Natural Resource Partners (NRP) 10-K 27 Feb 15 2014 FY Annual report Financial data

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.