,465 | ) | |||||||||
Net book value | $ | 1,781,852 | $ | 1,405,455 | |||||||||
For the years ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Total depletion and amortization expense on mineral interests | $ | 68,603 | $ | 54,595 | $ | 47,042 | |||||||
Intangible_Assets_Tables
Intangible Assets (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||
Intangible Assets | Amounts recorded as intangible assets along with the balances and accumulated amortization at December 31, 2014 and 2013 are reflected in the table below: | ||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
(In thousands) | |||||||||||||
Contract intangibles | $ | 82,972 | $ | 89,421 | |||||||||
Other intangibles | 3,004 | — | |||||||||||
Less accumulated amortization | (25,243 | ) | (22,471 | ) | |||||||||
Net book value | $ | 60,733 | $ | 66,950 | |||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Total amortization expense on intangible assets | $ | 3,642 | $ | 3,816 | $ | 4,354 | |||||||
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. | ||||||||||||
Estimated amortization expense (In thousands) | |||||||||||||
For year ended December 31, 2015 | $ | 3,486 | |||||||||||
For year ended December 31, 2016 | 3,743 | ||||||||||||
For year ended December 31, 2017 | 3,326 | ||||||||||||
For year ended December 31, 2018 | 3,126 | ||||||||||||
For year ended December 31, 2019 | 3,053 |
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||
Long-Term Debt | Long-term debt consists of the following: | ||||||||||||||||||||||||
December 31, | December 31, | ||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||
NRP LP Debt: | |||||||||||||||||||||||||
$425 million 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% | $ | 422,167 | $ | 297,170 | |||||||||||||||||||||
Opco Debt: | |||||||||||||||||||||||||
$300 million floating rate revolving credit facility, due August 2016 | 200,000 | 20,000 | |||||||||||||||||||||||
$200 million floating rate term loan, due January 2016 | 75,000 | 99,000 | |||||||||||||||||||||||
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018 | 18,467 | 23,084 | |||||||||||||||||||||||
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019 | 107,143 | 128,571 | |||||||||||||||||||||||
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020 | 46,154 | 53,846 | |||||||||||||||||||||||
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 | 1,345 | 1,538 | |||||||||||||||||||||||
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023 | 24,300 | 27,000 | |||||||||||||||||||||||
4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2023 | 67,500 | 75,000 | |||||||||||||||||||||||
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024 | 150,000 | 165,000 | |||||||||||||||||||||||
8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 | 45,455 | 50,000 | |||||||||||||||||||||||
5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 | 161,538 | 175,000 | |||||||||||||||||||||||
5.18% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 | 46,154 | 50,000 | |||||||||||||||||||||||
NRP Oil and Gas Debt: | |||||||||||||||||||||||||
Reserve-based revolving credit facility due 2019 | 110,000 | — | |||||||||||||||||||||||
Total debt | 1,475,223 | 1,165,209 | |||||||||||||||||||||||
Less—current portion of long term debt | (80,983 | ) | (80,983 | ) | |||||||||||||||||||||
Long-term debt | $ | 1,394,240 | $ | 1,084,226 | |||||||||||||||||||||
Principal Payments Due | The consolidated principal payments due are set forth below: | ||||||||||||||||||||||||
NRP LP | Opco | NRP | |||||||||||||||||||||||
Oil and Gas | |||||||||||||||||||||||||
Senior Notes | Senior Notes | Credit Facility | Term Loan | Credit Facility | Total | ||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||
2015 | $ | — | $ | 80,983 | $ | — | $ | — | $ | — | $ | 80,983 | |||||||||||||
2016 | — | 80,983 | 200,000 | 75,000 | — | 355,983 | |||||||||||||||||||
2017 | — | 80,983 | — | — | — | 80,983 | |||||||||||||||||||
2018 | 425,000 | (1) | 80,983 | — | — | — | 505,983 | ||||||||||||||||||
2019 | — | 76,366 | — | — | 110,000 | 186,366 | |||||||||||||||||||
Thereafter | — | 267,758 | — | — | — | 267,758 | |||||||||||||||||||
$ | 425,000 | $ | 668,056 | $ | 200,000 | $ | 75,000 | $ | 110,000 | $ | 1,478,056 | ||||||||||||||
-1 | The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2014 were carried at $422.2 million. |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Contractual Override, Note Receivable and Long-Term Debt | The fair market value and carrying value of the contractual override and long-term senior notes are as follows: | ||||||||||||||||
Fair Value As Of | Carrying Value As Of | ||||||||||||||||
December 31, | December 31, | December 31, | December 31, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
(In thousands) | |||||||||||||||||
Assets | |||||||||||||||||
Sugar Camp override, current and long-term | $ | 5,162 | $ | 6,852 | $ | 4,870 | $ | 6,063 | |||||||||
Liabilities | |||||||||||||||||
Long-term debt, current and long-term | $ | 1,096,520 | $ | 1,071,880 | $ | 1,090,223 | $ | 1,046,209 |
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Summary of Reimbursements | The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as follows: | ||||||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Reimbursement for services | $ | 11,798 | $ | 11,480 | $ | 9,791 | |||||||
Cline Affiliates [Member] | |||||||||||||
Summary of Revenues from Related Party | Revenues from the Cline affiliates are as follows: | ||||||||||||
For The Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Coal royalty revenues | $ | 52,415 | $ | 54,322 | $ | 48,567 | |||||||
Processing and transportation fees | 20,594 | 19,258 | 21,923 | ||||||||||
Minimums recognized as revenue | — | 3,477 | 17,785 | ||||||||||
Override revenue | 2,847 | 3,226 | 4,066 | ||||||||||
Other revenue | 5,690 | 8,149 | — | ||||||||||
$ | 81,546 | $ | 88,432 | $ | 92,341 | ||||||||
Forge Group [Member] | |||||||||||||
Summary of Revenues from Related Party | For the years ended December 31, 2014, 2013 and 2012, the revenues from Taggart prior to the sale to Forge were as follows: | ||||||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Processing revenue | $ | — | $ | 1,761 | $ | 5,580 | |||||||
Corsa [Member] | |||||||||||||
Summary of Revenues from Related Party | Revenues from Corsa are as follows: | ||||||||||||
For the Years Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
(In thousands) | |||||||||||||
Coal royalty revenues | $ | 3,013 | $ | 4,594 | $ | 3,486 | |||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
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 of the beginning and ending carrying amounts of the Partnership’s asset retirement obligations. | ||||||||
For the Years Ended | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(In thousands) | |||||||||
Balance, January 1 | $ | 39 | $ | 39 | |||||
Liabilities incurred in current period | 4,697 | — | |||||||
Accretion expense | 237 | — | |||||||
Balance, December 31 | $ | 4,973 | $ | 39 | |||||
Major_Lessees_Tables
Major Lessees (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Risks and Uncertainties [Abstract] | |||||||||||||||||||||||||
Revenues from Lessees that Exceeded Ten Percent of Total Revenues and Other Income | The Partnership has the following lessees that generated in excess of ten percent of total revenues in any one of the years ended December 31, 2014, 2013, and 2012. Revenues from these lessees are as follows: | ||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||
Revenues | Percent | Revenues | Percent | Revenues | Percent | ||||||||||||||||||||
(Dollars in thousands) | |||||||||||||||||||||||||
Foresight Energy and affiliates | $ | 81,546 | 20.4 | % | $ | 88,432 | 24.7 | % | $ | 92,341 | 24.4 | % | |||||||||||||
Alpha Natural Resources | $ | 48,783 | 12.2 | % | $ | 55,147 | 15.4 | % | $ | 81,077 | 21.4 | % |
Incentive_Plans_Tables
Incentive Plans (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||
Summary of Activity in Outstanding Grants | A summary of activity in the outstanding grants for the year ended December 31, 2014 are as follows: | ||||
Outstanding grants at the beginning of the period | 1,012,984 | ||||
Grants during the period | 454,884 | ||||
Grants vested and paid during the period | (285,500 | ) | |||
Forfeitures during the period | (28,975 | ) | |||
Outstanding grants at the end of the period | 1,153,393 | ||||
Supplemental_Financial_Data_Un1
Supplemental Financial Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Selected Quarterly Financial Information | Shown below are selected unaudited quarterly data. | ||||||||||||||||
Selected Quarterly Financial Information | |||||||||||||||||
(In thousands, except per unit data) | |||||||||||||||||
2014 | First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Total revenues and other income | $ | 80,309 | $ | 90,561 | $ | 91,609 | $ | 137,273 | |||||||||
Depreciation, depletion and amortization | $ | 14,647 | $ | 16,350 | $ | 18,621 | $ | 30,258 | |||||||||
Asset impairment | $ | — | $ | 5,624 | $ | — | $ | 20,585 | |||||||||
Income from operations | $ | 52,439 | $ | 50,403 | $ | 55,027 | $ | 31,050 | |||||||||
Net income | $ | 32,605 | $ | 31,407 | $ | 36,173 | $ | 8,645 | |||||||||
Net income per limited partner unit | $ | 0.29 | $ | 0.28 | $ | 0.32 | $ | 0.07 | |||||||||
Weighted average number of common units outstanding | 109,848 | 110,403 | 111,244 | 121,449 | |||||||||||||
2013 | First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Total revenues and other income | $ | 94,332 | $ | 86,804 | $ | 82,237 | $ | 94,744 | |||||||||
Depreciation, depletion and amortization | $ | 14,762 | $ | 17,411 | $ | 17,852 | $ | 14,352 | |||||||||
Income from operations | $ | 62,528 | $ | 55,332 | $ | 51,624 | $ | 66,752 | |||||||||
Asset impairment | $ | 291 | $ | 443 | $ | — | $ | — | |||||||||
Gain on Department of Highway condemnation | $ | — | $ | — | $ | — | $ | 10,370 | |||||||||
Net income | $ | 47,906 | $ | 41,065 | $ | 36,126 | $ | 46,981 | |||||||||
Net income per limited partner unit | $ | 0.43 | $ | 0.37 | $ | 0.32 | $ | 0.42 | |||||||||
Weighted average number of common units outstanding | 108,887 | 109,812 | 109,812 | 109,812 |
Supplemental_Oil_and_Gas_Data_1
Supplemental Oil and Gas Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Extractive Industries [Abstract] | |||||||||||||||||||||
Summary of Capitalized Costs | Capitalized Costs: | ||||||||||||||||||||
For The Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Proven properties | $ | 361,554 | |||||||||||||||||||
Unproven properties | 46,400 | ||||||||||||||||||||
Intangible drilling costs | 25,217 | ||||||||||||||||||||
Wells and related equipment | 5,382 | ||||||||||||||||||||
Gathering assets | — | ||||||||||||||||||||
Well plugging | — | ||||||||||||||||||||
Total property, plant, and equipment | 438,553 | ||||||||||||||||||||
Accumulated depreciation, depletion, and amortization | (18,993 | ) | |||||||||||||||||||
Net capitalized costs | $ | 419,560 | |||||||||||||||||||
Costs Incurred for Property Acquisition Exploration and Development | Costs incurred for property acquisition, exploration, and development: | ||||||||||||||||||||
For the | |||||||||||||||||||||
Year Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||
Property acquisitions | |||||||||||||||||||||
Proven properties | $ | 298,627 | |||||||||||||||||||
Unproven properties | 40,800 | ||||||||||||||||||||
Development | 5,340 | ||||||||||||||||||||
Exploration | — | ||||||||||||||||||||
Total | $ | 344,767 | |||||||||||||||||||
Results of Operations for Producing Activities | Results of Operations for Producing Activities: | ||||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In thousands) | |||||||||||||||||||||
Production revenue | $ | 48,834 | |||||||||||||||||||
Royalty and overriding royalty revenue(1) | 10,732 | ||||||||||||||||||||
Total oil and gas related revenue | 59,566 | ||||||||||||||||||||
Operating costs and expense: | |||||||||||||||||||||
Depreciation, depletion and amortization | 23,936 | ||||||||||||||||||||
General and administrative | 3,400 | ||||||||||||||||||||
Property, franchise and other taxes | 5,529 | ||||||||||||||||||||
Lease operating expenses | 9,144 | ||||||||||||||||||||
Total operating costs and expense | 42,009 | ||||||||||||||||||||
Total income from operations | $ | 17,557 | |||||||||||||||||||
-1 | Includes $1.9 million of nonproduction revenues including lease bonus payments. | ||||||||||||||||||||
Summary of Information Concerning Production Results, Average Sales Prices and Production Costs | The following table sets forth summary information concerning the Partnership’s production results, average sales prices and production costs for the year ended December 31, 2014 for the Partnership’s Williston Basin properties. Production and price information for the years ended December 31, 2013 and 2012 is not included, as the Partnership’s oil and natural gas producing activities were not material to the Partnership’s results of operations for those years. | ||||||||||||||||||||
For The Year Ended December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
Williston | Royalty and | Total | |||||||||||||||||||
Basin(1) | Overriding | ||||||||||||||||||||
Royalty | |||||||||||||||||||||
Interests(2) | |||||||||||||||||||||
Net Production Volumes: | |||||||||||||||||||||
Crude oil (MBbl) | 578 | 33 | 611 | ||||||||||||||||||
NGLs (MBbl) | 53 | 18 | 71 | ||||||||||||||||||
Natural gas (MMcf) | 408 | 1,313 | 1,721 | ||||||||||||||||||
Average sales prices: | |||||||||||||||||||||
Crude oil ($/Bbl) | $ | 77.85 | $ | 82.91 | $ | 78.12 | |||||||||||||||
NGLs ($/Bbl) | $ | 33.64 | $ | 34.56 | $ | 33.87 | |||||||||||||||
Natural gas ($/Mcf) | $ | 5.04 | $ | 4.17 | $ | 4.37 | |||||||||||||||
Average costs ($/Boe): | |||||||||||||||||||||
Production expenses | $ | 13.08 | — | $ | 13.08 | ||||||||||||||||
Ad valorem and severance taxes | $ | 7.91 | — | $ | 7.91 | ||||||||||||||||
General and administrative expense | $ | 4.86 | — | $ | 4.86 | ||||||||||||||||
DD&A expense | $ | 25.73 | $ | 22.06 | $ | 24.7 | |||||||||||||||
-1 | Represents volume, price and cost information relating to the Partnership’s non-operated Williston Basin working interest properties. | ||||||||||||||||||||
-2 | Represents information relating to the Partnership’s royalty and overriding royalty interests in oil and gas properties. These interests are recorded net of costs. | ||||||||||||||||||||
Summary of Estimated Proved Reserves and Related Standardized Measure of Discounted Cash Flows by Reserve Category | The following tables set forth the Partnership’s estimated proved and related standardized measure of discounted cash flows by reserve category as of December 31, 2014. Netherland Sewell prepared its report covering properties representing 100% of the Partnership’s estimated proved reserves as of December 31, 2014. Prices were calculated using the unweighted average of the first-day-of-the-month pricing for the twelve months ended December 31, 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. | ||||||||||||||||||||
Estimated Proved Reserves as of December 31, 2014(1) | |||||||||||||||||||||
Crude | NGLs | Natural | Total | Standardized | |||||||||||||||||
Oil | (MBbl) | Gas | Proved | Measure of | |||||||||||||||||
(MBbl) | (MMcf) | Reserves | Discounted | ||||||||||||||||||
(MBoe)(2) | Cash Flows(3) | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Proved Developed Producing | 8,918 | 1,093 | 13,069 | 12,189 | $ | 286,179 | |||||||||||||||
Proved Developed Non-Producing | 12 | 5 | 92 | 32 | 655 | ||||||||||||||||
Proved Undeveloped | 1,053 | 131 | 1,209 | 1,386 | 18,363 | ||||||||||||||||
Total | 9,983 | 1,229 | 14,370 | 13,607 | (4) | $ | 305,197 | ||||||||||||||
-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 | Standardized measure of discounted cash flows represents the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. | ||||||||||||||||||||
-4 | Includes 12,144 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 10% of which were proved undeveloped reserves. | ||||||||||||||||||||
Schedule of Capitalized Exploratory Well Cost Activity | The following table represents the capitalized development well cost activity as indicated: | ||||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Costs pending the determination of proved reserves at December 31, 2014 | |||||||||||||||||||||
For a period one year or less | $ | 5,340 | |||||||||||||||||||
For a period greater than one year but less than five years | — | ||||||||||||||||||||
For a period greater than five years | — | ||||||||||||||||||||
Total | $ | 5,340 | |||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves | $ | 5,177 | |||||||||||||||||||
Costs expensed due to determination of dry hole or abandonment of project | — | ||||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | Standardized Measure of Discounted Future Net Cash Flows: | ||||||||||||||||||||
For the Year | |||||||||||||||||||||
Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | |||||||||||||||||||||
(In Thousands) | |||||||||||||||||||||
Future Cash Flows: | |||||||||||||||||||||
Revenues | $ | 920,454 | |||||||||||||||||||
Production costs | 312,666 | ||||||||||||||||||||
Development costs | 20,072 | ||||||||||||||||||||
Future Net Cash Flows | 587,716 | ||||||||||||||||||||
Discount to present value at a 10% annual rate | 282,519 | ||||||||||||||||||||
Total standardized measure of discounted net cash flows | $ | 305,197 | |||||||||||||||||||
Basis_of_Presentation_and_Orga1
Basis of Presentation and Organization - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2014 | Oct. 01, 2014 | |
Coal_Reserves | Plant | |
Quarry | ||
Terminal | ||
Collaborative Arrangements Non collaborative Arrangements And Business Acquisitions Transactions [Line Items] | ||
Number of coal producing regions | 3 | |
OCI Wyoming [Member] | ||
Collaborative Arrangements Non collaborative Arrangements And Business Acquisitions Transactions [Line Items] | ||
Percentage of partnership interest owned | 49.00% | |
VantaCore Partners LP [Member] | ||
Collaborative Arrangements Non collaborative Arrangements And Business Acquisitions Transactions [Line Items] | ||
Number of hard rock quarries | 3 | 3 |
Number of sand and gravel plants | 5 | 5 |
Number of asphalt plants | 2 | 2 |
Number of marine terminal | 1 | 1 |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Summary of Reclassification Reconciliation (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||||||||||
Equity and other unconsolidated investment income | $41,416 | $34,186 | |||||||||
Aggregate royalties | 1,900 | ||||||||||
Oil and gas royalties | 59,566 | 17,080 | 9,561 | ||||||||
Property taxes | 13,609 | 15,416 | 15,273 | ||||||||
Other | 4,313 | 3,762 | 1,437 | ||||||||
Total revenues and other income | 137,273 | 91,609 | 90,561 | 80,309 | 94,744 | 82,237 | 86,804 | 94,332 | 399,752 | 358,117 | 379,147 |
Scenario, Previously Reported [Member] | |||||||||||
Revenues: | |||||||||||
Coal royalties | 212,663 | 260,734 | |||||||||
Equity and other unconsolidated investment income | 34,186 | ||||||||||
Aggregate royalties | 7,643 | 6,598 | |||||||||
Processing fees | 5,049 | 8,299 | |||||||||
Transportation fees | 17,977 | 19,513 | |||||||||
Oil and gas royalties | 17,080 | 9,160 | |||||||||
Property taxes | 15,416 | 15,273 | |||||||||
Minimums recognized as revenue | 8,285 | 23,956 | |||||||||
Override royalties | 13,499 | 15,527 | |||||||||
Other | 26,319 | 20,087 | |||||||||
Total revenues and other income | 358,117 | 379,147 | |||||||||
Reclassified as Coal Related Revenue [Member] | |||||||||||
Revenues: | |||||||||||
Coal royalties | 212,663 | 260,734 | |||||||||
Processing fees | 4,542 | 7,841 | |||||||||
Transportation fees | 17,977 | 19,513 | |||||||||
Minimums recognized as revenue | 6,528 | 23,029 | |||||||||
Override royalties | 10,372 | 13,979 | |||||||||
Other | 22,112 | 18,256 | |||||||||
Total revenues and other income | 274,194 | 343,352 | |||||||||
Reclassified as Aggregate Related Revenue [Member] | |||||||||||
Revenues: | |||||||||||
Aggregate royalties | 7,643 | 6,598 | |||||||||
Processing fees | 507 | 458 | |||||||||
Minimums recognized as revenue | 1,757 | 526 | |||||||||
Override royalties | 3,127 | 1,548 | |||||||||
Other | 445 | 394 | |||||||||
Total revenues and other income | 13,479 | 9,524 | |||||||||
Reclassified as Oil And Gas Related Revenues [Member] | |||||||||||
Revenues: | |||||||||||
Oil and gas royalties | 9,160 | ||||||||||
Minimums recognized as revenue | 401 | ||||||||||
Total revenues and other income | $9,561 |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Schedule Of Significant Accounting Policies [Line Items] | |
Maturity of cash and cash equivalents | 3 months |
Oil and gas royalty interests useful life | 30 years |
Minimum [Member] | |
Schedule Of Significant Accounting Policies [Line Items] | |
Ownership interest of Partnership with significant influence | 20.00% |
Maximum [Member] | |
Schedule Of Significant Accounting Policies [Line Items] | |
Ownership interest of Partnership with significant influence | 50.00% |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Summary of Plant and Equipment Useful Lives (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
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 |
Significant_Acquisitions_Addit
Significant Acquisitions - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 0 Months Ended | ||||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 30, 2014 | Oct. 01, 2014 | Aug. 30, 2014 | |
acre | ||||||||||||||
Wells | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Operating expenses of acquired entity | $210,833,000 | $121,881,000 | $111,982,000 | |||||||||||
Depreciation and depletion of acquired entity | 30,258,000 | 18,621,000 | 16,350,000 | 14,647,000 | 14,352,000 | 17,852,000 | 17,411,000 | 14,762,000 | 79,876,000 | 64,377,000 | 58,221,000 | |||
Net assets acquired | 339,400,000 | 339,400,000 | ||||||||||||
Lease operating expenses | 9,144,000 | 739,000 | ||||||||||||
Abraxas Petroleum [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Purchase price allocation for assets acquired | 38,000,000 | |||||||||||||
Sundance Energy Inc [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Purchase price allocation for assets acquired | 29,400,000 | 29,400,000 | ||||||||||||
Abraxas and Sundance [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Combined revenues | 36,100,000 | 5,400,000 | ||||||||||||
Capital expenditure | 22,900,000 | |||||||||||||
Lease operating expenses | 12,300,000 | 2,900,000 | ||||||||||||
Sanish Field [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Aggregate acquisition cost | 339,000,000 | |||||||||||||
Transaction costs of acquisition | 1,800,000 | 1,800,000 | ||||||||||||
Revenue from acquired entity | 12,800,000 | |||||||||||||
Operating expenses of acquired entity | 9,100,000 | |||||||||||||
Depreciation and depletion of acquired entity | 6,700,000 | |||||||||||||
Percentage of member interest Acquired | 40.00% | |||||||||||||
Percentage of assets acquired | 40.00% | |||||||||||||
Land acquired | 6,086 | |||||||||||||
Estimated average working interest, Percentage | 14.50% | |||||||||||||
Number of Oil & Gas wells | 192 | |||||||||||||
VantaCore Partners LP [Member] | ||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||
Aggregate acquisition cost | 200,582,000 | |||||||||||||
Number of hard rock quarries | 3 | 3 | 3 | |||||||||||
Number of sand and gravel plants | 5 | 5 | 5 | |||||||||||
Number of asphalt plants | 2 | 2 | 2 | |||||||||||
Number of marine terminal | 1 | 1 | 1 | |||||||||||
Transaction costs of acquisition | 2,900,000 | 2,900,000 | ||||||||||||
Revenue from acquired entity | 42,100,000 | |||||||||||||
Operating expenses of acquired entity | 32,300,000 | |||||||||||||
Depreciation and depletion of acquired entity | 3,200,000 | |||||||||||||
Purchase price allocation for assets acquired | $40,411,000 |
Significant_Acquisitions_Sched
Significant Acquisitions - Schedule of Adjustments to the Estimated Fair Value (Detail) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Oct. 01, 2014 | Nov. 12, 2014 | Nov. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Mineral rights | ||||||
Proven oil and gas properties | $298,627 | |||||
Probable and possible resources | 40,800 | |||||
Asset retirement obligation | -4,973 | -39 | -39 | |||
Preliminary Allocation of Purchase Price | ||||||
Goodwill | 52,012 | |||||
VantaCore Partners LP [Member] | ||||||
Mineral rights | ||||||
Fair value of net assets acquired | 200,582 | |||||
Consideration | ||||||
Cash | 168,978 | |||||
NRP common units | 31,604 | |||||
Total consideration given | 200,582 | |||||
Preliminary Allocation of Purchase Price | ||||||
Current assets | 37,222 | |||||
Land, property and equipment | 40,411 | |||||
Mineral rights | 87,907 | |||||
Other assets | 3,268 | |||||
Current liabilities | -16,953 | |||||
Asset retirement obligation | -3,285 | |||||
Goodwill | 52,012 | |||||
Fair value of net assets acquired | 200,582 | |||||
Sanish Field [Member] | ||||||
Mineral rights | ||||||
Proven oil and gas properties | 298,627 | |||||
Probable and possible resources | 40,800 | |||||
Total fair value of oil and gas properties acquired | 339,427 | |||||
Asset retirement obligation | -427 | |||||
Fair value of net assets acquired | 339,000 | |||||
Consideration | ||||||
Total consideration given | 339,000 | |||||
Preliminary Allocation of Purchase Price | ||||||
Fair value of net assets acquired | $339,000 |
Significant_Acquisitions_Sched1
Significant Acquisitions - Schedule of Adjustments to the Estimated Fair Value (Parenthetical) (Detail) (VantaCore Partners LP [Member], USD $) | Oct. 01, 2014 | Dec. 04, 2014 |
Business Acquisition [Line Items] | ||
Common units issued | 2,426,690 | |
Common units issued at price per share | $13.02 | |
Post Closing Adjustments [Member] | ||
Business Acquisition [Line Items] | ||
Common units issued | 813 | |
Common units issued at price per share | $10.48 |
Significant_Acquisitions_Busin
Significant Acquisitions - Business Acquisition Pro Forma Financial Information (Detail) (USD $) | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Business Combinations [Abstract] | ||
Revenue and other income except aggregate and oil and gas related revenues | $286,062 | $327,558 |
Aggregates related revenues | 137,220 | 152,032 |
Oil and gas related revenues | 110,235 | 100,343 |
Total revenue | 533,517 | 579,933 |
Net income | $122,319 | $197,164 |
Basic and diluted net income per limited partner unit | $0.99 | $1.60 |
Equity_and_Other_Investments_A
Equity and Other Investments - Additional Information (Detail) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Equity Method Investments [Line Items] | ||
Accounts payable and accrued liabilities, current portion | $32,416,000 | $8,659,000 |
Increase in fair value of property, plant and equipment | 65,400,000 | |
Weighted average useful life of assets | 28 years | |
Assigned right to mine asset | 132,700,000 | |
Revenue and other income from equity investments | 10.00% | 10.00% |
Big Island Trona [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Acquisition value | 292,500,000 | |
Contingent consideration accrued | 14,500,000 | |
Accounts payable and accrued liabilities, current portion | 3,800,000 | |
Other non-current liabilities, long term portion | 10,700,000 | |
Contingent consideration paid | 500,000 | |
Big Island Trona [Member] | Maximum [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Acquisition Agreement | $50,000,000 | |
OCI Wyoming [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Percentage of partnership interest owned | 49.00% |
Equity_and_Other_Investments_S
Equity and Other Investments - Schedule of Summarized Results of Operations (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule of Equity Method Investments [Line Items] | ||
Equity and other unconsolidated investments | $264,020 | $269,338 |
Excess of NRP's investment over net book value of NRP's equity interest | 65,400 | |
Equity and other unconsolidated investment income | 41,416 | 34,186 |
OCI LP and OCI Co [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Net book value of NRP's equity interests | 101,311 | 96,692 |
Equity and other unconsolidated investments | 264,020 | 269,338 |
Excess of NRP's investment over net book value of NRP's equity interest | 162,709 | 172,646 |
Income allocation to NRP's equity interests | 47,354 | 37,036 |
Amortization of basis difference | -5,938 | -2,850 |
Equity and other unconsolidated investment income | $41,416 | $34,186 |
Equity_and_Other_Investments_S1
Equity and Other Investments - Schedule of Summarized Financial Information of Unaudited Financial Statements (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Schedule of Equity Method Investments [Line Items] | |||||||||||
Net income | $8,645 | $36,173 | $31,407 | $32,605 | $46,981 | $36,126 | $41,065 | $47,906 | $108,830 | $172,078 | $213,355 |
Current assets | 136,118 | 135,607 | 136,118 | 135,607 | |||||||
Current liabilities | 147,931 | 123,388 | 147,931 | 123,388 | |||||||
OCI LP and OCI Co [Member] | |||||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||||
Sales | 465,032 | 442,132 | |||||||||
Gross profit | 118,439 | 94,299 | |||||||||
Net income | 96,640 | 79,655 | |||||||||
Current assets | 200,622 | 201,265 | 200,622 | 201,265 | |||||||
Noncurrent assets | 202,282 | 194,508 | 202,282 | 194,508 | |||||||
Current liabilities | 47,704 | 39,663 | 47,704 | 39,663 | |||||||
Noncurrent liabilities | $149,192 | $158,779 | $149,192 | $158,779 |
Allowance_for_Doubtful_Account2
Allowance for Doubtful Accounts - Additional Information (Detail) (VantaCore Partners LP [Member], USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
VantaCore Partners LP [Member] | |
Allowance For Doubtful Accounts Receivable [Line Items] | |
Allowance for doubtful accounts | $0.50 |
Allowance_for_Doubtful_Account3
Allowance for Doubtful Accounts - Allowance for Doubtful Accounts (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Provision charged to operations: | |||
Non-recoverable balances written off | ($714) | ||
Allowance for Doubtful Accounts [Member] | |||
Allowance For Doubtful Accounts Receivable [Line Items] | |||
Balance, January 1 | 275 | 711 | 393 |
Provision charged to operations: | |||
Additions to the reserve | 774 | 278 | 318 |
Collections of previously reserved accounts | -373 | ||
Total charged (credited) to operations | 401 | 278 | 318 |
Balance, December 31 | $676 | $275 | $711 |
Inventory_Components_of_Invent
Inventory - Components of Inventories (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Inventory Disclosure [Abstract] | |
Aggregates | $4,596 |
Supplies and parts | 1,218 |
Total | $5,814 |
Plant_and_Equipment_Plant_and_
Plant and Equipment - Plant and Equipment (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Property, Plant and Equipment [Abstract] | |||
Construction in process | $457 | ||
Plant and equipment at cost | 89,759 | 55,271 | |
Less accumulated depreciation | -30,123 | -28,836 | |
Net book value | 60,093 | 26,435 | |
Total depreciation expense on plant and equipment | $7,631 | $5,966 | $6,825 |
Plant_and_Equipment_Additional
Plant and Equipment - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Property, Plant and Equipment [Abstract] | |||||||
Impairment charge | $20,585 | $5,624 | $443 | $291 | $26,209 | $734 | $2,568 |
Mineral_Rights_Mineral_Rights_
Mineral Rights - Mineral Rights (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Less accumulated depletion and amortization | ($546,619) | ($489,465) | |
Net book value | 1,781,852 | 1,405,455 | |
Total depletion and amortization expense on mineral interests | 68,603 | 54,595 | 47,042 |
Coal [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Partnership's mineral rights | 1,541,572 | 1,574,914 | |
Oil And Gas [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Partnership's mineral rights | 560,395 | 204,906 | |
Aggregate [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Partnership's mineral rights | 211,490 | 100,080 | |
Other [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Partnership's mineral rights | $15,014 | $15,020 |
Mineral_Rights_Additional_Info
Mineral Rights - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Property Subject to or Available for Operating Lease [Line Items] | |||||||
Impairment expense | $20,585 | $5,624 | $443 | $291 | $26,209 | $734 | $2,568 |
Coal and Aggregates Mineral Rights [Member] | |||||||
Property Subject to or Available for Operating Lease [Line Items] | |||||||
Impairment expense | $19,800 |
Intangible_Assets_Intangible_A
Intangible Assets - Intangible Assets (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Contract intangibles | $82,972 | $89,421 | |
Other intangibles | 3,004 | ||
Less accumulated amortization | -25,243 | -22,471 | |
Net book value | 60,733 | 66,950 | |
Total amortization expense on intangible assets | $3,642 | $3,816 | $4,354 |
Intangible_Assets_Additional_I
Intangible Assets - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Intangible Assets [Line Items] | |||||||
Contract intangibles Asset | $82,972,000 | $82,972,000 | $89,421,000 | ||||
Asset impairment expenses | 20,585,000 | 5,624,000 | 443,000 | 291,000 | 26,209,000 | 734,000 | 2,568,000 |
VantaCore Partners LP [Member] | |||||||
Intangible Assets [Line Items] | |||||||
Goodwill | 52,000,000 | ||||||
Assets Held-for-sale [Member] | |||||||
Intangible Assets [Line Items] | |||||||
Contract intangibles Asset | $1,300,000 | $1,300,000 |
Intangible_Assets_Estimated_Am
Intangible Assets - Estimated Amortization Expense (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
For year ended December 31, 2015 | $3,486 |
For year ended December 31, 2016 | 3,743 |
For year ended December 31, 2017 | 3,326 |
For year ended December 31, 2018 | 3,126 |
For year ended December 31, 2019 | $3,053 |
LongTerm_Debt_Additional_Infor
Long-Term Debt - Additional Information (Detail) (USD $) | 12 Months Ended | 3 Months Ended | 1 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Aug. 31, 2013 | Oct. 31, 2014 | |
Debt Instrument [Line Items] | |||||||
Rate of Senior Notes due | 9.13% | ||||||
Term Loan | $327,983,000 | $386,230,000 | $30,800,000 | ||||
Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Repayment of principal amount | 24,000,000 | 101,000,000 | |||||
Weighted average interest rate for the debt outstanding | 2.22% | 2.43% | |||||
Amount received from debt issuance | 200,000,000 | ||||||
Borrowings outstanding | 75,000,000 | ||||||
NRP LP [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Rate of Senior Notes due | 9.13% | 9.13% | 9.13% | 9.13% | |||
Floating rate revolving credit facility | 300,000,000 | 300,000,000 | 125,000,000 | ||||
Senior Note issue percentage | 99.01% | 99.01% | 99.50% | ||||
Repayment of principal amount | 122,600,000 | ||||||
NRP LP [Member] | Maximum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Fixed charge coverage ratio | 2 | ||||||
NRP LP [Member] | Minimum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Fixed charge coverage ratio | 1 | ||||||
Opco [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Repayment of principal amount | 289,000,000 | ||||||
Term Loan | 91,000,000 | ||||||
Principal payments on its senior notes | 80,800,000 | ||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 4 | ||||||
Percentage of consolidated net tangible assets debt of subsidiaries not permitted to exceed | 10.00% | ||||||
Ratio of consolidated EBITDDA to consolidated fixed charges | 3.5 | ||||||
Additional interest accrue | 2.00% | ||||||
Partnership leverage ratio | 3.75 | ||||||
Opco [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Ratio of consolidated indebtedness to consolidated EBITDDA | 4 | ||||||
Ratio of consolidated EBITDDA to consolidated fixed charges | 3.5 | ||||||
Maximum increase in aggregate commitment | 500,000,000 | ||||||
Weighted average interest rate | 1.98% | 2.23% | |||||
Opco [Member] | $300 million floating rate revolving credit facility, due August 2016 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Floating rate revolving credit facility | 300,000,000 | ||||||
Opco [Member] | $300 million floating rate revolving credit facility, due August 2016 [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee on the undrawn portion of the revolving credit facility rates | 0.18% to 0.40% | ||||||
Opco [Member] | Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Leverage ratio, maximum | 4 | ||||||
Minimum interest coverage ratio | 3.5 | ||||||
Opco [Member] | Maximum [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee on the unused portion of the borrowing base under the credit facility | 0.40% | ||||||
Opco [Member] | Minimum [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee on the unused portion of the borrowing base under the credit facility | 0.18% | ||||||
NRP Oil and Gas [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee on the undrawn portion of the revolving credit facility rates | 0.375% to 0.50% | ||||||
Leverage ratio, maximum | 3.5 | ||||||
Debt Instrument, Interest Rate Terms | 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%. | ||||||
Current ratio, minimum | 1 | ||||||
NRP Oil and Gas [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Weighted average interest rate for the debt outstanding | 2.37% | ||||||
Borrowings outstanding | 110,000,000 | ||||||
Term of credit facility | 5 years | ||||||
Senior secured revolving credit facility | 100,000,000 | ||||||
Revolving credit facility maturity date | 12-Nov-19 | ||||||
NRP Oil and Gas [Member] | Amended On November 2014 [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Maximum increase in aggregate commitment | $500,000,000 | ||||||
NRP Oil and Gas [Member] | Maximum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee on the unused portion of the borrowing base under the credit facility | 0.50% | ||||||
NRP Oil and Gas [Member] | Minimum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee on the unused portion of the borrowing base under the credit facility | 0.38% |
LongTerm_Debt_LongTerm_Debt_De
Long-Term Debt - Long-Term Debt (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ||
Total debt | $1,475,223 | $1,165,209 |
Less - current portion of long term debt | -80,983 | -80,983 |
Long-term debt | 1,394,240 | 1,084,226 |
NRP LP [Member] | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Total debt | 422,167 | 297,170 |
Opco [Member] | $300 million floating rate revolving credit facility, due August 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Total debt | 200,000 | 20,000 |
Opco [Member] | $200 million floating rate term loan, due January 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Total debt | 75,000 | 99,000 |
Opco [Member] | 4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Total debt | 18,467 | 23,084 |
Opco [Member] | 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 | 107,143 | 128,571 |
Opco [Member] | 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 | 46,154 | 53,846 |
Opco [Member] | 5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Total debt | 1,345 | 1,538 |
Opco [Member] | 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 | 24,300 | 27,000 |
Opco [Member] | 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 | 67,500 | 75,000 |
Opco [Member] | 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 | 150,000 | 165,000 |
Opco [Member] | 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 | 45,455 | 50,000 |
Opco [Member] | 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 | 161,538 | 175,000 |
Opco [Member] | 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 | 46,154 | 50,000 |
NRP Oil and Gas [Member] | Reserve Based Revolving Credit Facility Due 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Total debt | $110,000 |
LongTerm_Debt_LongTerm_Debt_Pa
Long-Term Debt - Long-Term Debt (Parenthetical) (Detail) (USD $) | Dec. 31, 2014 | Oct. 31, 2014 | Sep. 30, 2013 |
In Millions, unless otherwise specified | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 9.13% | ||
NRP LP [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 9.13% | 9.13% | 9.13% |
Floating rate revolving credit facility | $125 | $300 | |
Senior Note issue percentage | 99.50% | 99.01% | |
9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 [Member] | NRP LP [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes, Face amount | 425 | ||
Rate of Senior Notes due | 9.13% | ||
9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 [Member] | Senior Notes issued at 99.007% [Member] | NRP LP [Member] | |||
Debt Instrument [Line Items] | |||
Floating rate revolving credit facility | 300 | ||
Senior Note issue percentage | 99.01% | ||
9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018 [Member] | Senior Notes issued at 99.5% [Member] | NRP LP [Member] | |||
Debt Instrument [Line Items] | |||
Floating rate revolving credit facility | 125 | ||
Senior Note issue percentage | 99.50% | ||
$300 million floating rate revolving credit facility, due August 2016 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Floating rate revolving credit facility | 300 | ||
$200 million floating rate term loan, due January 2016 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Floating rate revolving credit facility | 200 | ||
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 4.91% | ||
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 8.38% | ||
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 5.05% | ||
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 5.31% | ||
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 5.55% | ||
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] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 4.73% | ||
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024 [Member] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 5.82% | ||
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] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 8.92% | ||
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] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 5.03% | ||
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] | Opco [Member] | |||
Debt Instrument [Line Items] | |||
Rate of Senior Notes due | 5.18% |
LongTerm_Debt_Principal_Paymen
Long-Term Debt - Principal Payments Due (Detail) (USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ||
2015 | $80,983 | |
2016 | 355,983 | |
2017 | 80,983 | |
2018 | 505,983 | |
2019 | 186,366 | |
Thereafter | 267,758 | |
Principal Payments | 1,478,056 | |
NRP LP [Member] | Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
2018 | 425,000 | [1] |
Principal Payments | 425,000 | |
Opco [Member] | Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
2015 | 80,983 | |
2016 | 80,983 | |
2017 | 80,983 | |
2018 | 80,983 | |
2019 | 76,366 | |
Thereafter | 267,758 | |
Principal Payments | 668,056 | |
Opco [Member] | Term Loan [Member] | ||
Debt Instrument [Line Items] | ||
2016 | 75,000 | |
Principal Payments | 75,000 | |
Opco [Member] | Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
2016 | 200,000 | |
Principal Payments | 200,000 | |
NRP Oil and Gas [Member] | Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
2019 | 110,000 | |
Principal Payments | $110,000 | |
[1] | The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2014 were carried at $422.2 million. |
LongTerm_Debt_Principal_Paymen1
Long-Term Debt - Principal Payments Due (Parenthetical) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ||
Rate of Senior Notes due | 9.13% | |
Senior notes, Carrying value | $1,475,223 | $1,165,209 |
Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes, Carrying value | $422,200 |
Fair_Value_Measurements_Contra
Fair Value Measurements - Contractual Override, Note Receivable and Long-Term Debt (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Fair Value Disclosures [Abstract] | ||
Fair Value of Sugar Camp override, current and long-term | $5,162 | $6,852 |
Fair Value of Long-term debt, current and long-term | 1,096,520 | 1,071,880 |
Carrying Value of Sugar Camp override, current and long-term | 4,870 | 6,063 |
Carrying Value of Long-term debt, current and long-term | $1,090,223 | $1,046,209 |
Related_Party_Transactions_Add
Related Party Transactions - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | |||||
Dec. 31, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 31, 2014 | Sep. 30, 2012 | |
Related Party Transaction [Line Items] | |||||||||
Amount payable to related parties | $950,000 | $950,000 | $391,000 | ||||||
Lease expenses | 600,000 | ||||||||
Accounts receivable | 4,870,000 | 4,870,000 | 6,063,000 | ||||||
Contracts receivable | 50,008,000 | 50,008,000 | 51,732,000 | ||||||
Unrecouped minimum royalty payments | 86,800,000 | ||||||||
Proceeds from royalty payments in current year | 16,000,000 | ||||||||
Asset impairment | 20,585,000 | 5,624,000 | 443,000 | 291,000 | 26,209,000 | 734,000 | 2,568,000 | ||
Gain on reserve swaps | 5,700,000 | 8,100,000 | |||||||
Accounts receivable | 9,494,000 | 9,494,000 | 7,666,000 | ||||||
Rate of senior notes | 9.13% | 9.13% | |||||||
Senior Notes Due 2018 [Member] | Cline Trust Company, LLC [Member] | |||||||||
Related Party Transaction [Line Items] | |||||||||
Partnership common units owned | 5,350,000 | ||||||||
Principal amount of partnership purchased | 20,000,000 | ||||||||
Rate of senior notes | 9.13% | ||||||||
Aggregate principal amount of senior notes | 125,000,000 | ||||||||
Senior notes due | 19,900,000 | 19,900,000 | |||||||
Western Pocahontas Properties [Member] | |||||||||
Related Party Transaction [Line Items] | |||||||||
Amount payable to related parties | 400,000 | 400,000 | |||||||
Quintana Minerals [Member] | |||||||||
Related Party Transaction [Line Items] | |||||||||
Amount payable to related parties | 600,000 | 600,000 | |||||||
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 | 4,917,548 | ||||||||
Accounts receivable | 9,200,000 | 9,200,000 | |||||||
Contracts receivable | 50,008,000 | 50,008,000 | |||||||
Asset impairment | 2,600,000 | ||||||||
Net amount receivable | 5,600,000 | 5,600,000 | |||||||
Accounts receivable | 1,100,000 | 1,100,000 | |||||||
Taggart Global USA, LLC [Member] | |||||||||
Related Party Transaction [Line Items] | |||||||||
Preparation plant sale value | 12,300,000 | ||||||||
Cash received on sale of preparation plant | 10,500,000 | ||||||||
Gain on sale of preparation plant | 4,700,000 | ||||||||
Net book value of the asset | 7,600,000 | ||||||||
Corsa [Member] | |||||||||
Related Party Transaction [Line Items] | |||||||||
Accounts receivable | 300,000 | 300,000 | 300,000 | ||||||
Sugar Camp [Member] | |||||||||
Related Party Transaction [Line Items] | |||||||||
Aggregate payments remaining under the lease | 86,300,000 | 86,300,000 | |||||||
Unearned income | 39,000,000 | 39,000,000 | |||||||
Net amount receivable | 47,300,000 | 47,300,000 | |||||||
Accounts receivable | $1,800,000 | $1,800,000 |
Related_Party_Transactions_Sum
Related Party Transactions - Summary of Reimbursements (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Related Party Transactions [Abstract] | |||
Reimbursement for services | $11,798 | $11,480 | $9,791 |
Related_Party_Transactions_Sum1
Related Party Transactions - Summary of Revenues from Related Party (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Related Party Transaction [Line Items] | |||||||||||
Other revenue | $4,313 | $3,762 | $1,437 | ||||||||
Total revenues and other income | 137,273 | 91,609 | 90,561 | 80,309 | 94,744 | 82,237 | 86,804 | 94,332 | 399,752 | 358,117 | 379,147 |
Corsa [Member] | |||||||||||
Related Party Transaction [Line Items] | |||||||||||
Coal royalty revenues | 3,013 | 4,594 | 3,486 | ||||||||
Cline Affiliates [Member] | |||||||||||
Related Party Transaction [Line Items] | |||||||||||
Coal royalty revenues | 52,415 | 54,322 | 48,567 | ||||||||
Processing and transportation fees | 20,594 | 19,258 | 21,923 | ||||||||
Minimums recognized as revenue | 3,477 | 17,785 | |||||||||
Override revenue | 2,847 | 3,226 | 4,066 | ||||||||
Other revenue | 5,690 | 8,149 | |||||||||
Total revenues and other income | 81,546 | 88,432 | 92,341 | ||||||||
Forge Group [Member] | |||||||||||
Related Party Transaction [Line Items] | |||||||||||
Processing revenue | $1,761 | $5,580 |
Asset_Retirement_Obligations_A
Asset Retirement Obligations - Additional Information (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Asset Retirement Obligation Disclosure [Abstract] | |
Accounts payable and accrued liabilities | $68,000 |
Asset_Retirement_Obligations_S
Asset Retirement Obligations - Schedule of Reconciliation of Beginning and Ending Carrying Amounts of Partnership's Asset Retirement Obligations (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2012 |
Asset Retirement Obligation Disclosure [Abstract] | ||
Balance, January 1 | $39 | $39 |
Liabilities incurred in current period | 4,697 | |
Accretion expense | 237 | |
Balance, December 31 | $4,973 | $39 |
Major_Lessees_Revenues_from_Le
Major Lessees - Revenues from Lessees that Exceeded Ten Percent of Total Revenues and Other Income (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Foresight Energy and affiliates [Member] | |||
Operating Leased Assets [Line Items] | |||
Revenues | $81,546 | $88,432 | $92,341 |
Percent | 20.40% | 24.70% | 24.40% |
Alpha Natural Resources [Member] | |||
Operating Leased Assets [Line Items] | |||
Revenues | $48,783 | $55,147 | $81,077 |
Percent | 12.20% | 15.40% | 21.40% |
Major_Lessees_Additional_Infor
Major Lessees - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Operating Leased Assets [Line Items] | |||
Minimum Percentage of revenues and other income derived from major two leases | 32.60% | ||
Percentage of revenue derived from major lease | 50.00% | ||
Total revenue attributable | 30.00% | ||
Williamson [Member] | |||
Operating Leased Assets [Line Items] | |||
Percentage of revenues and other income received from major lessee excluding reserve swap | 10.20% | 13.00% | 12.40% |
Incentive_Plans_Additional_Inf
Incentive Plans - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Market value of common units under the incentive plan | Average closing price over the 20 trading days prior to the vesting date. | ||
Vesting period of Grants in years | 4 years | ||
Risk free interest rate | 0.26% | ||
Risk free interest rate | 1.06% | ||
Volatility rate | 33.40% | ||
Volatility rate | 43.43% | ||
Partnership's historical distribution rate | 7.46% | ||
Expenses related to Incentive Plan to be reimbursed to general partner | $4,413,000 | $293,000 | $59,000 |
Payments made in connection with Long-Term Incentive Plan | 6,500,000 | 7,000,000 | 6,600,000 |
Grant date fair value | 17.73 | 25.27 | 33.38 |
Unaccrued cost associated with outstanding grants and related DERs | 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 | $1,000,000 | $9,600,000 | $2,900,000 |
Incentive_Plans_Summary_of_Act
Incentive Plans - Summary of Activity in Outstanding Grants (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Compensation and Retirement Disclosure [Abstract] | |
Outstanding grants at the beginning of the period | 1,012,984 |
Grants during the period | 454,884 |
Grants vested and paid during the period | -285,500 |
Forfeitures during the period | -28,975 |
Outstanding grants at the end of the period | 1,153,393 |
Subsequent_Events_Unaudited_Ad
Subsequent Events (Unaudited) - Additional Information (Detail) (USD $) | 0 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Feb. 27, 2015 | Jan. 20, 2015 |
OCI Wyoming [Member] | ||
Subsequent Event [Line Items] | ||
Cash distributions from equity investment | $10.90 | |
Subsequent Event [Member] | ||
Subsequent Event [Line Items] | ||
Distributions per unit declared | $0.35 |
Supplemental_Financial_Data_Un2
Supplemental Financial Data (Unaudited) - Selected Quarterly Financial Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total revenues and other income | $137,273 | $91,609 | $90,561 | $80,309 | $94,744 | $82,237 | $86,804 | $94,332 | $399,752 | $358,117 | $379,147 |
Depreciation, depletion and amortization | 30,258 | 18,621 | 16,350 | 14,647 | 14,352 | 17,852 | 17,411 | 14,762 | 79,876 | 64,377 | 58,221 |
Income from operations | 31,050 | 55,027 | 50,403 | 52,439 | 66,752 | 51,624 | 55,332 | 62,528 | 188,919 | 236,236 | 267,165 |
Asset impairment | 20,585 | 5,624 | 443 | 291 | 26,209 | 734 | 2,568 | ||||
Gain on Department of Highway condemnation | 10,370 | ||||||||||
Net income | $8,645 | $36,173 | $31,407 | $32,605 | $46,981 | $36,126 | $41,065 | $47,906 | $108,830 | $172,078 | $213,355 |
Net income per limited partner unit | $0.07 | $0.32 | $0.28 | $0.29 | $0.42 | $0.32 | $0.37 | $0.43 | |||
Weighted average number of common units outstanding | 121,449 | 111,244 | 110,403 | 109,848 | 109,812 | 109,812 | 109,812 | 108,887 | 113,262 | 109,584 | 106,028 |
Supplemental_Oil_and_Gas_Data_2
Supplemental Oil and Gas Data (Unaudited) - Summary of Capitalized Costs (Detail) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Supplementary Information On Oil And Gas Extraction Activities [Abstract] | |
Proven properties | $361,554 |
Unproven properties | 46,400 |
Intangible drilling costs | 25,217 |
Wells and related equipment | 5,382 |
Gathering assets | 0 |
Well plugging | 0 |
Total property, plant, and equipment | 438,553 |
Accumulated depreciation, depletion, and amortization | -18,993 |
Net capitalized costs | $419,560 |
Supplemental_Oil_and_Gas_Data_3
Supplemental Oil and Gas Data (Unaudited) - Costs Incurred for Property Acquisition Exploration and Development (Detail) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Property acquisitions | |
Proven properties | $298,627 |
Unproven properties | 40,800 |
Development | 5,340 |
Exploration | 0 |
Total | $344,767 |
Supplemental_Oil_and_Gas_Data_4
Supplemental Oil and Gas Data (Unaudited) - Results of Operations for Producing Activities (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | |
Supplementary Information On Oil And Gas Extraction Activities [Abstract] | ||
Production revenue | $48,834 | |
Royalty and overriding royalty revenue | 10,732 | [1] |
Total oil and gas related revenue | 59,566 | |
Operating costs and expense: | ||
Depreciation, depletion and amortization | 23,936 | |
General and administrative | 3,400 | |
Property, franchise and other taxes | 5,529 | |
Lease operating expenses | 9,144 | |
Total operating costs and expense | 42,009 | |
Total income from operations | $17,557 | |
[1] | Includes $1.9 million of nonproduction revenues including lease bonus payments. |
Supplemental_Oil_and_Gas_Data_5
Supplemental Oil and Gas Data (Unaudited) - Results of Operations for Producing Activities (Parenthetical) (Detail) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Supplementary Information On Oil And Gas Extraction Activities [Abstract] | |
Nonproduction revenue | $1.90 |
Supplemental_Oil_and_Gas_Data_6
Supplemental Oil and Gas Data (Unaudited) - Summary of Information Concerning Production Results, Average Sales Prices and Production Costs (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
production expenses, Average costs | 13.08 |
Ad valorem and severance taxes, Average costs | 7.91 |
General and administrative expense, Average costs | 4.86 |
DD&A expense, average costs | 24.7 |
Williston Basin [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
production expenses, Average costs | 13.08 |
Ad valorem and severance taxes, Average costs | 7.91 |
General and administrative expense, Average costs | 4.86 |
DD&A expense, average costs | 25.73 |
Royalty and Overriding Royalty Interest Wells [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
DD&A expense, average costs | 22.06 |
Crude Oil [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 611 |
Average sales prices | 78.12 |
Crude Oil [Member] | Williston Basin [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 578 |
Average sales prices | 77.85 |
Crude Oil [Member] | Royalty and Overriding Royalty Interest Wells [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 33 |
Average sales prices | 82.91 |
NGLs [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 71 |
Average sales prices | 33.87 |
NGLs [Member] | Williston Basin [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 53 |
Average sales prices | 33.64 |
NGLs [Member] | Royalty and Overriding Royalty Interest Wells [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 18 |
Average sales prices | 34.56 |
Natural Gas [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 1,721 |
Average sales prices | 4.37 |
Natural Gas [Member] | Williston Basin [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 408 |
Average sales prices | 5.04 |
Natural Gas [Member] | Royalty and Overriding Royalty Interest Wells [Member] | |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |
Net Production Volumes | 1,313 |
Average sales prices | 4.17 |
Supplemental_Oil_and_Gas_Data_7
Supplemental Oil and Gas Data (Unaudited) - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Estimated proved reserves | 100.00% |
Description on pricing | Prices were calculated using the unweighted average of the first-day-of-the-month pricing |
Supplemental_Oil_and_Gas_Data_8
Supplemental Oil and Gas Data (Unaudited) - Summary of Estimated Proved Reserves and Related Standardized Measure of Discounted Cash Flows by Reserve Category (Detail) (USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | MBoe | |
Reserve Quantities [Line Items] | ||
Proved Developed | 12,144 | |
Total | 13,607 | [1],[2],[3] |
Standardized measure of discounted cash flows | $305,197 | [1],[4] |
Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 12,189 | [1],[2] |
Standardized measure of discounted cash flows | 286,179 | [1],[4] |
Non Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 32 | [1],[2] |
Standardized measure of discounted cash flows | 655 | [1],[4] |
Undeveloped Reserves [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Undeveloped | 1,386 | [1],[2] |
Standardized measure of discounted cash flows | $18,363 | [1],[4] |
Crude Oil [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Undeveloped | 1,053 | [1] |
Total | 9,983 | [1] |
Crude Oil [Member] | Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 8,918 | [1] |
Crude Oil [Member] | Non Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 12 | [1] |
NGLs [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Undeveloped | 131 | [1] |
Total | 1,229 | [1] |
NGLs [Member] | Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 1,093 | [1] |
NGLs [Member] | Non Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 5 | [1] |
Natural Gas [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Undeveloped | 1,209 | [1] |
Total | 14,370 | [1] |
Natural Gas [Member] | Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 13,069 | [1] |
Natural Gas [Member] | Non Producing [Member] | ||
Reserve Quantities [Line Items] | ||
Proved Developed | 92 | [1] |
[1] | Includes reserves attributable to our 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 12,144 MBoe of estimated proved reserves attributable to our non-operated working interests in oil and natural gas properties in the Williston Basin, approximately 10% of which were proved undeveloped reserves. | |
[4] | Standardized measure of discounted cash flows represents the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. |
Supplemental_Oil_and_Gas_Data_9
Supplemental Oil and Gas Data (Unaudited) - Summary of Estimated Proved Reserves and Related Standardized Measure of Discounted Cash Flows by Reserve Category (Parenthetical) (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
MBoe | |
Reserve Quantities [Line Items] | |
Percentage on estimated proved reserves | 100.00% |
Discount on future revenue, percentage | 10.00% |
Estimated proved reserve | 12,144 |
Energy content equivalency, description | Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. |
Percentage of Williston proved undeveloped reserves | 10.00% |
Brp Llc [Member] | |
Reserve Quantities [Line Items] | |
Percentage on estimated proved reserves | 51.00% |
Recovered_Sheet1
Supplemental Oil and Gas Data (Unaudited) - Schedule of Capitalized Exploratory Well Cost Activity (Detail) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Capitalized Costs Relating To Oil And Gas Properties [Line Items] | |
For a period one year or less | $5,340 |
Total | 5,340 |
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves | 5,177 |
Costs expensed due to determination of dry hole or abandonment of project | 0 |
Aging of Capitalized Exploratory Well Costs, Period Four [Member] | |
Capitalized Costs Relating To Oil And Gas Properties [Line Items] | |
For a period greater than five years | 0 |
Aging of Capitalized Exploratory Well Costs, Period Five [Member] | |
Capitalized Costs Relating To Oil And Gas Properties [Line Items] | |
For a period greater than five years | $0 |
Recovered_Sheet2
Supplemental Oil and Gas Data (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Future Cash Flows: | ||
Revenues | $920,454 | |
Production costs | 312,666 | |
Development costs | 20,072 | |
Future Net Cash Flows | 587,716 | |
Discount to present value at a 10% annual rate | 282,519 | |
Total standardized measure of discounted net cash flows | $305,197 | [1],[2] |
[1] | Includes reserves attributable to our 51% member interest in BRP LLC. | |
[2] | Standardized measure of discounted cash flows represents the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. |