Natural Resource Partners (NRP) 10-K 1 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	NRP
Entity Registrant Name	NATURAL RESOURCE PARTNERS LP
Entity Central Index Key	1,171,486
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		12,241,602
Entity Public Float			$ 218

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 29,827	$ 40,371
Accounts receivable, net	47,026	43,202
Accounts receivable—affiliates, net	161	6,658
Inventory	7,553	6,893
Prepaid expenses and other	5,838	7,271
Current assets of discontinued operations (see Note 7)	991	991
Total current assets	91,396	105,386
Land	25,247	25,252
Plant and equipment, net	46,170	49,443
Mineral rights, net	883,885	908,192
Intangible assets, net	49,554	3,236
Intangible assets, net—affiliate	0	49,811
Equity in unconsolidated investment	245,433	255,901
Long-term contracts receivable	40,776	0
Long-term contracts receivable—affiliate	0	43,785
Other assets	6,547	6,625
Other assets—affiliate	156	1,018
Total assets	1,389,164	1,448,649
Current liabilities:
Accounts payable	6,957	6,234
Accounts payable—affiliates	562	940
Accrued liabilities	16,890	25,999
Accrued liabilities—affiliates	515	0
Accrued interest	15,484	15,588
Current portion of long-term debt, net	79,740	140,037
Current liabilities of discontinued operations (see Note 7)	401	353
Total current liabilities	120,549	189,151
Deferred revenue	100,605	44,931
Deferred revenue—affiliates	0	71,632
Long-term debt, net	729,608	990,234
Other non-current liabilities	2,808	4,565
Other non-current liabilities—affiliate	346	0
Total liabilities	953,916	1,300,513
Commitments and contingencies (see Note 17)	0	0
Class A Convertible Preferred Units (258,844 units issued and outstanding at $1,000 par value per unit; liquidation preference of $1,500 per unit)	173,431	0
Partners’ capital:
Common unitholders’ interest (12,232,006 units issued and outstanding)	199,851	152,309
General partner’s interest	1,857	887
Warrant holders’ interest	66,816	0
Accumulated other comprehensive loss	(3,313)	(1,666)
Total partners’ capital	265,211	151,530
Non-controlling interest	(3,394)	(3,394)
Total capital	261,817	148,136
Total liabilities and capital	$ 1,389,164	$ 1,448,649

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common Units Outstanding	12,232,006	12,232,006
Common Units Issued	12,232,006	12,232,006
Preferred Units Issued	258,844	0
Preferred Units Outstanding	258,844	0
Preferred unit purchase price	$ 1,000	$ 0
Temporary Equity, Liquidation Preference Per Share	$ 1,500	$ 0

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income:
Revenues and other income	$ 374,161	$ 370,978	$ 432,748
Gain on asset sales, net	3,856	29,081	6,900
Total revenues and other income	378,017	400,059	439,648
Operating expenses:
Operating and maintenance expenses	126,982	119,621	136,943
Operating and maintenance expenses—affiliates, net	9,534	10,925	15,323
Depreciation, depletion and amortization	34,985	43,087	57,295
Amortization expense—affiliate	1,008	3,185	3,621
General and administrative	13,513	16,979	7,036
General and administrative—affiliates	4,989	3,591	5,312
Asset impairments	3,031	16,926	384,545
Total operating expenses	194,042	214,314	610,075
Income (loss) from operations	183,975	185,745	(170,427)
Other income (expense)
Interest expense	(82,902)	(90,047)	(87,911)
Interest expense—affiliate	0	(523)	(1,851)
Debt modification expense	(7,939)	0	0
Loss on extinguishment of debt	(4,107)	0	0
Interest income	181	39	18
Other expense, net	(94,767)	(90,531)	(89,744)
Net income (loss) from continuing operations	89,208	95,214	(260,171)
Net income (loss) from discontinued operations	(541)	1,678	(311,549)
Net income (loss)	88,667	96,892	(571,720)
Less: income attributable to preferred unitholders	(25,453)	0	0
Net income (loss) attributable to common unitholders and general partner	63,214	96,892	(571,720)
Net income (loss) attributable to common unitholders	61,950	95,229	(559,492)
Net income (loss) attributable to the general partner	$ 1,264	$ 1,663	$ (12,228)
Net income (loss) from continuing operations per common unit
Income (loss) from continuing operations per common unit (basic)	$ 5.11	$ 7.65	$ (20.78)
Income (loss) from continuing operations per common unit (diluted)	3.98	7.65	(20.78)
Basic and diluted net income (loss) per common unit (in dollars per share):
Net income (loss) per common unit (basic)	5.06	7.78	(45.75)
Net income (loss) per common unit (diluted)	$ 3.96	$ 7.78	$ (45.75)
Add: comprehensive income (loss) from unconsolidated investment and other	$ (1,647)	$ 486	$ (1,693)
Comprehensive income (loss)	87,020	97,378	(573,413)
Coal Royalty and Other
Revenues and other income:
Revenues and other income	158,399	144,520	154,066
Coal royalty and other—affiliates	23,402	46,259	67,682
Construction Aggregates
Revenues and other income:
Revenues and other income	112,970	103,755	124,085
Soda Ash
Revenues and other income:
Revenues and other income	40,457	40,061	49,918
Transportation and processing | Coal Royalty and Other
Revenues and other income:
Revenues and other income	14,510	0	0
Transportation and processing—affiliates | Coal Royalty and Other
Revenues and other income:
Coal royalty and other—affiliates	6,012	19,336	22,033
Road construction and asphalt paving | Construction Aggregates
Revenues and other income:
Revenues and other income	$ 18,411	$ 17,047	$ 14,964

Consolidated Statements of Part

Consolidated Statements of Partners' Capital - USD ($) shares in Thousands, $ in Thousands	Total	General Partner	Common Unitholders	Warrant Holders	Accumulated Other Comprehensive Income (Loss)	Partners Capital Excluding Noncontrolling Interest	Non-Controlling Interest	Common unitholders	Common unitholdersCommon Unitholders	General Partner	General PartnerGeneral Partner	Common unitholders and general partner	Common unitholders and general partnerPartners Capital Excluding Noncontrolling Interest	Preferred Partner	Preferred PartnerGeneral Partner	Preferred PartnerCommon Unitholders	Preferred PartnerPartners Capital Excluding Noncontrolling Interest
Balance, beginning of period (in shares) at Dec. 31, 2014			12,232
Balance, beginning of period at Dec. 31, 2014	$ 720,155	$ 12,245	$ 709,019	$ 0	$ (459)	$ 720,805	$ (650)
Net income (loss)	(571,720)	(12,228)	(559,492)			(571,720)
Cost associated with equity transactions	(109)		$ (109)			(109)
Distributions to unitholders									$ (70,324)		$ (1,434)	$ (71,758)	$ (71,758)
Distributions to non-controlling interests	(2,744)						(2,744)
Comprehensive income from unconsolidated investment and other	(1,693)				(1,693)	(1,693)
Non-cash contributions	811	811				811
Balance, end of period (in shares) at Dec. 31, 2015			12,232
Balance, end of period at Dec. 31, 2015	72,942	(606)	$ 79,094	0	(2,152)	76,336	(3,394)
Income attributable to preferred unitholders	0
Net income (loss)	96,892	1,663	$ 95,229			96,892
Distributions to unitholders									(22,014)		(451)	(22,465)	(22,465)
Comprehensive income from unconsolidated investment and other	486				486	486
Non-cash contributions	281	281				281
Balance, end of period (in shares) at Dec. 31, 2016			12,232
Balance, end of period at Dec. 31, 2016	148,136	887	$ 152,309	0	(1,666)	151,530	(3,394)
Income attributable to preferred unitholders	0
Net income (loss)	88,667	1,773	$ 86,894			88,667
Distributions to unitholders									$ (22,018)		$ (449)	$ (22,467)	$ (22,467)	$ (17,688)	$ 354	$ 17,334	$ (17,688)
Issuance of Warrants	66,816			66,816		66,816
Comprehensive income from unconsolidated investment and other	(1,647)				(1,647)	(1,647)
Balance, end of period (in shares) at Dec. 31, 2017			12,232
Balance, end of period at Dec. 31, 2017	261,817	$ 1,857	$ 199,851	$ 66,816	$ (3,313)	$ 265,211	$ (3,394)
Income attributable to preferred unitholders	$ 25,453							$ (24,900)		$ (500)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income (loss)	$ 88,667	$ 96,892	$ (571,720)
Adjustments to reconcile net income (loss) to net cash provided by operating activities of continuing operations:
Depreciation, depletion and amortization	34,985	43,087	57,295
Amortization expense—affiliate	1,008	3,185	3,621
Return on earnings from unconsolidated investment	43,354	46,550	46,795
Equity earnings from unconsolidated investment	(40,457)	(40,061)	(49,918)
Gain on asset sales, net	(3,856)	(29,081)	(6,900)
Debt modification expense	7,939	0	0
Loss on extinguishment of debt	4,107	0	0
(Income) loss from discontinued operations	541	(1,678)	311,549
Asset impairments	3,031	16,926	384,545
Gain on reserve swap	0	0	(9,290)
Amortization of debt issuance costs and other	8,005	8,284	(7,109)
Other, net—affiliates	1,207	993	(912)
Change in operating assets and liabilities:
Accounts receivable	2,305	431	7,705
Accounts receivable—affiliates	367	(313)	3,149
Accounts payable	1,361	707	(3,625)
Accounts payable—affiliates	(377)	139	(32)
Accrued liabilities	(8,443)	5,397	2,656
Accrued liabilities—affiliates	515	0	0
Accrued interest	(105)	(779)	(1,236)
Accrued interest—affiliates	0	(456)	0
Deferred revenue	(5,791)	(35,881)	7,605
Deferred revenue—affiliates	(10,166)	(11,222)	(4,200)
Other items, net	(359)	(2,477)	(1,466)
Net cash provided by operating activities of continuing operations	127,838	100,643	168,512
Net cash provided by (used in) operating activities of discontinued operations	(699)	7,318	34,912
Net cash provided by operating activities	127,139	107,961	203,424
Cash flows from investing activities:
Return of equity from unconsolidated investment	5,646	0	0
Proceeds from sale of assets	1,982	62,383	14,529
Return of long-term contract receivable	2,206	0	0
Return of long-term contract receivables—affiliate	804	2,968	2,463
Acquisition of plant and equipment and other	(7,301)	(5,408)	(9,607)
Acquisition of mineral rights	0	0	(400)
Net cash provided by investing activities of continuing operations	3,337	59,943	6,985
Net cash provided by (used in) investing activities of discontinued operations	206	106,872	(37,256)
Net cash provided by (used in) investing activities	3,543	166,815	(30,271)
Cash flows from financing activities:
Proceeds from issuance of Class A Convertible Preferred Units and Warrants, net	242,100	0	0
Proceeds from issuance of 2022 Senior Notes, net	103,688	0	0
Proceeds from loans	77,000	20,000	100,000
Repayments of loans	(492,319)	(183,141)	(165,983)
Distributions to non-controlling interest	0	0	(2,744)
Proceeds from (contributions to) discontinued operations	(493)	39,421	(36,725)
Debt issue costs and other	(40,384)	(15,234)	(6,054)
Net cash used in financing activities of continuing operations	(141,719)	(161,419)	(183,264)
Net cash provided by (used in) financing activities of discontinued operations	493	(124,759)	11,808
Net cash used in financing activities	(141,226)	(286,178)	(171,456)
Net increase (decrease) in cash and cash equivalents	(10,544)	(11,402)	1,697
Cash and cash equivalents of continuing operations at beginning of period	29,827	40,371	41,204
Cash and cash equivalents of discontinued operations at beginning of period	0	0	10,569
Cash and cash equivalents at beginning of period	40,371	51,773	50,076
Cash and cash equivalents at end of period	29,827	40,371	51,773
Cash paid during the period for interest from continuing operations	72,850	84,380	85,738
Cash paid during the period for interest from discontinued operations	0	1,906	2,755
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities	294	0	4,304
Issuance of 2022 Senior Notes in exchange for 2018 Senior Notes	240,638	0	0
Preferred Partner
Cash flows from financing activities:
Distributions to common unitholders and general partner	(8,844)	0	0
General Partner
Cash flows from financing activities:
Distributions to common unitholders and general partner	$ (22,467)	$ (22,465)	$ (71,758)

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning, operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates and other natural resources and is organized into three operating segments further described in Note 6. Segment Information . As used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or indicated by context. The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through one wholly owned operating company, NRP (Operating) LLC ("Opco"). NRP GP has sole responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC ("RCM"), a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Subject to the Board Representation and Observation Rights Agreement with certain entities controlled by funds affiliated with The Blackstone Group, L.P. (collectively referred to as "Blackstone") and affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree"), RCM is entitled to appoint the directors of the Board of Directors of GP Natural Resource Partners LLC. RCM has delegated the right to appoint one director to Blackstone.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with International Paper Company controlled by the Partnership. The Partnership has an equity investment through which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the investee’s activities and is accounted for using the equity method. Intercompany transactions and balances have been eliminated. Certain reclassifications have been made to prior year amounts on the Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income (Loss) and Statements of Cash Flows to conform with current year presentation. These reclassifications have no impact on previously reported assets, liabilities, total revenues and other income, net income (loss), or cash flows from operations, investing or financing. Use of Estimates Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income (Loss) during the reporting period. Actual results could differ from those estimates. The most significant estimates pertain to coal and aggregate reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization and impairments of coal and aggregate properties and commitments and contingencies. 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 14. 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. Allowance for Doubtful Accounts Accounts receivable are recorded net of the allowance for doubtful accounts. The Partnership records an allowance for doubtful accounts for receivables which it determines to be uncollectible based on the specific identification method. Accounts are written off when collection efforts are exhausted and future recovery is doubtful. The allowance for doubtful accounts included in the Partnership's net accounts receivable balance (including affiliates) was $5.1 million and $4.6 million at December 31, 2017 and December 31, 2016 , respectively. A significant amount of the Partnership's allowance for doubtful accounts relates to coal-related receivables. The Partnership recorded bad debt expense of $2.4 million , $0.4 million and $4.9 million , respectively, included in Operating and maintenance expense (including affiliates) on its Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015, respectively. Inventory Inventories are comprised of aggregates and supplies and parts and are stated at the lower of cost or net realizable value. 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 and parts inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Partnership’s aggregates operations. Plant and Equipment Plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the asset acquired and consists of coal preparation plants, related coal handling facilities, and other coal and aggregate transportation and processing infrastructure. Expenditures for new facilities or 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 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 costs for construction in process and mine development 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. Once production commences, capitalization of such costs ceases. Mine development costs are amortized based on production over the estimated life of mineral reserves and amortization is included as a component of depreciation expense. Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein. 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 over the remaining term of the underlying lease for temporarily idled assets. Asset Impairment The Partnership has developed procedures to evaluate its long-lived assets for possible impairment periodically or whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. These procedures are performed throughout the year and are based on historic, current and future performance and consider 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. The Partnership believes its estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a property. The Partnership evaluates its equity investment 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 potential 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. Revenue Recognition Coal Royalty and Other Revenues. Coal royalty and other revenues are recognized on the basis of tons of mineral mined or 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 mine or sell. While the Partnership may have multiple contracts with a single lessee, such contracts are accounted for as separate arrangements. Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as deferred revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenue when the underlying mineral lease recoups the minimum payment through production or is recognized as minimums recognized as revenue in the period immediately following the expiration of the lessee’s ability to recoup the payments. 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. Oil and gas related revenues consist of revenues from royalties and overriding royalties and 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. Transportation and Processing. 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. Processing fees are recognized on the basis of tons of material processed through the facilities by the 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. These fees are included in Transportation and processing fees (or Transportation and processing fees-affiliate) in the Consolidated Statements of Comprehensive Income (Loss). Equity in Earnings from Ciner Wyoming. The Partnership accounts for non-marketable equity 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. The Partnership accounts for its investment in Ciner Wyoming, of which it owns 49% , using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets 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 (Loss). The carrying value in Ciner Wyoming is reflected in the caption "Equity in unconsolidated investment" in the Partnership's Consolidated Balance Sheets. The Partnership's adjusted share of the earnings or losses of Ciner Wyoming is reflected in the Consolidated Statements of Comprehensive Income (Loss) as revenues and other income under the caption ‘‘Equity in earnings of Ciner Wyoming." The Partnership's share of 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 net assets, 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. In reporting cash flows of its equity method investment in Ciner Wyoming, the Partnership utilizes the cumulative earnings approach in which distributions received are considered returns on investment and classified as cash inflows from operating activities unless the cumulative distributions received exceed cumulative equity in earnings recognized by the Partnership, in which case the excess cumulative distributions received would be classified as cash inflows from investing activities as a return of investment. Construction Aggregates Revenues. Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Road Construction and Asphalt Paving. 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. See "—Recently Issued Accounting Standards - Revenue Recognition" below for information regarding the impact of adopting the new revenue recognition standard in January 2018. 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 Operating and maintenance expenses and in Coal Royalty and Other revenues, respectively, in the Consolidated Statements of Comprehensive Income (Loss). Transportation Revenue and Expense The Partnership records transportation revenue and pays transportation costs to a Foresight Energy LP ("Foresight Energy") affiliate to operate equipment on behalf of the Partnership. The revenue and expenses related to these transactions are recorded as Transportation and processing revenues (or Transportation and processing revenues—affiliates) and Operating and maintenance expenses or (Operating and maintenance expenses—affiliates), respectively, in the Consolidated Statements of Comprehensive Income (Loss). Subsequent to May 9, 2017, Foresight Energy is no longer deemed a related party; refer to Note 15. Related Party Transactions for further details. Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as Construction Aggregates revenues and Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income (Loss). Shipping and handling revenue included in Construction Aggregates revenues was $38.9 million , $36.0 million and $42.6 million for the years ended December 31, 2017, 2016 and 2015, respectively. Shipping and handling costs included in Operating and maintenance expenses was $36.3 million , $35.9 million and $42.1 million for the years ended December 31, 2017, 2016, and 2015, respectively. Unit-Based Compensation The Partnership has awarded unit-based compensation in the form of phantom units and accounts for such awards using the fair value method, which requires the Partnership to estimate compensation costs based on the fair value of the grant and remeasure each reporting period based on the Partnership’s common unit price over the requisite service, which is generally vesting period of the grant. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability. Unit-based compensation expense is recognized in General and administrative expense in the Consolidated Statements of Comprehensive Income. 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 line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's revolving credit facility are included in other assets (long-term) and deferred financing costs related to the Partnership's note agreements are included as a direct deduction from the carrying amount of the debt liability in Long-term debt, net on the Partnership's Consolidated Balance Sheets. Income Taxes The Partnership is not subject to federal or material state income taxes, as the partners are taxed individually on their allocable share of taxable income. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis 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. Recently Adopted Accounting Standards Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-15, Statement of Cash Flows (Topic 230), which is intended to clarify how certain cash receipts and cash payments are presented and classified in the statement of cash flows in order to reduce current and potential future diversity in practice. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. The Partnership elected to early adopt this guidance in the second quarter of 2017 and elected to continue to classify distributions it received from its equity method investees under the cumulative earnings approach in which distributions received are considered returns on investment and classified as cash inflows from operating activities unless the cumulative distributions received exceed cumulative equity in earnings recognized by the Partnership. The early adoption of this guidance in the second quarter of 2017 did not have a material effect on its consolidated financial statements. Accounting Changes and Error Corrections. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately. The Partnership adopted this guidance during the first quarter of 2017. The adoption of this guidance impacted the Partnership's disclosures but had no effect on its financial position, results of operations or cash flows. Earnings per Share. In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception. The guidance eliminates the requirement to consider "down-round" features when determining whether certain equity-linked financial instruments or embedded features are indexed to an entity’s own stock. The guidance requires entities that present earnings per share ("EPS") under ASC 260 to recognize the effect of a down-round feature in a freestanding equity-classified financial instrument only when it is triggered. The effect of triggering such a feature will be recognized as a dividend and a reduction to income available to common shareholders in basic EPS. Entities will also have to make new disclosures for financial instruments with down-round features and other terms that change conversion or exercise prices. The guidance is effective for annual and interim periods ending after December 31, 2018 and early adoption is permitted. The Partnership early adopted this guidance in the third quarter of 2017. Refer to Note 2. Change in Method of Accounting for NRP's Warrants in the Partnerships September 30, 2017 Form 10-Q for disclosure of the effects of adoption on its quarterly consolidated financial statements. There was no impact to the consolidated financial statements for the years ended December 31, 2017, 2016 and 2015. Recently Issued Accounting Standards Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, ASC Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. Additionally, in March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvements and practical expedients, which addresses narrow-scope improvements to the guidance on collectibility, non-cash consideration, and completed contracts at transition. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which clarifies the guidance or corrects unintended application of guidance. The Partnership adopted the new standard on January 1, 2018 and has elected to use the modified retrospective adoption method. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue. The Partnership identified the contracts for all of its revenue streams and utilized the practical expedient of grouping contracts or performance obligations with similar characteristics as prescribed by the new standard. As a result of the analysis performed, the Partnership concluded that the new revenue recognition standard will have no impact on revenue from NRP's Construction Aggregates or Soda Ash operating segments. However, the Partnership determined that adoption of the new revenue recognition standard will impact certain revenue from NRP's coal royalty leases as further described below. The other revenue streams within the Coal Royalty and Other segment will not be impacted. Historically, NRP has recognized all coal royalty revenue over the lease term based on coal production and minimum payments were deferred until either recoupment occurred or the recoupment period expired. Under the new revenue recognition standard, management has defined NRP's coal royalty lease performance obligation as providing the lessee the right to mine and sell NRP's coal over the lease term. The Partnership then evaluated the likelihood that consideration NRP received from its lessees resulting from coal production would exceed consideration received from minimum payments over the lease term. As a result of this evaluation, revenue recognition from the Partnership's leases will now be based on either production or minimum payments as follows: 1. Production Leases: Leases for which the Partnership expects that consideration from coal production will be greater than consideration from minimums over the lease term. Revenue recognition for these leases will be recognized over time based on coal production and minimum payments will continue to be deferred until recoupment occurs or the recoupment becomes remote. If the Partnership does receive minimum payments from these coal royalty leases, it will begin to evaluate the likelihood of recoupment and recognize deferred revenue prior to expiration of the recoupment period if it concludes that recoupment is remote. 2. Minimum Leases: Leases for which the Partnership expects that consideration from minimums will be greater than consideration from coal production over the lease term. Revenue recognition for these leases will now be recognized straight line over the lease term based on the minimum payment consideration amount. As a result of implementation of the new standard for the Partnership's coal lease contracts, NRP expects to record approximately $80 million to $90 million reduction to deferred revenue and a corresponding increase in retained earnings on January 1, 2018. The Partnership will perform this contract evaluation at the end of each reporting period going forward. Leases . In February 2016, the FASB issued ASU No. 2016-02, Leases, as a new Topic, ASC Topic 842. The new lease guidance supersedes Topic 840. Lessees are to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. This ASU does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. The guidance also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The guidance is effective for annual and interim periods beginning after December 31, 2018. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.

Class A Convertible Preferred U

Class A Convertible Preferred Units and Warrants Class A Convertible Preferred Units and Warrants	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Class A Convertible Preferred Units and Warrants	Class A Convertible Preferred Units and Warrants On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred Units") to certain entities controlled by funds affiliated with The Blackstone Group, L.P. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree") (together the "Preferred Purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000 Preferred Units to the Preferred Purchasers at a price of $1,000 per Preferred Unit (the "Per Unit Purchase Price"), less a 2.5% structuring and origination fee. The Preferred Units entitle the Preferred Purchasers to receive cumulative distributions at a rate of 12% per year, up to one half of which NRP may pay in additional Preferred Units (such additional Preferred Units, the "PIK Units"). The Preferred Units have a perpetual term, unless converted or redeemed as described below. NRP also issued two tranches of warrants (the "Warrants") to purchase common units to the Preferred Purchasers (Warrants to purchase 1.75 million common units with a strike price of $22.81 and Warrants to purchase 2.25 million common units with a strike price of $34.00 ). The Warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the Warrants, NRP may, at its option, elect to settle the Warrants in common units or cash, each on a net basis. After March 2, 2022 and prior to March 2, 2025, the holders of the Preferred Units may elect to convert up to 33% of the outstanding Preferred Units in any 12-month period into common units if the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to date notice is provided is greater than $51.00 . In such case, the number of common units to be issued upon conversion would be equal to the Per Unit Purchase Price plus the value of any accrued and unpaid distributions divided by an amount equal to a 7.5% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Rather than have the Preferred Units convert to common units in accordance with the provisions of this paragraph, NRP would have the option to elect to redeem the Preferred Units proposed to be converted for cash at a price equal to Per Unit Purchase Price plus the value of any accrued and unpaid distributions. On or after March 2, 2025, the holders of the Preferred Units may elect to convert the Preferred Units to common units at a conversion rate equal to the Liquidation Value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. The “Liquidation Value” will be an amount equal to the greater of: (1) (a) the Per Unit Purchase Price multiplied by (i) prior to March 2, 2020, 1.50 , (ii) on or after March 2, 2020 and prior to March 2, 2021, 1.70 and (iii) on or after March 2, 2021, 1.85 , less (b)(i) all Preferred Unit distributions previously made by NRP and (ii) all cash payments previously made in respect of redemption of any PIK Units; and (2) the Per Unit Purchase Price plus the value of all accrued and unpaid distributions. To the extent the holders of the Preferred Units have not elected to convert their Preferred Units before March 2, 2029, NRP has the right to force conversion of the Preferred Units at a price equal to the Liquidation Value divided by an amount equal to a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. In addition, NRP has the ability to redeem at any time (subject to compliance with its debt agreements) all or any portion of the Preferred Units and any outstanding PIK Units for cash. The redemption price for each outstanding PIK Unit is $1,000 plus the value of any accrued and unpaid distributions per PIK Unit. The redemption price for each Preferred Unit is the Liquidation Value divided by the number of outstanding Preferred Units. The Preferred Units are redeemable at the option of the Preferred Purchasers only upon a change in control. The terms of the Preferred Units contain certain restrictions on NRP's ability to pay distributions on its common units. To the extent that either (i) NRP's consolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership Agreement dated March 2, 2017 (the "Restated Partnership Agreement"), is greater than 3.25 x, or (ii) the ratio of NRP's Distributable Cash Flow (as defined in the Restated Partnership Agreement) to cash distributions made or proposed to be made is less than 1.2 x (in each case, with respect to the most recently completed four-quarter period), NRP may not increase the quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding Preferred Units. In addition, if at any time after January 1, 2022, any PIK Units are outstanding, NRP may not make distributions on its common units until it has redeemed all PIK Units for cash. The holders of the Preferred Units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rights with respect to changes of the terms of the Preferred Units. In addition, Blackstone has certain approval rights over certain matters as identified in the Restated Partnership Agreement. GoldenTree also has more limited approval rights that will expand once Blackstone's ownership goes below the Minimum Preferred Unit Threshold (as defined below). These approval rights are not transferrable without NRP's consent. In addition, the approval rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold"). At the closing, pursuant to the Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights, and Blackstone appointed one director and one observer to the Board of Directors of GP Natural Resource Partners LLC. NRP also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with the Preferred Purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the Warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the Preferred Units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of Preferred Units (the "Registration Deadlines"). In addition, the Preferred Unit and Warrant Registration Rights Agreement gives the Preferred Purchasers piggyback registration and demand underwritten offering rights under certain circumstances. The shelf registration statement to register the common units issuable upon exercise of the Warrants became effective on April 20, 2017. If the shelf registration statement to register the common units issuable upon conversion of the Preferred Units is not effective by the applicable Registration Deadline, NRP will be required to pay the Preferred Purchasers liquidated damages in the amounts and upon the term set forth in the Preferred Unit and Warrant Registration Rights Agreement. Accounting for the Preferred Units and Warrants Classification The Preferred Units are accounted for on NRP's consolidated balance sheets as temporary equity due to certain contingent redemption rights that may be exercised at the election of Preferred Purchasers. The Warrants are accounted for on NRP's consolidated balance sheets as equity. Prior to July 1, 2017, the Warrants were previously classified as a liability because of a "down-round" anti-dilution price protection provision that would reduce the Warrant holders' exercise price if NRP were to sell common units at a price less than the current strike price (subject to certain exceptions). The Partnership retrospectively adopted ASU No. 2017-11, Earnings Per Share (Topic 260) in the third quarter of 2017 and reclassified the Warrants on its Consolidated Balance Sheets. Refer to Note 2. Summary of Significant Accounting Policies for more discussion. Initial Measurement The net transaction price as shown below was allocated to the Preferred Units and Warrants based on their relative fair values at inception date. NRP allocated the transaction issuance costs to the Preferred Units and Warrants primarily on a pro-rata basis based on their relative inception date allocated values. The Preferred Units and Warrants were initially recognized as follows: (In thousands) March 2, 2017 Transaction price, gross $ 250,000 Structuring, origination and other fees to Preferred Purchasers (7,900 ) Transaction costs to other third parties (10,697 ) Transaction price, net $ 231,403 Allocation of net transaction price Preferred Units, net $ 164,587 Warrant holders interest, net 66,816 Transaction price, net $ 231,403 Subsequent Measurement Subsequent adjustment of the Preferred Units will not occur until NRP has determined that the conversion or redemption of all or a portion of the Preferred Units is probable of occurring. Once conversion or redemption becomes probable of occurring, the carrying amount of the Preferred Units will be accreted to their redemption value over the period from the date the feature is probable of occurring to the date the Preferred Units can first be converted or redeemed. Subsequent adjustment of the Warrants will not occur until the Warrants are exercised, at which time, NRP may, at its option, elect to settle the Warrants in common units or cash, each on a net basis. The net basis will be equal to the difference between the Partnership's common unit price and the strike price of the Warrant. Once Warrant exercise occurs, the difference between the carrying amount of the Warrants and the net settlement amount will be allocated on a pro-rata basis to the common unitholders and general partner. Certain embedded features within the Preferred Unit and Warrant purchase agreement are accounted for at fair value and are remeasured each quarter. See Note 14. Fair Value Measurements for further information regarding valuation of these embedded derivatives.

Common and Preferred Unit Distr

Common and Preferred Unit Distributions Common and Preferred Unit Distributions	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Common and Preferred Unit Distributions	Common and Preferred Unit Distributions The Partnership makes cash distributions to common unit holders on a quarterly basis, subject to approval by the Board of Directors. The Partnership also makes distributions to the preferred unitholders at a rate of 12% per year, up to one half of which NRP may pay in additional Preferred Units (such additional Preferred Units, the "PIK Units"), subject to approval by the Board of Directors. NRP recognizes both Common and Preferred Unit distributions on the date the distribution is declared. Common Unit Distributions Distributions made on the common units and the general partner's general partner interest are made on a pro-rata basis in accordance with their relative percentage interests in the Partnership. The general partner is entitled to receive 2% of such distributions. The following table shows the distributions paid by the Partnership on its common units and general partner's general partner interest during the years ended December 31, 2017 , 2016 and 2015 : (In thousands, except per unit data) Total Distributions Date Paid Period Covered by Distribution Distribution per Common Unit Common Units GP Interest Total 2017 February 14, 2017 October 1 - December 31, 2016 $ 0.45 $ 5,503 $ 112 $ 5,615 May 12, 2017 January 1 - March 31, 2017 0.45 5,506 113 5,619 August 14, 2017 April 1 - June 30, 2017 0.45 5,504 112 5,616 November 14, 2017 July 1 - September 30, 2017 0.45 5,505 112 5,617 2016 February 12, 2016 October 1 - December 31, 2015 $ 0.45 $ 5,503 $ 113 $ 5,616 May 13, 2016 January 1 - March 31, 2016 0.45 5,503 113 5,616 August 12, 2016 April 1 - June 30, 2016 0.45 5,505 112 5,617 November 14, 2016 July 1 - September 30, 2016 0.45 5,503 113 5,616 2015 February 13, 2015 October 1 - December 31, 2014 $ 3.50 $ 42,804 $ 874 $ 43,678 May 14, 2015 January 1 - March 31, 2015 0.90 11,007 225 11,232 August 14, 2015 April 1 - June 30, 2015 0.90 11,009 223 11,232 November 13, 2015 July 1 - September 30, 2015 0.45 5,504 112 5,616 Preferred Unit Distributions The following table shows the cash and paid-in-kind distributions declared and paid to Preferred Unitholders by the Partnership during the year ended December 31, 2017 : (In thousands, except per unit data) Date Paid Period Covered by Distribution Distribution per Preferred Unit Paid-in-Kind Preferred Units Cash Distributions Total Distribution Declared May 30, 2017 March 2 - March 31, 2017 $ 5.00 1,250 $ 1,250 $ 2,500 August 29, 2017 April 1 - June 30, 2017 $ 15.00 3,769 3,769 7,538 November 29, 2017 July 1 - September 30, 2017 $ 15.00 3,825 3,825 7,650 8,844 $ 8,844 $ 17,688 The following table shows the units outstanding and financial position of the Preferred Units from initial measurement at March 2, 2017 to December 31, 2017: (In thousands) Units outstanding Financial position Balance at December 31, 2016 — $ — Issuance of Preferred Units, net 250,000 164,587 Distribution paid-in-kind 8,844 8,844 Balance at December 31, 2017 258,844 $ 173,431 Income available to common unitholders and the general partner is reduced by Preferred Unit distributions that accumulated during the period. During the year ended December 31, 2017 , NRP reduced net income attributable to common unitholders and the general partner by $25.5 million as a result of accumulated Preferred Unit distributions. Subsequent Event On February 14, 2018, the Partnership paid a distribution of $0.45 per unit to unitholders of record on February 7, 2018. In addition, the Partnership paid a distribution on NRP's 12.0% Class A Convertible Preferred Units with respect to the fourth quarter. The entire $7.8 million distribution on the Preferred Units was paid in cash. Additionally, the Partnership redeemed all of the outstanding PIK Units, which resulted in an $8.8 million cash payment.

Net Income Per Common Unit Net

Net Income Per Common Unit Net Income Per Common Unit (Notes)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Net Income Per Common Unit	Net Income Per Common Unit Basic net income per common unit is computed by dividing net income, after considering income attributable to preferred unitholders and the general partner’s interest, by the weighted average number of common units outstanding. Diluted net income per common unit includes the effect of NRP's Warrants and Preferred Units (see Note 3. Class A Convertible Preferred Units and Warrants ), if the inclusion of these items is dilutive. The dilutive effect of the Warrants is calculated using the treasury stock method, which assumes that the proceeds from the exercise of these instruments are used to purchase common units at the average market price for the period. The calculation of the dilutive effect of the Warrants for the three and twelve months ended December 31, 2017 , did not include the net settlement of Warrants to purchase 2.25 million common units with a strike price of $34.00 because the impact would have been anti-dilutive. The dilutive effect of the Preferred Units is calculated using the if-converted method. Under the if-converted method, the Preferred Units are assumed to be converted at the beginning of the period, and the resulting common units are included in the denominator of the diluted net income per unit calculation for the period being presented. Interest recognized during the period (including the effect of accretion of discounts and amortization of issuance costs, if any), distributions declared in the period and undeclared distributions on the Preferred Units that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. The following table reconciles net income and weighted average units used in computing basic and diluted net income per common unit is as follows (in thousands, except per unit data): Years Ended December 31, (In thousands, except per unit data) 2017 2016 2015 Allocation of net income: Net income (loss) from continuing operations $ 89,208 $ 95,214 $ (260,171 ) Less: income attributable to preferred unitholders 25,453 — — Less: net income (loss) from continuing operations and income attributable to preferred unitholders allocated to the general partner 1,275 1,629 (5,998 ) Net income (loss) from continuing operations attributable to common unitholders $ 62,480 $ 93,585 $ (254,173 ) Net income (loss) from discontinued operations $ (541 ) $ 1,678 $ (311,549 ) Less: net income (loss) from discontinued operations attributable to the general partner (11 ) 34 (6,230 ) Net income (loss) from discontinued operations attributable to common unitholders $ (530 ) $ 1,644 $ (305,319 ) Net income (loss) $ 88,667 $ 96,892 $ (571,720 ) Less: income attributable to preferred unitholders 25,453 — — Less: net income (loss) and income attributable to preferred unitholders allocated to the general partner 1,264 1,663 (12,228 ) Net income (loss) attributable to common unitholders $ 61,950 $ 95,229 $ (559,492 ) Basic Income (Loss) per Unit: Weighted average common units—basic 12,232 12,232 12,232 Basic net income (loss) from continuing operations per common unit $ 5.11 $ 7.65 $ (20.78 ) Basic net income (loss) from discontinued operations per common unit $ (0.04 ) $ 0.13 $ (24.97 ) Basic net income (loss) per common unit $ 5.06 $ 7.78 $ (45.75 ) Diluted Income (Loss) per Unit: Weighted average common units—basic 12,232 12,232 12,232 Plus: dilutive effect of Warrants 300 — — Plus: dilutive effect of Preferred Units 9,418 — — Weighted average common units—diluted 21,950 12,232 12,232 Net income (loss) from continuing operations $ 89,208 $ 95,214 $ (260,171 ) Less: net income (loss) from continuing operations allocated to the general partner 1,784 1,629 (5,998 ) Diluted net income (loss) from continuing operations attributable to common unitholders $ 87,424 $ 93,585 $ (254,173 ) Diluted net income (loss) from discontinued operations attributable to common unitholders $ (530 ) $ 1,644 $ (305,319 ) Net income (loss) $ 88,667 $ 96,892 $ (571,720 ) Less: net income (loss) allocated to the general partner 1,773 1,663 (12,228 ) Diluted net income (loss) attributable to common unitholders $ 86,894 $ 95,229 $ (559,492 ) Diluted net income (loss) from continuing operations per common unit $ 3.98 $ 7.65 $ (20.78 ) Diluted net income (loss) from discontinued operations per common unit $ (0.02 ) $ 0.13 $ (24.97 ) Diluted net income (loss) per common unit $ 3.96 $ 7.78 $ (45.75 )

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Segment Information The Partnership's segments are strategic business units that offer products and services to different customers in different geographies within the U.S. and that are managed accordingly. NRP has the following three operating segments: Coal Royalty and Other —consists primarily of coal royalty and coal-related transportation and processing assets. Other assets include aggregates royalty, industrial mineral royalty, oil and gas royalty and timber. The Partnership's coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. The Partnership's aggregates and industrial minerals properties are located in a number of states across the United States. The Partnership's oil and gas royalty assets are primarily located in Louisiana. Soda Ash —consists of the Partnership's 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, 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. Construction Aggregates —consists of the Partnership's construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. Construction Aggregates operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. Direct segment costs and certain costs incurred at the corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments. These allocated costs include costs of: taxes, legal, information technology and shared facilities services and are included in Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income (Loss). Intersegment sales are at prices that approximate market. Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include interest and financing, corporate headquarters and overhead, centralized treasury and accounting and other corporate-level activity not specifically allocated to a segment and are included in General and administrative expenses and General and administrative expenses—affiliates on the Consolidated Statements of Comprehensive Income (Loss). Operating Segments (In thousands) Coal Royalty and Other Soda Ash Construction Aggregates Corporate and Financing Total For the Year Ended December 31, 2017 Revenues (including affiliates) $ 202,323 $ 40,457 $ 131,381 $ — $ 374,161 Intersegment revenues (expenses) 295 — (295 ) — — Gain on asset sales, net 3,545 — 311 — 3,856 Operating and maintenance expenses (including affiliates) 24,883 — 111,633 — 136,516 General and administrative (including affiliates) — — — 18,502 18,502 Depreciation, depletion and amortization (including affiliates) 23,414 — 12,579 — 35,993 Asset impairment 2,967 — 64 — 3,031 Other expense, net — — 693 94,074 94,767 Net income (loss) from continuing operations 154,899 40,457 6,428 (112,576 ) 89,208 Net income from discontinued operations — — — — (541 ) Capital expenditures — — 7,595 — 7,595 As of December 31, 2017 Total assets of continuing operations $ 945,237 $ 245,433 $ 191,374 $ 6,129 $ 1,388,173 Total assets of discontinued operations — — — — 991 Trade accounts receivable (including affiliates) 16,355 — 22,976 — 39,331 Property taxes and other receivable (including affiliates) 7,856 — — — 7,856 Operating Segments (In thousands) Coal Royalty and Other Soda Ash Construction Aggregates Corporate and Financing Total For the Year Ended December 31, 2016 Revenues (including affiliates) $ 210,115 $ 40,061 $ 120,802 $ — $ 370,978 Intersegment revenues (expenses) 150 — (150 ) — — Gain on asset sales, net 29,068 — 13 — 29,081 Operating and maintenance expenses 29,890 — 100,656 — 130,546 General and administrative (including affiliates) — — — 20,570 20,570 Depreciation, depletion and amortization (including affiliates) 31,766 — 14,506 — 46,272 Asset impairment 15,861 — 1,065 — 16,926 Other expense, net — — — 90,531 90,531 Net income (loss) from continuing operations 161,816 40,061 4,438 (111,101 ) 95,214 Net income from discontinued operations — — — — 1,678 Capital expenditures 5 — 5,380 — 5,385 As of December 31, 2016 Total assets of continuing operations $ 990,172 $ 255,901 $ 190,615 $ 10,970 $ 1,447,658 Total assets of discontinued operations — — — — 991 Trade accounts receivable (including affiliates) 18,791 — 19,168 — 37,959 Property taxes and other receivable (including affiliates) 11,661 — 208 32 11,901 For the Year Ended December 31, 2015 Revenues (including affiliates) $ 243,781 $ 49,918 $ 139,049 $ — $ 432,748 Intersegment revenues (expenses) 21 — (21 ) — — Gain (loss) on asset sales, net 6,936 — (36 ) — 6,900 Operating and maintenance expenses (including affiliates) 35,321 — 116,945 — 152,266 General and administrative (including affiliates) — — — 12,348 12,348 Depreciation, depletion and amortization (including affiliates) 45,338 — 15,578 — 60,916 Asset impairment 378,327 — 6,218 — 384,545 Other expense, net — — — 89,744 89,744 Net income (loss) from continuing operations (208,248 ) 49,918 251 (102,092 ) (260,171 ) Net loss from discontinued operations — — — — (311,549 ) Capital expenditures 428 — 14,039 — 14,467

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations In July 2016, NRP Oil and Gas sold its non-operated oil and gas working interest assets for $116.1 million in gross sales proceeds. The sale had an effective date of April 1, 2016. The Partnership's exit from its non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on its coal royalty, soda ash and construction aggregates business segments. As a result, the Partnership classified the operating results, cash flows and assets and liabilities of its non-operated oil and gas working interest assets as discontinued operations in its Consolidated Balance Sheets, Consolidated Statements of Comprehensive Income and Consolidated Statements of Cash Flows for all periods presented. The Partnership transitioned the remaining investments in royalty interests in oil and natural gas properties into the Coal Royalty and Other operating segment during the third quarter of 2016. The following table presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations in the Consolidated Balance Sheets: December 31, (In thousands) 2017 2016 ASSETS Current assets: Accounts receivable, net (including affiliates) (1) $ 991 $ 991 Total assets of discontinued operations $ 991 $ 991 LIABILITIES Current liabilities: Other (including affiliates) (1) $ 401 $ 353 Total liabilities of discontinued operations $ 401 $ 353 (1) See Note 15. Related Party Transactions for additional information on the Partnership's related party assets and liabilities. The following table presents summarized financial results of the Partnership's discontinued operations in the Consolidated Statements of Comprehensive Income (Loss): For the Years Ended December 31, (In thousands) 2017 2016 2015 Revenues and other income: Oil and gas $ 38 $ 16,486 $ 48,750 Gain on asset sales (289 ) 8,274 451 Total revenues and other income $ (251 ) $ 24,760 $ 49,201 Operating expenses: Operating and maintenance expenses (including affiliates) $ 290 $ 11,503 $ 19,724 Depreciation, depletion and amortization — 7,527 39,912 Asset impairments — 564 297,049 Total operating expenses $ 290 $ 19,594 $ 356,685 Interest expense — (3,488 ) (4,065 ) Income (loss) from discontinued operations $ (541 ) $ 1,678 $ (311,549 ) The following table presents supplemental cash flow information of the Partnership's discontinued operations: Years Ended December 31, (In thousands) 2017 2016 2015 Cash paid for interest $ — $ 1,906 $ 2,755 Plant, equipment and mineral rights funded with accounts payable or accrued liabilities — — 1,645 Capital expenditures related to the Partnership's discontinued operations were $1.4 million and $30.6 million during the years months ended December 31, 2016 and 2015, respectively.

Equity Investment

Equity Investment	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Investment	Equity Investment The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Ciner Wyoming distributed $49.0 million , $46.6 million and $46.8 million to the Partnership in the year ended December 31, 2017 , 2016 and 2015 , respectively. The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was $145.6 million and $150.0 million as of December 31, 2017 and 2016 , respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years . The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method. The Partnership's equity in the earnings of Ciner Wyoming is summarized as follows: For the Year Ended December 31, (In thousands) 2017 2016 2015 Income allocation to NRP’s equity interests (1) $ 44,846 $ 44,882 $ 54,709 Amortization of basis difference (4,389 ) (4,821 ) (4,791 ) Equity in earnings of unconsolidated investment $ 40,457 $ 40,061 $ 49,918 (1) Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $0.7 million , $0.9 million and $0.7 million for the year ended December 31, 2017, 2016 and 2015, respectively. The results of Ciner Wyoming’s operations are summarized as follows: For the Year Ended December 31, (In thousands) 2017 2016 2015 Sales $ 497,340 $ 475,187 $ 486,393 Gross profit 114,202 114,232 131,493 Net Income 91,523 91,596 111,650 The financial position of Ciner Wyoming is summarized as follows: December 31, (In thousands) 2017 2016 Current assets $ 180,433 $ 134,616 Noncurrent assets 228,002 235,427 Current liabilities 56,219 55,396 Noncurrent liabilities 148,401 98,425 The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming required the Partnership to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement were met by Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2016, 2015 and 2014, the Partnership paid contingent consideration of $7.2 million , $3.8 million and $0.5 million , respectively, in contingent consideration to Anadarko for performance criteria met by Ciner Wyoming in 2015, 2014 and 2013, respectively.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventory	Inventory The components of inventories are as follows: December 31, (In thousands) 2017 2016 Aggregates $ 6,209 $ 6,037 Supplies and parts 1,344 856 Total inventory $ 7,553 $ 6,893

Plant and Equipment

Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Plant and Equipment	Plant and Equipment The Partnership’s plant and equipment consist of the following: December 31, (In thousands) 2017 2016 Plant and equipment at cost $ 84,173 $ 79,171 Construction in process 803 557 Less accumulated depreciation (38,806 ) (30,285 ) Total plant and equipment, net $ 46,170 $ 49,443 Depreciation expense related to the Partnership's plant and equipment totaled $10.3 million , $12.4 million and $15.9 million for the year ended December 31, 2017 , 2016 and 2015 , respectively. Impairment expense related to the Partnership's plant and equipment totaled $0.1 million , $3.1 million , and $7.7 million and are included in Asset impairments in the Consolidated Statements of Comprehensive Income (Loss) for the year ending December 31, 2017 , 2016 and 2015 , respectively. During 2016, the Partnership recorded a $2.0 million impairment expense in its Coal Royalty and Other segment primarily related to a coal preparation plant and a $1.1 million impairment expense in its Construction Aggregates segment primarily related to equipment write-downs. During 2015, the Partnership recorded $7.0 million in impairment expense in its Coal Royalty and Other segment related to a coal preparation plant, transportation and processing assets and obsolete equipment. Additionally, the Partnership recorded a $0.7 million impairment expense related to obsolete plant and equipment in its Construction Aggregates segment.

Mineral Rights

Mineral Rights	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Mineral Rights	Mineral Rights The Partnership’s mineral rights consist of the following: December 31, 2017 (In thousands) Carrying Value Accumulated Depletion Net Book Value Coal properties $ 1,170,104 $ (436,964 ) $ 733,140 Aggregates properties 150,642 (16,836 ) 133,806 Oil and gas royalty properties 12,395 (7,158 ) 5,237 Other 13,168 (1,466 ) 11,702 Total mineral rights, net $ 1,346,309 $ (462,424 ) $ 883,885 December 31, 2016 (In thousands) Carrying Value Accumulated Depletion Net Book Value Coal properties $ 1,170,904 $ (420,032 ) $ 750,872 Aggregates properties 176,774 (39,056 ) 137,718 Oil and gas royalty properties 12,395 (6,289 ) 6,106 Other 14,946 (1,450 ) 13,496 Total mineral rights, net $ 1,375,019 $ (466,827 ) $ 908,192 Depletion expense related to the Partnership’s mineral rights totaled $22.2 million , $29.8 million and $40.4 million for the year ended December 31, 2017 , 2016 and 2015 , respectively. Asset Divestitures During the year ended December 31, 2017, the Partnership sold mineral reserves in its Coal Royalty and Other segment in multiple transactions for cumulative $1.0 million of gross sales proceeds and recorded a $3.5 million gain on asset sales included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income (Loss). During the year ended December 31, 2016, the Partnership completed the sale of the following assets: 1) Oil and gas royalty and overriding royalty interests in the Coal Royalty and Other segment in several producing properties located in the Appalachian Basin for $36.4 million gross sales proceeds. The effective date of the sale was January 1, 2016, and the Partnership recorded an $18.6 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income (Loss). 2) Aggregates reserves and related royalty rights in the Coal Royalty and Other segment at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds. The effective date of the sale was February 1, 2016, and the Partnership recorded a $1.5 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income (Loss). In addition to the two asset sales described above, during the year ended December 31, 2016, the Partnership sold mineral reserves within its Coal Royalty and Other segment in multiple sale transactions for cumulative $17.3 million of gross sales proceeds and recorded $8.6 million of cumulative gain from these sale transactions that are included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income (Loss). These amounts primarily relate to eminent domain transactions with governmental agencies and the sale of additional oil and gas royalty interests. During the year ended December 31, 2015, the Partnership sold mineral reserves in its Coal Royalty and Other segment in multiple transactions for cumulative $3.5 million of gross sales proceeds and recorded a $3.3 million gain on asset sales included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income (Loss). Impairment of Mineral Rights For the evaluation of the Partnership's long-lived assets for possible impairment, inputs used by management for fair value measurements include significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement for these types of assets. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require that a separate impairment evaluation be completed on a significant property. During the years ended December 31, 2017 , 2016 and 2015 , the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense as follows: For the years ended December 31, (In thousands) 2017 2016 2015 Coal properties (1) $ 595 $ 12,088 $ 257,468 Oil and gas properties (2) — 36 70,527 Aggregates and timber royalty properties (3) 2,372 1,677 43,402 Total $ 2,967 $ 13,801 $ 371,397 (1) The Partnership recorded $0.6 million of coal property impairments during the year ended December 31, 2017 . The Partnership recorded $12.1 million of coal property impairments during the year ended December 31, 2016, primarily as a result of lease surrender and termination. The Partnership recorded $3.8 million of coal property impairment during the three months ended September 30, 2016 and the fair value of the impaired asset was reduced to $4.0 million at September 30, 2016. The Partnership recorded $8.2 million of coal property impairment during the three months ended December 31, 2016 and the fair value of the impaired asset was reduced to $0.0 million at December 31, 2016. Total coal property impairment expense for the year ended December 31, 2015 was $257.5 million . The Partnership recorded $1.5 million of coal property impairment during the three months ended June 30, 2015 and the fair value measurement of these impaired assets was reduced to $0.0 million at June 30, 2015. The Partnership recorded $247.8 million of coal property impairment during the three months ended September 30, 2015 and the fair value of these impaired assets was reduced to $28.4 million at September 30, 2015. The Partnership recorded the remaining $8.2 million of coal property impairment during the three months ended December 31, 2015 and the fair value of these impaired assets was reduced to $0.4 million at December 31, 2015. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. (2) The Partnership recorded $36 thousand of oil and gas royalty asset impairment during the year ended December 31, 2016. The total oil and gas royalty impairment for the year ended December 31, 2015 was $70.5 million . The Partnership recorded this impairment during the three months ended September 30, 2015. The fair value measurement of these impaired assets was reduced to $13.0 million at September 30, 2015. This impairment primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on its acreage. NRP compared net capitalized costs of its oil and gas royalty properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials. (3) The Partnership recorded $2.4 million of aggregates and timber royalty property impairments during the year ended December 31, 2017. The Partnership recorded $1.7 million of aggregates royalty property impairments during the year ended December 31, 2016. Total aggregates property impairment expense for the year ended December 31, 2015 was $43.4 million . This impairment was recorded during the three months ended September 30, 2015. The fair value measurement of these impaired assets was reduced to $13.1 million at September 30, 2015. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows.

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Including Affiliate)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets (Including Affiliate)	Goodwill and Intangible Assets (Including Affiliate) The Partnership's intangible assets (including affiliate) primarily consists of above market coal transportation contracts with subsidiaries of Foresight Energy in which the Partnership receives throughput fees for the handling and transportation of coal. As of May 9, 2017, Foresight Energy is no longer deemed to be an affiliate of the Partnership. Refer to Note 15. Related Party Transactions for additional details. The Partnership's intangible assets include permits, aggregates-related trade names and other agreements. The Partnership's intangible assets (including affiliate) included in the Partnership's Consolidated Balance Sheets are as follows: December 31, (In thousands) 2017 2016 Intangible assets (including affiliate) $ 86,336 $ 86,336 Less accumulated amortization (including affiliate) (36,782 ) (33,289 ) Total intangible assets, net (including affiliate) $ 49,554 $ 53,047 Amortization expense related to the Partnership's intangible assets—affiliate totaled $1.0 million , $3.2 million and $3.6 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Amortization expense related to the Partnership's intangible assets totaled $2.5 million , $0.8 million and $1.0 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The estimates of amortization expense for the years ended December 31, as indicated below, are based on current mining plans and are subject to revision as those plans change in future periods. (In thousands) Estimated Amortization Expense 2018 $ 3,123 2019 2,921 2020 3,492 2021 3,351 2022 3,351 The weighted average remaining amortization period for contract intangibles and other intangibles was 25 years and 14 years , respectively. During 2014, $52.0 million of goodwill was added relating to the Construction Aggregates acquisition. This amount represented the preliminary residual value. During 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for Construction Aggregates’ property, plant and equipment, right to mine assets and asset retirement obligations that existed as of the acquisition date. These adjustments decreased goodwill by $46.5 million and resulted in an acquisition date goodwill of $5.5 million . During 2015, the Partnership evaluated goodwill for impairment and compared the estimated fair value of the Construction Aggregates reporting unit to its carrying amount. The carrying amount exceeded fair value and the Partnership recorded a $5.5 million goodwill impairment expense include in Asset impairments on the Partnership's Consolidated Statements of Comprehensive Income (Loss). The lower fair value was primarily a result of the deterioration in certain regional markets in which Construction Aggregates operates causing a decline in future performance levels compared to levels estimated during the purchase price allocation process. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. These estimates were based on current conditions and historical experience applied to develop projections of future operating performance.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Debt The Partnership's debt consisted of the following: December 31, (In thousands) 2017 2016 NRP LP debt: 10.500% senior notes, with semi-annual interest payments in March and September, due March 2022, $241 million issued at par and $105 million issued at 98.75% $ 345,638 $ — 9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% — 425,000 Opco debt: Revolving credit facility 60,000 210,000 Senior notes 4.91% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018 4,586 9,187 8.38% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019 42,670 64,029 5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020 22,946 30,633 5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 16,115 18,825 4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 44,693 52,204 5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 104,520 119,524 8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 31,733 36,272 5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 120,547 134,035 5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 34,396 38,262 5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021 — 961 Total debt at face value $ 827,844 $ 1,138,932 Net unamortized debt discount (1,661 ) (1,322 ) Net unamortized debt issuance costs (16,835 ) (7,339 ) Total debt, net $ 809,348 $ 1,130,271 Less: current portion of long-term debt 79,740 140,037 Total long-term debt, net $ 729,608 $ 990,234 NRP LP Debt NRP 2018 Senior Notes In March 2017, the Partnership and NRP Finance exchanged $241 million aggregate principal amount of the 2018 Senior Notes for $241 million aggregate principal amount of a new series of 10.500% Senior Notes due 2022 (the “2022 Senior Notes”). In April 2017, the Partnership and NRP Finance redeemed $90 million in aggregate principal amount of the 2018 Senior Notes at a redemption price of 104.563% , and paid all accrued and unpaid interest thereon. In addition, pursuant to the 2022 Indenture (as defined below), the Partnership and NRP Finance redeemed the remaining outstanding $94.4 million of 2018 Senior Notes at par (and paid accrued and unpaid interest thereon) on October 2, 2017 using a combination of cash on hand and borrowings from the Opco Credit Facility. 2022 Senior Notes In March 2017, NRP and NRP Finance issued $346 million aggregate principal amount of 2022 Senior Notes to several holders of their 2018 Senior Notes. Of the $346 million of 2022 Senior Notes issued, $241 million in aggregate principal amount were issued in exchange for $241 million in aggregate principal amount of 2018 Senior Notes, and $105 million of the 2022 Senior Notes were issued to the holders for cash. The 2022 Senior Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 Indenture"), bear interest at 10.500% per year, are payable semi-annually on March 15 and September 15, beginning September 15, 2017, and mature on March 15, 2022. The $105.0 million in 2022 Senior Notes purchased for cash were issued at a price of 98.75% (original issue discount of 1.25% ), and each holder exchanging 2018 Senior Notes received a fee of 5.813% of the aggregate principal amount of all 2018 Senior Notes tendered for exchange by such holder, as well as all accrued and unpaid interest thereon. The 5.813% fee included a 4.563% call premium on the early repayment of the 2018 Senior Notes and a 1.25% fee on the exchange of the 2018 Notes for 2022 Senior Notes. This fee is accounted for as a debt issue cost, capitalized and shown net of the debt liability on our consolidated balance sheets. NRP and NRP Finance have the option to redeem the 2022 Senior Notes, in whole or in part, at any time on or after March 15, 2019, at the redemption prices (expressed as percentages of principal amount) of 105.25% for the 12-month period beginning March 15, 2019, 102.625% for the 12-month period beginning March 15, 2020, and thereafter at 100.000% , together, in each case, with any accrued and unpaid interest to the date of redemption. Furthermore, before March 15, 2019, NRP may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes with the net proceeds of certain public or private equity offerings at a redemption price of 110.500% of the principal amount of 2022 Senior Notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Senior Notes issued under the 2022 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the 2022 Indenture, the holders of the 2022 Senior Notes may require the Partnership to purchase their 2022 Senior Notes at a purchase price equal to 101% of the principal amount of the 2022 Senior Notes, plus accrued and unpaid interest, if any. The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing the 2018 Senior Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under the debt incurrence covenant, NRP's non-guarantor restricted subsidiaries will not be permitted to incur additional indebtedness unless their consolidated leverage ratio is less than 3.00 x (measured on a pro forma basis and assuming that the greater of (i) $150.0 million of debt (or, if less, at NRP's election, the amount of total lending commitments under any revolving credit facility) and (ii) the actual amount of debt outstanding is outstanding under any revolving credit facility); provided, however, that such non-guarantor restricted subsidiaries will be permitted to make up to $150 million in borrowings under a revolving credit facility (which amount will be reduced on a dollar-for-dollar basis to the extent NRP has made the election described in clause (i) above). Under the restricted payments covenant, NRP will not be able to increase the quarterly distribution on its common units or elect to pay more than 50% of the distributions required to be made on the Preferred Units in cash, unless, in each case, its consolidated leverage ratio is less than 4.00 x. The 2022 Indenture also contains restrictions on NRP's ability to redeem the Preferred Units. The 2022 Senior Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Senior Notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance and senior in right of payment to any of NRP's subordinated debt. The 2022 Senior Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiaries guarantee the 2022 Senior Notes. As of December 31, 2017 and December 31, 2016, NRP and NRP Finance were in compliance with the terms of its debt agreements. Opco Debt All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of December 31, 2017 and 2016, Opco was in compliance with the terms of the financial covenants contained in its debt agreements. Opco Credit Facility Opco’s Third Amended and Restated Credit Agreement, as amended (the "Opco Credit Facility"), matures on April 30, 2020. Commitments under the Opco Credit Facility were reduced to $150 million at December 31, 2017 and will be further reduced to $100 million at December 31, 2018 through maturity in April 2020. Indebtedness under the Opco Credit Facility bears interest, at Opco's option, at: • 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 2.50% to 3.50% ; or • a rate equal to LIBOR plus an applicable margin ranging from 3.50% to 4.50% . The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for the years ended December 31, 2017 and 2016 were 5.32% and 4.46% , respectively. Debt issue cost related to the OpCo credit facility were $4.6 million and $4.0 million at December 31, 2017 and December 31, 2016, respectively and have been capitalized and included in Other assets on the Partnership's Consolidated Balance Sheets. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty. As of December 31, 2017 , Opco had $60.0 million of indebtedness outstanding and $90.0 million in borrowing capacity under our Opco Credit Facility. The Opco Credit Facility contains financial covenants requiring Opco to maintain: • a leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 4.0 x; provided, however, that if NRP increases its quarterly distribution to its common unitholders above $0.45 per common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from 4.0 x to 3.0 x; and • a fixed charge coverage ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0. The Opco Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of liquidity. In addition, Opco is required to use 75% of the net cash proceeds of certain non-ordinary course asset sales to repay the Opco Credit Facility (without any corresponding commitment reduction) and use the remaining 25% of the net cash proceeds to offer to repay its senior notes on a pro-rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes. The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $649.7 million and $673.0 million classified as Land, Plant and equipment and Mineral rights on the Partnership’s Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of Construction Aggregates’ construction aggregates mining operations, and (5) certain of Opco’s coal-related infrastructure assets. Opco Senior Notes Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of December 31, 2017 and 2016, the Opco Senior Notes had cumulative principal balances of $422.2 million and $503.0 million , respectively. Opco made mandatory principal payments on the Opco Senior Notes of $80.8 million $82.9 million and $80.8 million for the years ended December 31, 2017 , 2016 and 2015, respectively. The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to: • maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters; • not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and • maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0. In addition, the Note Purchase Agreements include a covenant that provides that, in the event NRP Operating or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the Note Purchase Agreements and the holders of the Notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement. The 8.38% and 8.92% Opco Senior Notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Note Purchase Agreements) 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. Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through December 31, 2017 . In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepayment offers on the Opco Senior Notes as follows: • until the earlier of the time that (1) Opco has sold $300 million of assets and (2) June 30, 2020, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using 25% of the net cash proceeds from certain asset sales; and • after the earlier to occur of the dates above, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid. The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes. Consolidated Principal Payments The consolidated principal payments due are set forth below: NRP LP Opco (In thousands) Senior Notes (1) Senior Notes Credit Facility Total 2018 $ — $ 80,385 $ — $ 80,385 2019 — 75,799 — 75,799 2020 — 54,464 60,000 114,464 2021 — 46,815 — 46,815 2022 345,638 46,815 — 392,453 Thereafter — 117,928 — 117,928 $ 345,638 $ 422,206 $ 60,000 $ 827,844 (1) The 10.500% senior notes due 2022 were issued at a discount and were carried at $344.0 million as of December 31, 2017.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Fair Value of Financial Instruments The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, contracts receivable, accounts payable, debt, Preferred Units and warrants. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. There were no transfers between Level 1, Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 2017 or 2016 . The Partnership uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the estimated amount the Partnership would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Partnership's default or repayment risk. The following table shows the carrying amount and estimated fair value of the Partnership's debt and contracts receivable (including affiliates): December 31, 2017 December 31, 2016 (In thousands) Carrying Value Estimated Carrying Estimated Debt NRP 2018 Senior Notes (1) $ — $ — $ 420,097 $ 412,250 NRP 2022 Senior Notes (1) 330,404 366,376 — — Opco Senior Notes and utility local improvement obligation (2) 418,944 447,538 500,174 488,814 Opco Revolving Credit Facility (3) 60,000 60,000 210,000 210,000 Assets: Contracts receivable (including affiliates), current and long-term (4) $ 43,826 $ 30,517 $ 46,742 $ 32,554 (1) The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period end. (2) Due to no observable quoted prices on these instruments, the Level 3 fair value is estimated by management using quotations obtained for the NRP Senior Notes on the closing trading prices near period end. (3) The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. (4) The Level 3 fair value is determined based on the present value of future cash flow projections related to the underlying assets. NRP has embedded derivatives in the Preferred Units related to certain conversion options, redemption features and the change of control provision that are accounted for separately from the Preferred Units as assets and liabilities at fair value in NRP's consolidated balance sheets. Level 3 valuation of the embedded derivatives are based on numerous factors including the likelihood of the event occurring. The embedded derivatives are revalued at each reporting period, and changes in their fair value would be recorded in Other income (expense) in NRP's Consolidated Statements of Comprehensive Income (Loss). The embedded derivatives had zero value at inception and as of December 31, 2017 . Fair Value of Non-Financial Assets The Partnership discloses or recognizes its non-financial assets, such as impairments of coal and aggregate properties and other assets, at fair value on a nonrecurring basis. Refer to Note 10. Plant and Equipment and Note 11. Mineral Rights for additional disclosures related to the fair value associated with the impaired assets.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Cline Affiliates and Foresight Energy Mr. Chris Cline, both individually and through another affiliate, Adena Minerals, LLC ("Adena"), owned a 31% interest in NRP's general partner, as well as approximately 0.5 million of NRP's common units through May 9, 2017. On May 9, 2017, Adena sold its 31% limited partner interest in NRP (GP) LP (the Partnership’s general partner) (“NRP GP”) to Great Northern Properties Limited Partnership (“GNPLP”) and Western Pocahontas Properties Limited Partnership ("WPPLP") (the “Adena Sale”). GNPLP and WPPLP are companies controlled by Corbin J. Robertson, the Chairman and Chief Executive Officer of GP Natural Resource Partners LLC (the general partner of NRP GP) (“GP LLC”). Upon closing of this transaction, NRP no longer considers the various companies affiliated with Chris Cline, including Foresight Energy to be affiliates of NRP. As a result, all transactions (including revenues, expenses and cash flows) after May 9, 2017, with the various companies affiliated with Chris Cline, including Foresight Energy, are considered to be third party transactions. Various subsidiaries of Foresight Energy lease coal reserves from the Partnership, and the Partnership also leases coal transportation assets to them for a fee. Revenues related to these transactions with Foresight Energy are included in the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows: For the Years Ended December 31, (In thousands) 2017 2016 2015 Coal royalty and other revenue $ 43,273 $ — $ — Coal royalty and other — affiliates revenue 27,216 63,355 86,614 Total $ 70,489 $ 63,355 $ 86,614 During the year ended December 31, 2015, the Partnership recognized a gain of $9.3 million on a reserve swap at Foresight Energy's Williamson mine. The gain is included in Coal royalty and other—affiliates revenues on the Consolidated Statements of Comprehensive Income (Loss). The Level 3 fair value of the reserves was estimated using a discounted cash flow model. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates. In addition, NRP owns and leases a rail load out facility and owns a contractual overriding royalty interest at Foresight Energy's Sugar Camp mine. NRP's rail load out lease with a subsidiary of Foresight Energy is accounted for as a direct financing lease. Minimum lease payments are $5.0 million per year for the next five years and represent a $1.25 million per quarter in deficiency payment. NRP's contractual overriding royalty interest from a subsidiary of Foresight Energy provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty is accounted for as a financing arrangement. Revenues from these transactions are included in Coal royalty and other revenues, including affiliates, in the table above. Lastly, NRP owns rail load out transportation assets and subcontracts out the operating responsibilities to a subsidiary of Foresight Energy at Foresight's Williamson mine. Expenses related to these transactions with Foresight Energy are included in the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows: For the Years Ended December 31, (In thousands) 2017 2016 2015 Operating and maintenance expense $ 1,066 $ — $ — Operating and maintenance expense—affiliates, net 452 1,347 1,413 Total $ 1,518 $ 1,347 $ 1,413 The following table shows certain amounts related to NRP's Sugar Camp rail load out facility direct financing lease and amounts of all other transactions with subsidiaries of Foresight Energy reflected on NRP's Consolidated Balance Sheets: December 31, (In thousands) 2017 2016 Sugar Camp rail load out direct financing lease amounts Projected remaining payments $ 71,452 $ 76,424 Unearned Income 28,366 31,803 ASSETS Accounts receivable $ 6,127 $ — Accounts receivable—affiliates, net — 6,496 Long-term contracts receivable 40,776 — Long-term contracts receivable—affiliates — 43,785 LIABILITIES Deferred revenue $ 53,778 — Deferred revenue—affiliates — $ 71,632 Reimbursements to Affiliates of our General Partner The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and WPPLP, affiliates of the Partnership, provide their services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. These QMC and WPPLP employee management service costs and non-cash equity compensation expenses are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income (Loss). NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain rent, legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by or on behalf of the Partnership’s general partner and its affiliates and are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income (Loss). The Partnership had Accounts payable—affiliates to QMC of $0.4 million on its Consolidated Balance Sheets at both December 31, 2017 and 2016. Included in Current liabilities of discontinued operations on the Partnership's Consolidated Balance Sheets is less than $0.1 million in accounts payable due to QMC at both December 31, 2017 and 2016. The Partnership had Accounts payable—affiliates to WPPLP of $0.1 million and $0.6 million on its Consolidated Balance Sheets at December 31, 2017 and 2016 , respectively. Direct general and administrative expenses charged to the Partnership by WPPLP and QMC are as follows: For the Years Ended December 31, (In thousands) 2017 2016 2015 Operating and maintenance expenses—affiliates, net $ 7,606 $ 9,891 $ 10,063 General and administrative—affiliates $ 4,989 $ 3,591 $ 5,312 Included in Income (loss) from discontinued operations on the Partnership's Consolidated Statements of Income (Loss) are $1.3 million and $0.7 million of operating and maintenance expenses charged by QMC for the year ended December 31, 2016 and 2015, respectively. Quintana Capital Group GP, Ltd. Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in the Partnership's conflicts policy. At December 31, 2017 , a fund controlled by Quintana Capital owned a substantial interest in Corsa Coal Corp. ("Corsa"), a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, was Chairman of the Board of Corsa through May 10, 2017. Coal-related revenues from Corsa totaled $1.3 million , $2.2 million and $3.1 million for the years ended December 31, 2017 , 2016 and 2015 , respectively and are included in Coal royalty and other—affiliates revenue in the Partnership's Statements of Comprehensive Income (Loss). The Partnership had Accounts receivable—affiliates totaling $0.2 million from Corsa at both December 31, 2017 and 2016 on the Consolidated Balance Sheets. WPPLP Production Royalty and Overriding Royalty During the year ended December 31, 2017 , 2016 and 2015 , the Partnership recorded $1.5 million , $0.7 million and $0.4 million in Operating and maintenance expenses—affiliates, respectively, on the Statements of Comprehensive Income (Loss) related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007. The Partnership had Other assets—affiliate from WPPLP of $0.2 million and $1.0 million at December 31, 2017 and December 31, 2016 , respectively on the Consolidated Balance Sheets related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine. Quinwood Coal Company Royalty In May 2017, a subsidiary of Alpha Natural Resources assigned two coal leases with the Partnership to Quinwood Coal Partners LP ("Quinwood"), an entity controlled by Corbin J. Robertson III. In connection with this lease assignment, Quinwood forfeited the historical recoupable balance related to this property. As a result, NRP recognized $0.9 million of deferred minimum payments received in prior periods from the subsidiary of Alpha as Coal royalty and other—affiliates revenue on the Statements of Comprehensive Income (Loss) during the year ended December 31, 2017 . There were no deferred minimum payments received in prior periods from the subsidiary of Alpha recognized as Coal royalty and other—affiliates revenue on the Statements of Comprehensive Income (Loss) during the year ended December 31, 2017 .

Major Customers

Major Customers	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Major Customers	Major Customers Revenues from customers that exceeded 10 percent of total revenues and other income for any of the periods presented below are as follows: For the Years Ended December 31, 2017 2016 2015 (In thousands) Revenues Percent Revenues Percent Revenues Percent Foresight Energy $ 70,489 18.6 % $ 63,355 15.8 % $ 86,614 19.7 % Revenues from Foresight Energy are included within the Partnership's Coal Royalty and Other segment.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Legal NRP 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. NRP is also currently involved in the legal proceedings described below. Anadarko Contingent Consideration Payment Dispute In January 2013, NRP acquired a non-controlling 48.51% general partner interest in OCI Wyoming, L.P. ("OCI LP") and all of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko"). The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical Corporation. The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by the NRP if certain performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015. For those years, NRP paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment obligations. In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, NRP exchanged the stock of OCI Co for a limited partner interest in OCI LP. Following the reorganization, NRP's interest in OCI LP increased to 49% , consisting of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues, management or control of OCI LP. In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC alleging that the transactions conducted in 2013 triggered an acceleration of NRP's obligation under the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of such amount, together with interest, court costs and attorneys’ fees. NRP does not believe the reorganization transactions triggered an obligation to pay any additional contingent consideration, and intends to vigorously defend this lawsuit. However, the ultimate outcome cannot be predicted with certainty given the early stage of this matter, and the Partnership estimates a possible range of loss between $0 , if it prevails, and approximately $40 million , plus interest, court costs and attorneys’ fees if Anadarko prevails and is awarded the full damages it seeks. Foresight Energy Disputes In November 2015, NRP filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro") and has subsequently named Foresight Energy and certain of its other subsidiaries in that lawsuit. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine, as well as alter-ego and tortious interference claims against Foresight Energy. In late March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled. In July 2015, Hillsboro declared a force majeure event under its lease with us, and Hillsboro has failed to make its contractually obligated minimum quarterly payments of $7.5 million since then. NRP believes the force majeure declaration by Hillsboro has no merit, and is vigorously pursuing recovery against Hillsboro as well as against Foresight Energy and certain of its other subsidiaries. Hillsboro has failed to make $76.0 million of required quarterly payments to NRP to date and such amount will continue to increase by $7.5 million for each quarter with respect to which payment is not made. In April 2016, NRP filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail loop leases by incorrectly recouping previously paid minimum royalties. As a result, Macoupin owes NRP approximately $9.5 million in improperly recouped minimum royalties through December 31, 2017. 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, 2017. The Partnership is not associated with any material 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. The Partnership is also responsible for losses and liabilities, including environmental liabilities that may arise from uninsured and underinsured events at its Construction Aggregates operations. Additionally, as a former 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 during the period it was an owner.

Deferred Revenue and Deferred R

Deferred Revenue and Deferred Revenue - Affiliate	12 Months Ended
	Dec. 31, 2017
Deferred Revenue Disclosure [Abstract]
Deferred Revenue and Deferred Revenue - Affiliate	Deferred Revenue and Deferred Revenue—Affiliate Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as a deferred revenue liability 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. The Partnership’s deferred revenue (including affiliate) consists of the following: December 31, (In thousands) 2017 2016 Deferred revenue $ 100,605 $ 44,931 Deferred revenue—affiliate — 71,632 Total deferred revenue (including affiliate) $ 100,605 $ 116,563 The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums resulting from the expiration of the lessee’s ability to recoup the payments as Coal royalty and other revenue: For the Years Ended December 31, (In thousands) 2017 2016 2015 Coal royalty and other $ 16,767 $ 49,284 $ 3,451 Coal royalty and other—affiliates 14,055 15,307 12,038 Total coal royalty and other (including affiliates) $ 30,822 $ 64,591 $ 15,489 Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances During the years ended December 31, 2017 , 2016 and 2015 , the Partnership entered into agreements with certain lessees to either modify or terminate existing coal-related leases that resulted in the Partnership recognizing $3.4 million , $40.5 million , and less than $0.1 million of deferred revenue as revenue, respectively.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit-Based Compensation	Unit-Based Compensation 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, Nominating and Governance Committee ("CNG Committee") of GP Natural Resource Partners LLC’s board of directors (the "Board") 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 and the CNG Committee have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant. Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a unit of the Parent common units upon each vesting. The Partnership records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted each reporting period for any changes in the Partnership’s unit price. Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise. In connection with the phantom unit awards, the CNG Committee also granted tandem Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting. A summary of activity in the outstanding grants during 2017 is as follows: (In thousands) Phantom Units Outstanding grants at January 1, 2017 86 Grants during the period — Grants vested and paid during the period (28 ) Forfeitures during the period (5 ) Outstanding grants at December 31, 2017 53 Grants typically vest at the end of a four -year period and are paid in cash upon vesting. The grant date fair value was $4.2 million for awards in 2015 . There were no new awards issued in 2016 or 2017. The Partnership recognized compensation expense (benefit) of $0.3 million , $1.4 million and $(3.4) million included in Operating and maintenance expenses and General and administrative expenses on its Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017 , 2016 and 2015 , respectively. Compensation expense includes the amortization of the awards over the vesting period and changes in the market price of the Partnership's common units during the period. The unamortized cost associated with unvested outstanding grants and related DERs at December 31, 2017 and December 31, 2016 , was $0.2 million and $0.8 million , respectively. In connection with the Long-Term Incentive Plans, cash payments are typically made during the first quarter of the year. Payments of $1.8 million , $1.5 million and $4.4 million were made during the years ended December 31, 2017 , 2016 , and 2015 , respectively.

Supplemental Quarterly Informat

Supplemental Quarterly Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Information (Unaudited)	Quarterly Financial Data The following table summarizes quarterly financial data for 2017: (In thousands, except per unit data) First (1) Second (2) Third Fourth Total Revenues (including affiliates) $ 88,653 $ 91,570 $ 93,116 $ 100,822 $ 374,161 Gain on asset sales 44 3,361 171 280 3,856 Asset impairments 1,778 — — 1,253 3,031 Income from operations 37,042 50,404 46,531 49,998 183,975 Debt modification expense 7,807 132 — — 7,939 Loss on extinguishment of debt — 4,107 — — 4,107 Net income from continuing operations 6,111 25,857 26,499 30,741 89,208 Net income (loss) from discontinued operations (207 ) 133 (433 ) (34 ) (541 ) Net income 5,904 25,990 26,066 30,707 88,667 Net income attributable to common unitholders and general partner 3,404 18,452 18,416 22,942 63,214 Net income per common unit (basic) 0.28 1.47 1.48 1.84 5.06 Net income per common unit (diluted) 0.28 1.13 1.07 1.26 3.96 Weighted average number of common units outstanding (basic) 12,232 12,232 12,232 12,232 12,232 Weighted average number of common units outstanding (diluted) 14,945 22,459 23,980 23,874 21,950 (1) During the first quarter of 2017 the Partnership incurred $7.8 million of debt modification costs as a result of the exchange of $241 million of our 2018 Senior Notes for 2022 Senior Notes. (2) During the second quarter of 2017 the Partnership incurred a $4.1 million loss on extinguishment of debt related to the 4.563% premium paid to redeem the 2018 Senior Notes in April 2017. The following table summarizes quarterly financial data for 2016: (In thousands, except per unit data) First (1) Second (2) Third (3) Fourth Total Revenues (including affiliates) $ 73,902 $ 119,317 $ 91,448 $ 86,311 $ 370,978 Gain (loss) on asset sales 21,925 (1,071 ) 6,426 1,801 29,081 Asset impairments (4) 1,893 91 5,697 9,245 16,926 Income from operations 48,991 70,741 38,907 27,106 185,745 Net income from continuing operations 26,351 48,633 16,419 3,811 95,214 Net income (loss) from discontinued operations (2,924 ) (2,187 ) 7,112 (323 ) 1,678 Net income 23,427 46,446 23,531 3,488 96,892 Net income attributable to common unitholders and general partner 23,427 46,446 23,531 3,488 96,892 Net income per common unit (basic and diluted) 1.88 3.73 1.89 0.28 7.78 Weighted average number of common units outstanding (basic and diluted) 12,232 12,232 12,232 12,232 12,232 (1) During the first quarter of 2016 the Partnership sold oil and gas royalty and aggregates royalty assets for a cumulative gain of $21.9 million . (2) During the second quarter of 2016 the Partnership entered into agreements with certain lessees to either modify or terminate existing coal-related leases that resulted in the Partnership recognizing $35 million of deferred revenue. (3) During the third quarter of 2016 the Partnership sold assets in multiple sale transactions for a net gain of $6.4 million primarily related to eminent domain transactions with governmental agencies. (4) See Note 11. Mineral Rights for asset impairment discussion.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with International Paper Company controlled by the Partnership. The Partnership has an equity investment through which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the investee’s activities and is accounted for using the equity method. Intercompany transactions and balances have been eliminated.
Use of Estimates	Use of Estimates Preparation of the accompanying financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income (Loss) during the reporting period. Actual results could differ from those estimates. The most significant estimates pertain to coal and aggregate reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization and impairments of coal and aggregate properties and commitments and contingencies.
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 14. 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	Allowance for Doubtful Accounts Accounts receivable are recorded net of the allowance for doubtful accounts. The Partnership records an allowance for doubtful accounts for receivables which it determines to be uncollectible based on the specific identification method. Accounts are written off when collection efforts are exhausted and future recovery is doubtful.
Inventory	Inventory Inventories are comprised of aggregates and supplies and parts and are stated at the lower of cost or net realizable value. 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 and parts inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Partnership’s aggregates operations.
Plant and Equipment	Plant and Equipment Plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the asset acquired and consists of coal preparation plants, related coal handling facilities, and other coal and aggregate transportation and processing infrastructure. Expenditures for new facilities or 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 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 costs for construction in process and mine development 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. Once production commences, capitalization of such costs ceases. Mine development costs are amortized based on production over the estimated life of mineral reserves and amortization is included as a component of depreciation expense.
Mineral Rights	Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.
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 over the remaining term of the underlying lease for temporarily idled assets.
Asset Impairment	Asset Impairment The Partnership has developed procedures to evaluate its long-lived assets for possible impairment periodically or whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. These procedures are performed throughout the year and are based on historic, current and future performance and consider 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. The Partnership believes its estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a property. The Partnership evaluates its equity investment 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 potential 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.
Revenue Recognition	Revenue Recognition Coal Royalty and Other Revenues. Coal royalty and other revenues are recognized on the basis of tons of mineral mined or 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 mine or sell. While the Partnership may have multiple contracts with a single lessee, such contracts are accounted for as separate arrangements. Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as deferred revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenue when the underlying mineral lease recoups the minimum payment through production or is recognized as minimums recognized as revenue in the period immediately following the expiration of the lessee’s ability to recoup the payments. 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. Oil and gas related revenues consist of revenues from royalties and overriding royalties and 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. Transportation and Processing. 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. Processing fees are recognized on the basis of tons of material processed through the facilities by the 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. These fees are included in Transportation and processing fees (or Transportation and processing fees-affiliate) in the Consolidated Statements of Comprehensive Income (Loss). Equity in Earnings from Ciner Wyoming. The Partnership accounts for non-marketable equity 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. The Partnership accounts for its investment in Ciner Wyoming, of which it owns 49% , using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of investee's net assets 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 (Loss). The carrying value in Ciner Wyoming is reflected in the caption "Equity in unconsolidated investment" in the Partnership's Consolidated Balance Sheets. The Partnership's adjusted share of the earnings or losses of Ciner Wyoming is reflected in the Consolidated Statements of Comprehensive Income (Loss) as revenues and other income under the caption ‘‘Equity in earnings of Ciner Wyoming." The Partnership's share of 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 net assets, 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. In reporting cash flows of its equity method investment in Ciner Wyoming, the Partnership utilizes the cumulative earnings approach in which distributions received are considered returns on investment and classified as cash inflows from operating activities unless the cumulative distributions received exceed cumulative equity in earnings recognized by the Partnership, in which case the excess cumulative distributions received would be classified as cash inflows from investing activities as a return of investment. Construction Aggregates Revenues. Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Road Construction and Asphalt Paving. 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.
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 Operating and maintenance expenses and in Coal Royalty and Other revenues, respectively, in the Consolidated Statements of Comprehensive Income (Loss).
Transportation Revenue and Expense	Transportation Revenue and Expense The Partnership records transportation revenue and pays transportation costs to a Foresight Energy LP ("Foresight Energy") affiliate to operate equipment on behalf of the Partnership. The revenue and expenses related to these transactions are recorded as Transportation and processing revenues (or Transportation and processing revenues—affiliates) and Operating and maintenance expenses or (Operating and maintenance expenses—affiliates), respectively, in the Consolidated Statements of Comprehensive Income (Loss). Subsequent to May 9, 2017, Foresight Energy is no longer deemed a related party; refer to Note 15. Related Party Transactions for further details. Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as Construction Aggregates revenues and Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income (Loss).
Unit-Based Compensation	Unit-Based Compensation The Partnership has awarded unit-based compensation in the form of phantom units and accounts for such awards using the fair value method, which requires the Partnership to estimate compensation costs based on the fair value of the grant and remeasure each reporting period based on the Partnership’s common unit price over the requisite service, which is generally vesting period of the grant. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability.
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 line-of-credit or debt arrangements. Deferred financing costs related to the Partnership's revolving credit facility are included in other assets (long-term) and deferred financing costs related to the Partnership's note agreements are included as a direct deduction from the carrying amount of the debt liability in Long-term debt, net on the Partnership's Consolidated Balance Sheets.
Income Taxes	Income Taxes The Partnership is not subject to federal or material state income taxes, as the partners are taxed individually on their allocable share of taxable income. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis 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.
Recently Issued Accounting Standards	Recently Adopted Accounting Standards Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-15, Statement of Cash Flows (Topic 230), which is intended to clarify how certain cash receipts and cash payments are presented and classified in the statement of cash flows in order to reduce current and potential future diversity in practice. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. The Partnership elected to early adopt this guidance in the second quarter of 2017 and elected to continue to classify distributions it received from its equity method investees under the cumulative earnings approach in which distributions received are considered returns on investment and classified as cash inflows from operating activities unless the cumulative distributions received exceed cumulative equity in earnings recognized by the Partnership. The early adoption of this guidance in the second quarter of 2017 did not have a material effect on its consolidated financial statements. Accounting Changes and Error Corrections. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately. The Partnership adopted this guidance during the first quarter of 2017. The adoption of this guidance impacted the Partnership's disclosures but had no effect on its financial position, results of operations or cash flows. Earnings per Share. In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception. The guidance eliminates the requirement to consider "down-round" features when determining whether certain equity-linked financial instruments or embedded features are indexed to an entity’s own stock. The guidance requires entities that present earnings per share ("EPS") under ASC 260 to recognize the effect of a down-round feature in a freestanding equity-classified financial instrument only when it is triggered. The effect of triggering such a feature will be recognized as a dividend and a reduction to income available to common shareholders in basic EPS. Entities will also have to make new disclosures for financial instruments with down-round features and other terms that change conversion or exercise prices. The guidance is effective for annual and interim periods ending after December 31, 2018 and early adoption is permitted. The Partnership early adopted this guidance in the third quarter of 2017. Refer to Note 2. Change in Method of Accounting for NRP's Warrants in the Partnerships September 30, 2017 Form 10-Q for disclosure of the effects of adoption on its quarterly consolidated financial statements. There was no impact to the consolidated financial statements for the years ended December 31, 2017, 2016 and 2015. Recently Issued Accounting Standards Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, ASC Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. Additionally, in March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvements and practical expedients, which addresses narrow-scope improvements to the guidance on collectibility, non-cash consideration, and completed contracts at transition. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which clarifies the guidance or corrects unintended application of guidance. The Partnership adopted the new standard on January 1, 2018 and has elected to use the modified retrospective adoption method. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue. The Partnership identified the contracts for all of its revenue streams and utilized the practical expedient of grouping contracts or performance obligations with similar characteristics as prescribed by the new standard. As a result of the analysis performed, the Partnership concluded that the new revenue recognition standard will have no impact on revenue from NRP's Construction Aggregates or Soda Ash operating segments. However, the Partnership determined that adoption of the new revenue recognition standard will impact certain revenue from NRP's coal royalty leases as further described below. The other revenue streams within the Coal Royalty and Other segment will not be impacted. Historically, NRP has recognized all coal royalty revenue over the lease term based on coal production and minimum payments were deferred until either recoupment occurred or the recoupment period expired. Under the new revenue recognition standard, management has defined NRP's coal royalty lease performance obligation as providing the lessee the right to mine and sell NRP's coal over the lease term. The Partnership then evaluated the likelihood that consideration NRP received from its lessees resulting from coal production would exceed consideration received from minimum payments over the lease term. As a result of this evaluation, revenue recognition from the Partnership's leases will now be based on either production or minimum payments as follows: 1. Production Leases: Leases for which the Partnership expects that consideration from coal production will be greater than consideration from minimums over the lease term. Revenue recognition for these leases will be recognized over time based on coal production and minimum payments will continue to be deferred until recoupment occurs or the recoupment becomes remote. If the Partnership does receive minimum payments from these coal royalty leases, it will begin to evaluate the likelihood of recoupment and recognize deferred revenue prior to expiration of the recoupment period if it concludes that recoupment is remote. 2. Minimum Leases: Leases for which the Partnership expects that consideration from minimums will be greater than consideration from coal production over the lease term. Revenue recognition for these leases will now be recognized straight line over the lease term based on the minimum payment consideration amount. As a result of implementation of the new standard for the Partnership's coal lease contracts, NRP expects to record approximately $80 million to $90 million reduction to deferred revenue and a corresponding increase in retained earnings on January 1, 2018. The Partnership will perform this contract evaluation at the end of each reporting period going forward. Leases . In February 2016, the FASB issued ASU No. 2016-02, Leases, as a new Topic, ASC Topic 842. The new lease guidance supersedes Topic 840. Lessees are to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. This ASU does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. The guidance also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The guidance is effective for annual and interim periods beginning after December 31, 2018. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Plant and Equipment Useful Lives	These assets 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

Class A Convertible Preferred29

Class A Convertible Preferred Units and Warrants Class A Convertible Preferred Units and Warrants (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Preferred Units and Warrants Issued	The Preferred Units and Warrants were initially recognized as follows: (In thousands) March 2, 2017 Transaction price, gross $ 250,000 Structuring, origination and other fees to Preferred Purchasers (7,900 ) Transaction costs to other third parties (10,697 ) Transaction price, net $ 231,403 Allocation of net transaction price Preferred Units, net $ 164,587 Warrant holders interest, net 66,816 Transaction price, net $ 231,403

Common and Preferred Unit Dis30

Common and Preferred Unit Distributions (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of distributions paid	The following table shows the distributions paid by the Partnership on its common units and general partner's general partner interest during the years ended December 31, 2017 , 2016 and 2015 : (In thousands, except per unit data) Total Distributions Date Paid Period Covered by Distribution Distribution per Common Unit Common Units GP Interest Total 2017 February 14, 2017 October 1 - December 31, 2016 $ 0.45 $ 5,503 $ 112 $ 5,615 May 12, 2017 January 1 - March 31, 2017 0.45 5,506 113 5,619 August 14, 2017 April 1 - June 30, 2017 0.45 5,504 112 5,616 November 14, 2017 July 1 - September 30, 2017 0.45 5,505 112 5,617 2016 February 12, 2016 October 1 - December 31, 2015 $ 0.45 $ 5,503 $ 113 $ 5,616 May 13, 2016 January 1 - March 31, 2016 0.45 5,503 113 5,616 August 12, 2016 April 1 - June 30, 2016 0.45 5,505 112 5,617 November 14, 2016 July 1 - September 30, 2016 0.45 5,503 113 5,616 2015 February 13, 2015 October 1 - December 31, 2014 $ 3.50 $ 42,804 $ 874 $ 43,678 May 14, 2015 January 1 - March 31, 2015 0.90 11,007 225 11,232 August 14, 2015 April 1 - June 30, 2015 0.90 11,009 223 11,232 November 13, 2015 July 1 - September 30, 2015 0.45 5,504 112 5,616 Preferred Unit Distributions The following table shows the cash and paid-in-kind distributions declared and paid to Preferred Unitholders by the Partnership during the year ended December 31, 2017 : (In thousands, except per unit data) Date Paid Period Covered by Distribution Distribution per Preferred Unit Paid-in-Kind Preferred Units Cash Distributions Total Distribution Declared May 30, 2017 March 2 - March 31, 2017 $ 5.00 1,250 $ 1,250 $ 2,500 August 29, 2017 April 1 - June 30, 2017 $ 15.00 3,769 3,769 7,538 November 29, 2017 July 1 - September 30, 2017 $ 15.00 3,825 3,825 7,650 8,844 $ 8,844 $ 17,688
Financial Position of Preferred Units	The following table shows the units outstanding and financial position of the Preferred Units from initial measurement at March 2, 2017 to December 31, 2017: (In thousands) Units outstanding Financial position Balance at December 31, 2016 — $ — Issuance of Preferred Units, net 250,000 164,587 Distribution paid-in-kind 8,844 8,844 Balance at December 31, 2017 258,844 $ 173,431

Net Income Per Common Unit Ne31

Net Income Per Common Unit Net Income Per Common Unit (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Reconciliation of Net Income to Weighted Average Units Outstanding	The following table reconciles net income and weighted average units used in computing basic and diluted net income per common unit is as follows (in thousands, except per unit data): Years Ended December 31, (In thousands, except per unit data) 2017 2016 2015 Allocation of net income: Net income (loss) from continuing operations $ 89,208 $ 95,214 $ (260,171 ) Less: income attributable to preferred unitholders 25,453 — — Less: net income (loss) from continuing operations and income attributable to preferred unitholders allocated to the general partner 1,275 1,629 (5,998 ) Net income (loss) from continuing operations attributable to common unitholders $ 62,480 $ 93,585 $ (254,173 ) Net income (loss) from discontinued operations $ (541 ) $ 1,678 $ (311,549 ) Less: net income (loss) from discontinued operations attributable to the general partner (11 ) 34 (6,230 ) Net income (loss) from discontinued operations attributable to common unitholders $ (530 ) $ 1,644 $ (305,319 ) Net income (loss) $ 88,667 $ 96,892 $ (571,720 ) Less: income attributable to preferred unitholders 25,453 — — Less: net income (loss) and income attributable to preferred unitholders allocated to the general partner 1,264 1,663 (12,228 ) Net income (loss) attributable to common unitholders $ 61,950 $ 95,229 $ (559,492 ) Basic Income (Loss) per Unit: Weighted average common units—basic 12,232 12,232 12,232 Basic net income (loss) from continuing operations per common unit $ 5.11 $ 7.65 $ (20.78 ) Basic net income (loss) from discontinued operations per common unit $ (0.04 ) $ 0.13 $ (24.97 ) Basic net income (loss) per common unit $ 5.06 $ 7.78 $ (45.75 ) Diluted Income (Loss) per Unit: Weighted average common units—basic 12,232 12,232 12,232 Plus: dilutive effect of Warrants 300 — — Plus: dilutive effect of Preferred Units 9,418 — — Weighted average common units—diluted 21,950 12,232 12,232 Net income (loss) from continuing operations $ 89,208 $ 95,214 $ (260,171 ) Less: net income (loss) from continuing operations allocated to the general partner 1,784 1,629 (5,998 ) Diluted net income (loss) from continuing operations attributable to common unitholders $ 87,424 $ 93,585 $ (254,173 ) Diluted net income (loss) from discontinued operations attributable to common unitholders $ (530 ) $ 1,644 $ (305,319 ) Net income (loss) $ 88,667 $ 96,892 $ (571,720 ) Less: net income (loss) allocated to the general partner 1,773 1,663 (12,228 ) Diluted net income (loss) attributable to common unitholders $ 86,894 $ 95,229 $ (559,492 ) Diluted net income (loss) from continuing operations per common unit $ 3.98 $ 7.65 $ (20.78 ) Diluted net income (loss) from discontinued operations per common unit $ (0.02 ) $ 0.13 $ (24.97 ) Diluted net income (loss) per common unit $ 3.96 $ 7.78 $ (45.75 )

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	he following table summarizes certain financial information for each of the Partnership's operating segments: Operating Segments (In thousands) Coal Royalty and Other Soda Ash Construction Aggregates Corporate and Financing Total For the Year Ended December 31, 2017 Revenues (including affiliates) $ 202,323 $ 40,457 $ 131,381 $ — $ 374,161 Intersegment revenues (expenses) 295 — (295 ) — — Gain on asset sales, net 3,545 — 311 — 3,856 Operating and maintenance expenses (including affiliates) 24,883 — 111,633 — 136,516 General and administrative (including affiliates) — — — 18,502 18,502 Depreciation, depletion and amortization (including affiliates) 23,414 — 12,579 — 35,993 Asset impairment 2,967 — 64 — 3,031 Other expense, net — — 693 94,074 94,767 Net income (loss) from continuing operations 154,899 40,457 6,428 (112,576 ) 89,208 Net income from discontinued operations — — — — (541 ) Capital expenditures — — 7,595 — 7,595 As of December 31, 2017 Total assets of continuing operations $ 945,237 $ 245,433 $ 191,374 $ 6,129 $ 1,388,173 Total assets of discontinued operations — — — — 991 Trade accounts receivable (including affiliates) 16,355 — 22,976 — 39,331 Property taxes and other receivable (including affiliates) 7,856 — — — 7,856 Operating Segments (In thousands) Coal Royalty and Other Soda Ash Construction Aggregates Corporate and Financing Total For the Year Ended December 31, 2016 Revenues (including affiliates) $ 210,115 $ 40,061 $ 120,802 $ — $ 370,978 Intersegment revenues (expenses) 150 — (150 ) — — Gain on asset sales, net 29,068 — 13 — 29,081 Operating and maintenance expenses 29,890 — 100,656 — 130,546 General and administrative (including affiliates) — — — 20,570 20,570 Depreciation, depletion and amortization (including affiliates) 31,766 — 14,506 — 46,272 Asset impairment 15,861 — 1,065 — 16,926 Other expense, net — — — 90,531 90,531 Net income (loss) from continuing operations 161,816 40,061 4,438 (111,101 ) 95,214 Net income from discontinued operations — — — — 1,678 Capital expenditures 5 — 5,380 — 5,385 As of December 31, 2016 Total assets of continuing operations $ 990,172 $ 255,901 $ 190,615 $ 10,970 $ 1,447,658 Total assets of discontinued operations — — — — 991 Trade accounts receivable (including affiliates) 18,791 — 19,168 — 37,959 Property taxes and other receivable (including affiliates) 11,661 — 208 32 11,901 For the Year Ended December 31, 2015 Revenues (including affiliates) $ 243,781 $ 49,918 $ 139,049 $ — $ 432,748 Intersegment revenues (expenses) 21 — (21 ) — — Gain (loss) on asset sales, net 6,936 — (36 ) — 6,900 Operating and maintenance expenses (including affiliates) 35,321 — 116,945 — 152,266 General and administrative (including affiliates) — — — 12,348 12,348 Depreciation, depletion and amortization (including affiliates) 45,338 — 15,578 — 60,916 Asset impairment 378,327 — 6,218 — 384,545 Other expense, net — — — 89,744 89,744 Net income (loss) from continuing operations (208,248 ) 49,918 251 (102,092 ) (260,171 ) Net loss from discontinued operations — — — — (311,549 ) Capital expenditures 428 — 14,039 — 14,467

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Summary of Financial Results of Discontinued Operations	The following table presents supplemental cash flow information of the Partnership's discontinued operations: Years Ended December 31, (In thousands) 2017 2016 2015 Cash paid for interest $ — $ 1,906 $ 2,755 Plant, equipment and mineral rights funded with accounts payable or accrued liabilities — — 1,645 The following table presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations in the Consolidated Balance Sheets: December 31, (In thousands) 2017 2016 ASSETS Current assets: Accounts receivable, net (including affiliates) (1) $ 991 $ 991 Total assets of discontinued operations $ 991 $ 991 LIABILITIES Current liabilities: Other (including affiliates) (1) $ 401 $ 353 Total liabilities of discontinued operations $ 401 $ 353 (1) See Note 15. Related Party Transactions for additional information on the Partnership's related party assets and liabilities. The following table presents summarized financial results of the Partnership's discontinued operations in the Consolidated Statements of Comprehensive Income (Loss): For the Years Ended December 31, (In thousands) 2017 2016 2015 Revenues and other income: Oil and gas $ 38 $ 16,486 $ 48,750 Gain on asset sales (289 ) 8,274 451 Total revenues and other income $ (251 ) $ 24,760 $ 49,201 Operating expenses: Operating and maintenance expenses (including affiliates) $ 290 $ 11,503 $ 19,724 Depreciation, depletion and amortization — 7,527 39,912 Asset impairments — 564 297,049 Total operating expenses $ 290 $ 19,594 $ 356,685 Interest expense — (3,488 ) (4,065 ) Income (loss) from discontinued operations $ (541 ) $ 1,678 $ (311,549 )

Equity Investment (Tables)

Equity Investment (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Summarized Financial Information	The Partnership's equity in the earnings of Ciner Wyoming is summarized as follows: For the Year Ended December 31, (In thousands) 2017 2016 2015 Income allocation to NRP’s equity interests (1) $ 44,846 $ 44,882 $ 54,709 Amortization of basis difference (4,389 ) (4,821 ) (4,791 ) Equity in earnings of unconsolidated investment $ 40,457 $ 40,061 $ 49,918 (1) Includes reclassifications of accumulated other comprehensive loss to income allocation to NRP equity interest of $0.7 million , $0.9 million and $0.7 million for the year ended December 31, 2017, 2016 and 2015, respectively. The results of Ciner Wyoming’s operations are summarized as follows: For the Year Ended December 31, (In thousands) 2017 2016 2015 Sales $ 497,340 $ 475,187 $ 486,393 Gross profit 114,202 114,232 131,493 Net Income 91,523 91,596 111,650 The financial position of Ciner Wyoming is summarized as follows: December 31, (In thousands) 2017 2016 Current assets $ 180,433 $ 134,616 Noncurrent assets 228,002 235,427 Current liabilities 56,219 55,396 Noncurrent liabilities 148,401 98,425

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Components of Inventories	The components of inventories are as follows: December 31, (In thousands) 2017 2016 Aggregates $ 6,209 $ 6,037 Supplies and parts 1,344 856 Total inventory $ 7,553 $ 6,893

Plant and Equipment (Tables)

Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Plant and Equipment	The Partnership’s plant and equipment consist of the following: December 31, (In thousands) 2017 2016 Plant and equipment at cost $ 84,173 $ 79,171 Construction in process 803 557 Less accumulated depreciation (38,806 ) (30,285 ) Total plant and equipment, net $ 46,170 $ 49,443

Mineral Rights (Tables)

Mineral Rights (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Mineral Rights	The Partnership’s mineral rights consist of the following: December 31, 2017 (In thousands) Carrying Value Accumulated Depletion Net Book Value Coal properties $ 1,170,104 $ (436,964 ) $ 733,140 Aggregates properties 150,642 (16,836 ) 133,806 Oil and gas royalty properties 12,395 (7,158 ) 5,237 Other 13,168 (1,466 ) 11,702 Total mineral rights, net $ 1,346,309 $ (462,424 ) $ 883,885 December 31, 2016 (In thousands) Carrying Value Accumulated Depletion Net Book Value Coal properties $ 1,170,904 $ (420,032 ) $ 750,872 Aggregates properties 176,774 (39,056 ) 137,718 Oil and gas royalty properties 12,395 (6,289 ) 6,106 Other 14,946 (1,450 ) 13,496 Total mineral rights, net $ 1,375,019 $ (466,827 ) $ 908,192
Schedule of Impairment Expense	During the years ended December 31, 2017 , 2016 and 2015 , the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense as follows: For the years ended December 31, (In thousands) 2017 2016 2015 Coal properties (1) $ 595 $ 12,088 $ 257,468 Oil and gas properties (2) — 36 70,527 Aggregates and timber royalty properties (3) 2,372 1,677 43,402 Total $ 2,967 $ 13,801 $ 371,397 (1) The Partnership recorded $0.6 million of coal property impairments during the year ended December 31, 2017 . The Partnership recorded $12.1 million of coal property impairments during the year ended December 31, 2016, primarily as a result of lease surrender and termination. The Partnership recorded $3.8 million of coal property impairment during the three months ended September 30, 2016 and the fair value of the impaired asset was reduced to $4.0 million at September 30, 2016. The Partnership recorded $8.2 million of coal property impairment during the three months ended December 31, 2016 and the fair value of the impaired asset was reduced to $0.0 million at December 31, 2016. Total coal property impairment expense for the year ended December 31, 2015 was $257.5 million . The Partnership recorded $1.5 million of coal property impairment during the three months ended June 30, 2015 and the fair value measurement of these impaired assets was reduced to $0.0 million at June 30, 2015. The Partnership recorded $247.8 million of coal property impairment during the three months ended September 30, 2015 and the fair value of these impaired assets was reduced to $28.4 million at September 30, 2015. The Partnership recorded the remaining $8.2 million of coal property impairment during the three months ended December 31, 2015 and the fair value of these impaired assets was reduced to $0.4 million at December 31, 2015. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. (2) The Partnership recorded $36 thousand of oil and gas royalty asset impairment during the year ended December 31, 2016. The total oil and gas royalty impairment for the year ended December 31, 2015 was $70.5 million . The Partnership recorded this impairment during the three months ended September 30, 2015. The fair value measurement of these impaired assets was reduced to $13.0 million at September 30, 2015. This impairment primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on its acreage. NRP compared net capitalized costs of its oil and gas royalty properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials. (3) The Partnership recorded $2.4 million of aggregates and timber royalty property impairments during the year ended December 31, 2017. The Partnership recorded $1.7 million of aggregates royalty property impairments during the year ended December 31, 2016. Total aggregates property impairment expense for the year ended December 31, 2015 was $43.4 million . This impairment was recorded during the three months ended September 30, 2015. The fair value measurement of these impaired assets was reduced to $13.1 million at September 30, 2015. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows.

Goodwill and Intangible Asset38

Goodwill and Intangible Assets (Including Affiliate) (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transaction [Line Items]
Estimated Amortization Expense	The estimates of amortization expense for the years ended December 31, as indicated below, are based on current mining plans and are subject to revision as those plans change in future periods. (In thousands) Estimated Amortization Expense 2018 $ 3,123 2019 2,921 2020 3,492 2021 3,351 2022 3,351
Affiliated Entity
Related Party Transaction [Line Items]
Intangible Assets	The Partnership's intangible assets (including affiliate) included in the Partnership's Consolidated Balance Sheets are as follows: December 31, (In thousands) 2017 2016 Intangible assets (including affiliate) $ 86,336 $ 86,336 Less accumulated amortization (including affiliate) (36,782 ) (33,289 ) Total intangible assets, net (including affiliate) $ 49,554 $ 53,047

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	The Partnership's debt consisted of the following: December 31, (In thousands) 2017 2016 NRP LP debt: 10.500% senior notes, with semi-annual interest payments in March and September, due March 2022, $241 million issued at par and $105 million issued at 98.75% $ 345,638 $ — 9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% — 425,000 Opco debt: Revolving credit facility 60,000 210,000 Senior notes 4.91% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018 4,586 9,187 8.38% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019 42,670 64,029 5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020 22,946 30,633 5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 16,115 18,825 4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 44,693 52,204 5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 104,520 119,524 8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 31,733 36,272 5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 120,547 134,035 5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 34,396 38,262 5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021 — 961 Total debt at face value $ 827,844 $ 1,138,932 Net unamortized debt discount (1,661 ) (1,322 ) Net unamortized debt issuance costs (16,835 ) (7,339 ) Total debt, net $ 809,348 $ 1,130,271 Less: current portion of long-term debt 79,740 140,037 Total long-term debt, net $ 729,608 $ 990,234
Principal Payments Due	The consolidated principal payments due are set forth below: NRP LP Opco (In thousands) Senior Notes (1) Senior Notes Credit Facility Total 2018 $ — $ 80,385 $ — $ 80,385 2019 — 75,799 — 75,799 2020 — 54,464 60,000 114,464 2021 — 46,815 — 46,815 2022 345,638 46,815 — 392,453 Thereafter — 117,928 — 117,928 $ 345,638 $ 422,206 $ 60,000 $ 827,844 (1) The 10.500% senior notes due 2022 were issued at a discount and were carried at $344.0 million as of December 31, 2017.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Contractual Override, Note Receivable and Long-Term Debt	The following table shows the carrying amount and estimated fair value of the Partnership's debt and contracts receivable (including affiliates): December 31, 2017 December 31, 2016 (In thousands) Carrying Value Estimated Carrying Estimated Debt NRP 2018 Senior Notes (1) $ — $ — $ 420,097 $ 412,250 NRP 2022 Senior Notes (1) 330,404 366,376 — — Opco Senior Notes and utility local improvement obligation (2) 418,944 447,538 500,174 488,814 Opco Revolving Credit Facility (3) 60,000 60,000 210,000 210,000 Assets: Contracts receivable (including affiliates), current and long-term (4) $ 43,826 $ 30,517 $ 46,742 $ 32,554 (1) The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period end. (2) Due to no observable quoted prices on these instruments, the Level 3 fair value is estimated by management using quotations obtained for the NRP Senior Notes on the closing trading prices near period end. (3) The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. (4) The Level 3 fair value is determined based on the present value of future cash flow projections related to the underlying assets.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Expenses related to these transactions with Foresight Energy are included in the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows: For the Years Ended December 31, (In thousands) 2017 2016 2015 Operating and maintenance expense $ 1,066 $ — $ — Operating and maintenance expense—affiliates, net 452 1,347 1,413 Total $ 1,518 $ 1,347 $ 1,413 The following table shows certain amounts related to NRP's Sugar Camp rail load out facility direct financing lease and amounts of all other transactions with subsidiaries of Foresight Energy reflected on NRP's Consolidated Balance Sheets: December 31, (In thousands) 2017 2016 Sugar Camp rail load out direct financing lease amounts Projected remaining payments $ 71,452 $ 76,424 Unearned Income 28,366 31,803 ASSETS Accounts receivable $ 6,127 $ — Accounts receivable—affiliates, net — 6,496 Long-term contracts receivable 40,776 — Long-term contracts receivable—affiliates — 43,785 LIABILITIES Deferred revenue $ 53,778 — Deferred revenue—affiliates — $ 71,632 Revenues related to these transactions with Foresight Energy are included in the Partnership's Consolidated Statement of Comprehensive Income (Loss) as follows: For the Years Ended December 31, (In thousands) 2017 2016 2015 Coal royalty and other revenue $ 43,273 $ — $ — Coal royalty and other — affiliates revenue 27,216 63,355 86,614 Total $ 70,489 $ 63,355 $ 86,614
Summary of Reimbursements	Direct general and administrative expenses charged to the Partnership by WPPLP and QMC are as follows: For the Years Ended December 31, (In thousands) 2017 2016 2015 Operating and maintenance expenses—affiliates, net $ 7,606 $ 9,891 $ 10,063 General and administrative—affiliates $ 4,989 $ 3,591 $ 5,312

Major Customers (Tables)

Major Customers (Tables)	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Major customers	Revenues from customers that exceeded 10 percent of total revenues and other income for any of the periods presented below are as follows: For the Years Ended December 31, 2017 2016 2015 (In thousands) Revenues Percent Revenues Percent Revenues Percent Foresight Energy $ 70,489 18.6 % $ 63,355 15.8 % $ 86,614 19.7 % Revenues from Foresight Energy are included within the Partnership's Coal Royalty and Other segment.

Deferred Revenue and Deferred43

Deferred Revenue and Deferred Revenue - Affiliate (Tables)	12 Months Ended
	Dec. 31, 2017
Deferred Revenue Disclosure [Abstract]
Schedule of Deferred Revenue	The Partnership’s deferred revenue (including affiliate) consists of the following: December 31, (In thousands) 2017 2016 Deferred revenue $ 100,605 $ 44,931 Deferred revenue—affiliate — 71,632 Total deferred revenue (including affiliate) $ 100,605 $ 116,563 The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums resulting from the expiration of the lessee’s ability to recoup the payments as Coal royalty and other revenue: For the Years Ended December 31, (In thousands) 2017 2016 2015 Coal royalty and other $ 16,767 $ 49,284 $ 3,451 Coal royalty and other—affiliates 14,055 15,307 12,038 Total coal royalty and other (including affiliates) $ 30,822 $ 64,591 $ 15,489

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Activity in Outstanding Grants	A summary of activity in the outstanding grants during 2017 is as follows: (In thousands) Phantom Units Outstanding grants at January 1, 2017 86 Grants during the period — Grants vested and paid during the period (28 ) Forfeitures during the period (5 ) Outstanding grants at December 31, 2017 53

Supplemental Quarterly Inform45

Supplemental Quarterly Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Information	The following table summarizes quarterly financial data for 2017: (In thousands, except per unit data) First (1) Second (2) Third Fourth Total Revenues (including affiliates) $ 88,653 $ 91,570 $ 93,116 $ 100,822 $ 374,161 Gain on asset sales 44 3,361 171 280 3,856 Asset impairments 1,778 — — 1,253 3,031 Income from operations 37,042 50,404 46,531 49,998 183,975 Debt modification expense 7,807 132 — — 7,939 Loss on extinguishment of debt — 4,107 — — 4,107 Net income from continuing operations 6,111 25,857 26,499 30,741 89,208 Net income (loss) from discontinued operations (207 ) 133 (433 ) (34 ) (541 ) Net income 5,904 25,990 26,066 30,707 88,667 Net income attributable to common unitholders and general partner 3,404 18,452 18,416 22,942 63,214 Net income per common unit (basic) 0.28 1.47 1.48 1.84 5.06 Net income per common unit (diluted) 0.28 1.13 1.07 1.26 3.96 Weighted average number of common units outstanding (basic) 12,232 12,232 12,232 12,232 12,232 Weighted average number of common units outstanding (diluted) 14,945 22,459 23,980 23,874 21,950 (1) During the first quarter of 2017 the Partnership incurred $7.8 million of debt modification costs as a result of the exchange of $241 million of our 2018 Senior Notes for 2022 Senior Notes. (2) During the second quarter of 2017 the Partnership incurred a $4.1 million loss on extinguishment of debt related to the 4.563% premium paid to redeem the 2018 Senior Notes in April 2017. The following table summarizes quarterly financial data for 2016: (In thousands, except per unit data) First (1) Second (2) Third (3) Fourth Total Revenues (including affiliates) $ 73,902 $ 119,317 $ 91,448 $ 86,311 $ 370,978 Gain (loss) on asset sales 21,925 (1,071 ) 6,426 1,801 29,081 Asset impairments (4) 1,893 91 5,697 9,245 16,926 Income from operations 48,991 70,741 38,907 27,106 185,745 Net income from continuing operations 26,351 48,633 16,419 3,811 95,214 Net income (loss) from discontinued operations (2,924 ) (2,187 ) 7,112 (323 ) 1,678 Net income 23,427 46,446 23,531 3,488 96,892 Net income attributable to common unitholders and general partner 23,427 46,446 23,531 3,488 96,892 Net income per common unit (basic and diluted) 1.88 3.73 1.89 0.28 7.78 Weighted average number of common units outstanding (basic and diluted) 12,232 12,232 12,232 12,232 12,232 (1) During the first quarter of 2016 the Partnership sold oil and gas royalty and aggregates royalty assets for a cumulative gain of $21.9 million . (2) During the second quarter of 2016 the Partnership entered into agreements with certain lessees to either modify or terminate existing coal-related leases that resulted in the Partnership recognizing $35 million of deferred revenue. (3) During the third quarter of 2016 the Partnership sold assets in multiple sale transactions for a net gain of $6.4 million primarily related to eminent domain transactions with governmental agencies. (4) See Note 11. Mineral Rights for asset impairment discussion.

Organization and Nature of Op46

Organization and Nature of Operations - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017companysegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments | segment	3
Number of operating companies owned | company	1

Summary of Significant Accoun47

Summary of Significant Accounting Policies - Summary of Plant and Equipment Useful Lives (Detail)	12 Months Ended
	Dec. 31, 2017
Leasehold Improvements
Property, Plant and Equipment [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	Life of Lease
Minimum | Buildings and Improvements
Property, Plant and Equipment [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	20 years
Minimum | Machinery and Equipment
Property, Plant and Equipment [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	5 years
Maximum | Buildings and Improvements
Property, Plant and Equipment [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	40 years
Maximum | Machinery and Equipment
Property, Plant and Equipment [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	12 years

Summary of Significant Accoun48

Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2018	Jul. 31, 2013	Jan. 31, 2013
Schedule Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 5.1	$ 4.6
Bad debt expense	2.4	0.4	$ 4.9
Shipping and handling revenue	38.9	36	42.6
Shipping and handling costs	$ 36.3	$ 35.9	$ 42.1
Ciner Wyoming
Schedule Of Significant Accounting Policies [Line Items]
Percentage of partnership interest owned (percent)	49.00%				49.00%	48.51%
Leasehold Improvements
Schedule Of Significant Accounting Policies [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	Life of Lease
Minimum
Schedule Of Significant Accounting Policies [Line Items]
Percentage of ownership interest owned (percent)	20.00%
Minimum | Buildings and Improvements
Schedule Of Significant Accounting Policies [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	20 years
Minimum | Machinery and Equipment
Schedule Of Significant Accounting Policies [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	5 years
Minimum | Scenario, Forecast [Member]
Schedule Of Significant Accounting Policies [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption				$ 80
Maximum
Schedule Of Significant Accounting Policies [Line Items]
Percentage of ownership interest owned (percent)	50.00%
Maximum | Buildings and Improvements
Schedule Of Significant Accounting Policies [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	40 years
Maximum | Machinery and Equipment
Schedule Of Significant Accounting Policies [Line Items]
Period of assets which are depreciated on straight line basis over their useful lives	12 years
Maximum | Scenario, Forecast [Member]
Schedule Of Significant Accounting Policies [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption				$ 90

Class A Convertible Preferred49

Class A Convertible Preferred Units and Warrants Class A Convertible Preferred Units and Warrants - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 02, 2017	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Preferred units issued (in shares)		258,844	0
Preferred unit purchase price		$ 1,000	$ 0
Class A Convertible Preferred Units
Class of Stock [Line Items]
Preferred units issued (in shares)	250,000
Preferred unit purchase price	$ 1,000
Preferred Units, Origination Fee, Percent	2.50%
Dividend rate (as a percent)	12.00%	12.00%
Convertible Preferred Units, Redemption Price, Minimum	$ 51
Convertible Preferred Units, Maximum Redeemed Units, Percent	33.00%
Debt Instrument, Covenants, Consolidated Leverage Ratio, Minimum	3.25
Debt Instrument, Covenants, Distributable Cash Flow Ratio, Maximum	1.2
Distribution amount (in dollars per share)	$ 0.45
Purchaser approval rights threshold (as a percent)	20.00%
Warrants at $22.81 Strike | Warrant Holders
Class of Stock [Line Items]
Class of Warrant or Right, Warrants Issued	1,750,000
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 22.81
Warrants at $34.00 Strike | Warrant Holders
Class of Stock [Line Items]
Class of Warrant or Right, Warrants Issued	2,250,000
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 34
Debt Instrument, Redemption, Period One | Class A Convertible Preferred Units
Class of Stock [Line Items]
Convertible Preferred Units, Conversion to Common Units, Discount Percentage	7.50%
Convertible Preferred Units, Purchase Price Multiplier	1.50
Debt Instrument, Redemption, Period Two | Class A Convertible Preferred Units
Class of Stock [Line Items]
Convertible Preferred Units, Purchase Price Multiplier	1.70
Debt Instrument, Redemption, Period Three | Class A Convertible Preferred Units
Class of Stock [Line Items]
Convertible Preferred Units, Conversion to Common Units, Discount Percentage	10.00%
Convertible Preferred Units, Purchase Price Multiplier	1.85
Preferred Stock
Class of Stock [Line Items]
Transaction price, gross	$ 250,000

Class A Convertible Preferred50

Class A Convertible Preferred Units and Warrants Class A Convertible Preferred Units and Warrants - Preferred Units and Warrants Issued (Details) - USD ($) $ in Thousands	Mar. 02, 2017	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Warrant holders interest		$ 66,816	$ 0
Preferred Stock
Class of Stock [Line Items]
Transaction price, gross	$ 250,000
Structuring, origination and other fees to Preferred Purchasers	(7,900)
Transaction costs to other third parties	(10,697)
Transaction price, net	$ 231,403
Preferred Partner | Preferred Stock
Class of Stock [Line Items]
Preferred Units, net		$ 164,587

Common and Preferred Unit Dis51

Common and Preferred Unit Distributions Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 14, 2018	Mar. 02, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Temporary Equity [Line Items]
Income attributable to preferred unitholders			$ 25,453	$ 0	$ 0
Class A Convertible Preferred Units
Temporary Equity [Line Items]
Dividend rate (as a percent)		12.00%	12.00%
Subsequent Event [Member]
Temporary Equity [Line Items]
Distributions per common unit (in dollars per share)	$ 0.45
Subsequent Event [Member] | Class A Convertible Preferred Units
Temporary Equity [Line Items]
Distributions to common unitholders and general partner	$ 7,800
Redeemed PIK units, cash payment	$ 8,800

Common and Preferred Unit Dis52

Common and Preferred Unit Distributions Schedule of Distributions Paid (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 29, 2017	Nov. 14, 2017	Aug. 29, 2017	Aug. 14, 2017	May 30, 2017	May 12, 2017	Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 14, 2015	Feb. 13, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Common unitholders and general partner
Class of Stock [Line Items]
Distributions per common unit (in dollars per share)		$ 0.45		$ 0.45		$ 0.45	$ 0.45	$ 0.45	$ 0.45	$ 0.45	$ 0.45	$ 0.45	$ 0.90	$ 0.90	$ 3.50
Total distributions paid		$ 5,617		$ 5,616		$ 5,619	$ 5,615	$ 5,616	$ 5,617	$ 5,616	$ 5,616	$ 5,616	$ 11,232	$ 11,232	$ 43,678	$ 22,467	$ 22,465	$ 71,758
Common unitholders
Class of Stock [Line Items]
Distributions to common unitholders and general partner		5,505		5,504		5,506	5,503	5,503	5,505	5,503	5,503	5,504	11,009	11,007	42,804
General Partner
Class of Stock [Line Items]
Distributions to common unitholders and general partner																22,467	22,465	71,758
Distributions paid to general partners		$ 112		$ 112		$ 113	$ 112	$ 113	$ 112	$ 113	$ 113	$ 112	$ 223	$ 225	$ 874
Preferred Partner
Class of Stock [Line Items]
Distributions to common unitholders and general partner																8,844	$ 0	$ 0
Total distributions paid																$ 17,688
Preferred Partner | Preferred Stock
Class of Stock [Line Items]
Distributions per common unit (in dollars per share)	$ 15		$ 15		$ 5
Paid-in-Kind Preferred Units (in shares)	3,825		3,769		1,250
Distribution paid-in-kind (in shares)																8,844
Distributions to common unitholders and general partner	$ 3,825		$ 3,769		$ 1,250											$ 8,844
Total Distributions Declared	$ 7,650		$ 7,538		$ 2,500											$ 17,688

Common and Preferred Unit Dis53

Common and Preferred Unit Distributions Financial Position of Preferred Units (Details) - USD ($) $ in Thousands	Nov. 29, 2017	Aug. 29, 2017	May 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance				$ 0
Ending balance				173,431	$ 0
Preferred Partner
Increase (Decrease) in Temporary Equity [Roll Forward]
Distribution paid-in-kind				$ 8,844	$ 0	$ 0
Preferred Partner | Preferred Stock
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance (in shares)				0
Issuance of preferred units, net (in shares)				250,000
Distribution paid-in-kind (in shares)				8,844
Ending balance (in shares)				258,844	0
Beginning balance				$ 0
Issuance of Preferred Units, net				164,587
Distribution paid-in-kind	$ 3,825	$ 3,769	$ 1,250	8,844
Ending balance				$ 173,431	$ 0

Net Income Per Common Unit Ne54

Net Income Per Common Unit Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Mar. 02, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Allocation of net income:
Net income (loss) from continuing operations		$ 30,741	$ 26,499	$ 25,857	$ 6,111	$ 3,811	$ 16,419	$ 48,633	$ 26,351	$ 89,208	$ 95,214	$ (260,171)
Less: income attributable to preferred unitholders										25,453	0	0
Less: net income (loss) from continuing operations and income attributable to preferred unitholders allocated to the general partner										1,275	1,629	(5,998)
Net income (loss) from continuing operations attributable to common unitholders										62,480	93,585	(254,173)
Net income (loss) from discontinued operations		(34)	(433)	133	(207)	(323)	7,112	(2,187)	(2,924)	(541)	1,678	(311,549)
Less: net income (loss) from discontinued operations attributable to the general partner										(11)	34	(6,230)
Net income (loss) from discontinued operations attributable to common unitholders										(530)	1,644	(305,319)
Net income (loss)		$ 30,707	$ 26,066	$ 25,990	$ 5,904	$ 3,488	$ 23,531	$ 46,446	$ 23,427	88,667	96,892	(571,720)
Less: net income (loss) and income attributable to preferred unitholders allocated to the general partner											1,663	(12,228)
Net income (loss) attributable to common unitholders										$ 61,950	$ 95,229	$ (559,492)
Weighted average common units—basic (in shares)		12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232
Basic net income (loss) from continuing operations per common unit										$ 5.11	$ 7.65	$ (20.78)
Basic net income (loss) from discontinued operations per common unit										(0.04)	0.13	(24.97)
Basic net income (loss) per common unit		$ 1.84	$ 1.48	$ 1.47	$ 0.28					$ 5.06	$ 7.78	$ (45.75)
Dilutive effect of Warrants (in shares)										300	0	0
Dilutive effect of Preferred Units (in shares)										9,418	0	0
Weighted average common units—diluted (in shares)		23,874	23,980	22,459	14,945					21,950	12,232	12,232
Less: net income (loss) from continuing operations allocated to the general partner										$ 1,784	$ 1,629	$ (5,998)
Diluted net income (loss) from continuing operations attributable to common unitholders										87,424	93,585	(254,173)
Diluted net income (loss) from discontinued operations attributable to common unitholders										(530)	1,644	(305,319)
Less: net income (loss) allocated to the general partner										1,773	1,663	(12,228)
Diluted net income (loss) attributable to common unitholders										$ 86,894	$ 95,229	$ (559,492)
Diluted net income (loss) from continuing operations per common unit										$ 3.98	$ 7.65	$ (20.78)
Diluted net income (loss) from discontinued operations per common unit										(0.02)	0.13	(24.97)
Diluted net income (loss) per common unit		$ 1.26	$ 1.07	$ 1.13	$ 0.28					$ 3.96	$ 7.78	$ (45.75)
Warrant Holders | Warrants at $34.00 Strike
Class of Warrant or Right, Warrants Issued	2,250
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 34

Segment Information - Additiona

Segment Information - Additional Information (Details) - segment	12 Months Ended
	Dec. 31, 2017	Jul. 31, 2013	Jan. 31, 2013
Segment Reporting Information [Line Items]
Number of operating segments	3
Ciner Wyoming
Segment Reporting Information [Line Items]
Percentage of partnership interest owned (percent)	49.00%	49.00%	48.51%

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues and other income	$ 100,822	$ 93,116	$ 91,570	$ 88,653	$ 86,311	$ 91,448	$ 119,317	$ 73,902	$ 374,161	$ 370,978	$ 432,748
Gain on asset sales, net	280	171	3,361	44	1,801	6,426	(1,071)	21,925	3,856	29,081	6,900
Operating and maintenance expenses (including affiliates)									136,516	130,546	152,266
General and administrative (including affiliates)									18,502	20,570	12,348
Depreciation, depletion and amortization (including affiliates)									35,993	46,272	60,916
Asset impairments	1,253	0	0	1,778	9,245	5,697	91	1,893	3,031	16,926	384,545
Other expense, net									94,767	90,531	89,744
Net income (loss) from continuing operations	30,741	$ 26,499	$ 25,857	$ 6,111	3,811	$ 16,419	$ 48,633	$ 26,351	89,208	95,214	(260,171)
Net income (loss) from discontinued operations									(541)	1,678	(311,549)
Capital expenditures									7,595	5,385	14,467
Total assets	1,389,164				1,448,649				1,389,164	1,448,649
Trade accounts receivable	39,331				37,959				39,331	37,959
Property taxes and other receivable	7,856				11,901				7,856	11,901
Corporate and Financing
Segment Reporting Information [Line Items]
Revenues and other income									0	0	0
Gain on asset sales, net									0	0	0
Operating and maintenance expenses (including affiliates)									0	0	0
General and administrative (including affiliates)									18,502	20,570	12,348
Depreciation, depletion and amortization (including affiliates)									0	0	0
Asset impairments									0	0	0
Other expense, net									94,074	90,531	89,744
Net income (loss) from continuing operations									(112,576)	(111,101)	(102,092)
Net income (loss) from discontinued operations									0	0	0
Capital expenditures									0	0	0
Trade accounts receivable	0				0				0	0
Property taxes and other receivable	0				32				0	32
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues and other income									0	0	0
Coal Royalty and Other
Segment Reporting Information [Line Items]
Revenues and other income									158,399	144,520	154,066
Coal Royalty and Other | Operating Segments
Segment Reporting Information [Line Items]
Revenues and other income									202,323	210,115	243,781
Gain on asset sales, net										29,068	6,936
Operating and maintenance expenses (including affiliates)									24,883	29,890	35,321
General and administrative (including affiliates)									0	0	0
Depreciation, depletion and amortization (including affiliates)									23,414	31,766	45,338
Asset impairments									2,967	15,861	378,327
Other expense, net									0	0	0
Net income (loss) from continuing operations									154,899	161,816	(208,248)
Net income (loss) from discontinued operations									0	0	0
Capital expenditures									0	5	428
Trade accounts receivable	16,355				18,791				16,355	18,791
Property taxes and other receivable	7,856				11,661				7,856	11,661
Coal Royalty and Other | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues and other income									295	150	21
Soda Ash
Segment Reporting Information [Line Items]
Revenues and other income									40,457	40,061	49,918
Soda Ash | Operating Segments
Segment Reporting Information [Line Items]
Revenues and other income									40,457	40,061	49,918
Gain on asset sales, net									0	0	0
Operating and maintenance expenses (including affiliates)									0	0	0
General and administrative (including affiliates)									0	0	0
Depreciation, depletion and amortization (including affiliates)									0	0	0
Asset impairments									0	0	0
Other expense, net									0	0	0
Net income (loss) from continuing operations									40,457	40,061	49,918
Net income (loss) from discontinued operations									0	0	0
Capital expenditures									0	0	0
Trade accounts receivable	0				0				0	0
Property taxes and other receivable	0				0				0	0
Soda Ash | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues and other income									0	0	0
Construction Aggregates
Segment Reporting Information [Line Items]
Revenues and other income									112,970	103,755	124,085
Construction Aggregates | Operating Segments
Segment Reporting Information [Line Items]
Revenues and other income									131,381	120,802	139,049
Gain on asset sales, net									311	13	(36)
Operating and maintenance expenses (including affiliates)									111,633	100,656	116,945
General and administrative (including affiliates)									0	0	0
Depreciation, depletion and amortization (including affiliates)									12,579	14,506	15,578
Asset impairments									64	1,065	6,218
Other expense, net									(693)	0	0
Net income (loss) from continuing operations									6,428	4,438	251
Net income (loss) from discontinued operations									0	0	0
Capital expenditures									7,595	5,380	14,039
Trade accounts receivable	22,976				19,168				22,976	19,168
Property taxes and other receivable	0				208				0	208
Construction Aggregates | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues and other income									(295)	(150)	$ (21)
Continuing Operations
Segment Reporting Information [Line Items]
Total assets	1,388,173				1,447,658				1,388,173	1,447,658
Continuing Operations | Corporate and Financing
Segment Reporting Information [Line Items]
Total assets	6,129				10,970				6,129	10,970
Continuing Operations | Coal Royalty and Other | Operating Segments
Segment Reporting Information [Line Items]
Total assets	945,237				990,172				945,237	990,172
Continuing Operations | Soda Ash | Operating Segments
Segment Reporting Information [Line Items]
Total assets	245,433				255,901				245,433	255,901
Continuing Operations | Construction Aggregates | Operating Segments
Segment Reporting Information [Line Items]
Total assets	191,374				190,615				191,374	190,615
Discontinued Operations
Segment Reporting Information [Line Items]
Total assets	991				991				991	991
Discontinued Operations | Corporate and Financing
Segment Reporting Information [Line Items]
Total assets	0				0				0	0
Discontinued Operations | Coal Royalty and Other | Operating Segments
Segment Reporting Information [Line Items]
Total assets	0				0				0	0
Discontinued Operations | Soda Ash | Operating Segments
Segment Reporting Information [Line Items]
Total assets	0				0				0	0
Discontinued Operations | Construction Aggregates | Operating Segments
Segment Reporting Information [Line Items]
Total assets	$ 0				$ 0				$ 0	$ 0

Discontinued Operations Summary

Discontinued Operations Summary of Financial Results of Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 31, 2016
Assets
Accounts receivable, net (including affiliates)	$ 991	$ 991
Total assets of discontinued operations	991	991
Liabilities
Other (including affiliates)	401	353
Total liabilities of discontinued operations	401	353
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Cash paid for interest	0	1,906	$ 2,755
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities	294	0	4,304
Discontinued Operations, Held-for-sale
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Oil and gas revenues and other income	38	16,486	48,750
Gain on asset sales	(289)	8,274	451
Total revenues and other income	(251)	24,760	49,201
Operating and maintenance expenses (including affiliates)	290	11,503	19,724
Depreciation, depletion and amortization	0	7,527	39,912
Asset impairments	0	564	297,049
Total operating expenses	290	19,594	356,685
Interest expense	0	(3,488)	(4,065)
Income (loss) from discontinued operations	(541)	1,678	(311,549)
Net Cash Provided by (Used in) Discontinued Operations [Abstract]
Cash paid for interest	0	1,906	2,755
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities	$ 0	0	1,645
Capital expenditures, Discontinued Operations		$ 1,400	$ 30,600
Disposal Group, Including Discontinued Operation, Consideration				$ 116,100

Equity Investment - Additional

Equity Investment - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended			36 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2015	Jul. 31, 2013	Jan. 31, 2013
Schedule of Equity Method Investments [Line Items]
Distributions from equity method Investment				$ 5,646	$ 0	$ 0
Weighted average useful life of assets (in years)				28 years
Reclassification of accumulated other comprehensive loss to income allocation				$ 700	900	700
Ciner Wyoming
Schedule of Equity Method Investments [Line Items]
Percentage of partnership interest owned (percent)				49.00%				49.00%	48.51%
Distributions from equity method Investment				$ 49,000	46,600	$ 46,800
Increase in fair value of property, plant and equipment				$ 145,600	$ 150,000
Anadarko Holding Company | Ciner Wyoming
Schedule of Equity Method Investments [Line Items]
Equity Investment Contingent Consideration Paid							$ 11,500
Anadarko Holding Company | Ciner Wyoming
Schedule of Equity Method Investments [Line Items]
Equity Investment Contingent Consideration Paid	$ 7,200	$ 3,800	$ 500

Equity Investment - Schedule o

Equity Investment - Schedule of Summarized Financial Information of Unaudited Financial Statements (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Net Income	$ 30,707	$ 26,066	$ 25,990	$ 5,904	$ 3,488	$ 23,531	$ 46,446	$ 23,427	$ 88,667	$ 96,892	$ (571,720)
Current assets	91,396				105,386				91,396	105,386
Current liabilities	120,549				189,151				120,549	189,151
Ciner Wyoming
Schedule of Equity Method Investments [Line Items]
Income allocation to NRP’s equity interests									44,846	44,882	54,709
Amortization of basis difference									(4,389)	(4,821)	(4,791)
Equity in earnings of unconsolidated investment									40,457	40,061	49,918
Sales									497,340	475,187	486,393
Gross profit									114,202	114,232	131,493
Net Income									91,523	91,596	$ 111,650
Current assets	180,433				134,616				180,433	134,616
Noncurrent assets	228,002				235,427				228,002	235,427
Current liabilities	56,219				55,396				56,219	55,396
Noncurrent liabilities	$ 148,401				$ 98,425				$ 148,401	$ 98,425

Inventory - Components of Inven

Inventory - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Aggregates	$ 6,209	$ 6,037
Supplies and parts	1,344	856
Total inventory	$ 7,553	$ 6,893

Plant and Equipment - Plant and

Plant and Equipment - Plant and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Plant and equipment at cost	$ 84,173	$ 79,171
Construction in process	803	557
Less accumulated depreciation	(38,806)	(30,285)
Total plant and equipment, net	$ 46,170	$ 49,443

Plant and Equipment - Additiona

Plant and Equipment - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended										12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Depreciation expense on plant and equipment											$ 10,300	$ 12,400	$ 15,900
Asset impairments	$ 1,253	$ 0	$ 0	$ 1,778	$ 9,245	$ 5,697	$ 91	$ 1,893			3,031	16,926	384,545
Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Asset impairments											$ 100	3,100	$ 7,700
Coal Plant
Property, Plant and Equipment [Line Items]
Asset impairments										$ 7,000		2,000
Construction Aggregates | Obsolete Plant and Equipment
Property, Plant and Equipment [Line Items]
Asset impairments									$ 700			$ 1,100

Mineral Rights - Mineral Rights

Mineral Rights - Mineral Rights (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Carrying Value	$ 1,346,309	$ 1,375,019
Accumulated Depletion	(462,424)	(466,827)
Net Book Value	883,885	908,192
Coal Mineral Rights
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Carrying Value	1,170,104	1,170,904
Accumulated Depletion	(436,964)	(420,032)
Net Book Value	733,140	750,872
Aggregate Mineral Rights
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Carrying Value	150,642	176,774
Accumulated Depletion	(16,836)	(39,056)
Net Book Value	133,806	137,718
Oil And Gas Mineral Rights
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Carrying Value	12,395	12,395
Accumulated Depletion	(7,158)	(6,289)
Net Book Value	5,237	6,106
Other Mineral Rights
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Carrying Value	13,168	14,946
Accumulated Depletion	(1,466)	(1,450)
Net Book Value	$ 11,702	$ 13,496

Mineral Rights - Additional Inf

Mineral Rights - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Proceeds from sale of assets									$ 1,982	$ 62,383	$ 14,529
Gain (loss) on asset sales	$ 280	$ 171	$ 3,361	$ 44	$ 1,801	$ 6,426	$ (1,071)	$ 21,925	3,856	29,081	6,900
Total depletion and amortization expense on mineral interests									22,200	29,800	40,400
Appalachian Basin [Member]
Proceeds from sale of assets										36,400
Gain (loss) on asset sales										18,600
Texas, Georgia, Tennessee [Member]
Gain (loss) on asset sales										1,500
Proceeds from Sale of Hard Mineral Reserves										10,000
Other Mineral Rights
Gain (loss) on asset sales									3,545	8,600	3,300
Proceeds from Sale of Hard Mineral Reserves									$ 1,000	$ 17,300	$ 3,500

Mineral Rights Schedule of Impa

Mineral Rights Schedule of Impairment Expense (Details) - USD ($) $ in Thousands	3 Months Ended											12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Asset impairments	$ 1,253	$ 0	$ 0	$ 1,778	$ 9,245	$ 5,697	$ 91	$ 1,893				$ 3,031	$ 16,926	$ 384,545
Coal Mineral Rights
Property, Plant and Equipment [Line Items]
Asset impairments					8,200	3,800			$ 8,200	$ 247,800	$ 1,500	595	12,088	257,468
Fair value of impaired assets					$ 0	$ 4,000			$ 400	28,400	$ 0		0	400
Oil And Gas Mineral Rights
Property, Plant and Equipment [Line Items]
Asset impairments												0	36	70,527
Fair value of impaired assets										13,000
Aggregate Mineral Rights
Property, Plant and Equipment [Line Items]
Asset impairments												2,372	1,677	43,402
Fair value of impaired assets										$ 13,100
Mining Properties and Mineral Rights
Property, Plant and Equipment [Line Items]
Asset impairments												$ 2,967	$ 13,801	$ 371,397

Goodwill and Intangible Asset66

Goodwill and Intangible Assets (Including Affiliate) - Intangible Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 86,336
Finite-Lived Intangible Assets, Including Related Parties, Gross		$ 86,336
Less accumulated amortization	(36,782)
Finite-Lived Intangible Assets, Including Related Parties, Accumulated Amortization		(33,289)
Total intangible assets, net	$ 49,554	3,236
Finite-Lived Intangible Assets, Including Related Parties, Net		$ 53,047

Goodwill and Intangible Asset67

Goodwill and Intangible Assets (Including Affiliate) - Estimated Amortization Expense (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2,018	$ 3,123
2,019	2,921
2,020	3,492
2,021	3,351
2,022	$ 3,351

Goodwill and Intangible Asset68

Goodwill and Intangible Assets (Including Affiliate) - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 01, 2014
Intangible Assets [Line Items]
Amortization expense—affiliate			$ 1,008	$ 3,185	$ 3,621
Amortization expense			$ 2,500	$ 800	1,000
Contractual Rights [Member]
Intangible Assets [Line Items]
Remaining amortization period for intangibles (in years)			25 years
Other Intangible Assets
Intangible Assets [Line Items]
Remaining amortization period for intangibles (in years)			14 years
Construction Aggregates
Intangible Assets [Line Items]
Acquisition of goodwill		$ 52,000
Increase (decrease) in goodwill					$ (46,500)
Goodwill						$ 5,500
Goodwill impairment loss	$ 5,500

Debt - Long-Term Debt (Detail)

Debt - Long-Term Debt (Detail) - USD ($)	Dec. 31, 2017	Mar. 02, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Senior Note issue percentage		98.75%
Principal balance	$ 827,844,000		$ 1,138,932,000
Net unamortized debt discount	(1,661,000)		(1,322,000)
Net unamortized debt issuance costs	(16,835,000)		(7,339,000)
Total debt	809,348,000		1,130,271,000
Less - current portion of long term debt	79,740,000		140,037,000
Total long-term debt, net	729,608,000		990,234,000
NRP LP | 10.5% senior notes, with semi-annual interest payments in March and September, maturing March 2022 [Member]
Debt Instrument [Line Items]
Principal balance	$ 345,638,000		0
NRP LP | Senior Notes Due Two Zero Two Two [Member]
Debt Instrument [Line Items]
Interest rate	10.50%
Senior Notes, Face Amount	$ 345,638,000
NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018
Debt Instrument [Line Items]
Interest rate	9.125%
Senior Notes, Face Amount	$ 425,000,000
Principal balance	0		425,000,000
Opco | Floating Rate Revolving Credit Facility Due April Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Floating rate revolving credit facility	150,000,000
Principal balance	$ 60,000,000		210,000,000
Opco | 4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018
Debt Instrument [Line Items]
Interest rate	4.91%
Principal balance	$ 4,586,000		$ 9,187,000
Opco | 8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019 [Member]
Debt Instrument [Line Items]
Interest rate	8.38%		8.38%
Principal balance	$ 42,670,000		$ 64,029,000
Opco | 5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020 [Member]
Debt Instrument [Line Items]
Interest rate	5.05%
Principal balance	$ 22,946,000		30,633,000
Opco | 5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023 [Member]
Debt Instrument [Line Items]
Interest rate	5.55%
Principal balance	$ 16,115,000		18,825,000
Opco | 4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2023 [Member]
Debt Instrument [Line Items]
Interest rate	4.73%
Principal balance	$ 44,693,000		52,204,000
Opco | 5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024 [Member]
Debt Instrument [Line Items]
Interest rate	5.82%
Principal balance	$ 104,520,000		$ 119,524,000
Opco | 8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 [Member]
Debt Instrument [Line Items]
Interest rate	8.92%		8.92%
Principal balance	$ 31,733,000		$ 36,272,000
Opco | 5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 [Member]
Debt Instrument [Line Items]
Interest rate	5.03%
Principal balance	$ 120,547,000		134,035,000
Opco | 5.18% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026 [Member]
Debt Instrument [Line Items]
Interest rate	5.18%
Principal balance	$ 34,396,000		38,262,000
Opco | Utility Local Improvement Obligation Due March Two Zero Two One [Member]
Debt Instrument [Line Items]
Interest rate	5.31%
Principal balance	$ 0		$ 961,000
Senior Notes Offering Price Two [Member] | NRP LP | Senior Notes Due Two Zero Two Two [Member]
Debt Instrument [Line Items]
Floating rate revolving credit facility	$ 240,638,000
Senior Note issue percentage	100.00%
Senior Notes Offering Price Two [Member] | NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018
Debt Instrument [Line Items]
Floating rate revolving credit facility	$ 125,000,000
Senior Note issue percentage	99.50%
Senior Notes Offering Price One [Member] | NRP LP | Senior Notes Due Two Zero Two Two [Member]
Debt Instrument [Line Items]
Floating rate revolving credit facility	$ 105,000,000
Senior Note issue percentage	98.75%
Senior Notes Offering Price One [Member] | NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018
Debt Instrument [Line Items]
Floating rate revolving credit facility	$ 300,000,000
Senior Note issue percentage	99.007%

Debt - Additional Information (

Debt - Additional Information (Detail)

Oct. 02, 2017USD ($)

Apr. 03, 2017USD ($)

Mar. 02, 2017USD ($)

Jun. 30, 2016

Jun. 30, 2017

Mar. 31, 2017USD ($)

Dec. 31, 2017USD ($)$ / shares

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2018USD ($)

Jul. 31, 2013

Jan. 31, 2013

Debt Instrument [Line Items]

Senior Note issue percentage

98.75%

Debt issuance cost capitalized

$ 16,835,000

$ 7,339,000

Principal balance

827,844,000

1,138,932,000

Debt Instrument, Percentage of Principal Eligible for Redemption

35.00%

Debt Instrument, Discount on Debt Issuance, as a Percent

1.25%

Debt Instrument, Net Redemption Premium, Percent

5.813%

Debt Instrument, Redemption Premium Above Par, Percentage

4.563%

Debt Instrument, Fee on Redemption, Percent

1.25%

Long-term Debt

809,348,000

1,130,271,000

Senior Notes due 2022 [Member]

Debt Instrument [Line Items]

Principal balance

330,404,000

0

Senior Notes due 2022 [Member] | Senior Notes

Debt Instrument [Line Items]

Rate of senior notes

10.50%

Senior Notes, Face Amount

$ 346,000,000

Proceeds from Issuance of Secured Debt

$ 105,000,000

Debt Instrument Redemption Price Percentage Of Principal Remaining After Redemption

65.00%

Debt Instrument Redemption Price At Change Of Control Event As Percentage Of Principal Amount

101.00%

Senior Notes due 2018

Debt Instrument [Line Items]

Principal balance

$ 0

$ 420,097,000

Senior Notes due 2018 | Senior Notes

Debt Instrument [Line Items]

Senior Notes, Face Amount

$ 241,000,000

Debt Instrument, Repurchased Face Amount

$ 90,000,000

Debt Instrument, Redemption Price, Percentage

104.563%

Debt extinguished

$ 94,400,000

$ 241,000,000

Debt Instrument, Redemption Premium Above Par, Percentage

4.563%

Ciner Wyoming

Debt Instrument [Line Items]

Percentage of partnership interest owned (percent)

49.00%

49.00%

48.51%

Ciner Wyoming | Revolving Credit Facility

Debt Instrument [Line Items]

Percentage of partnership interest owned (percent)

49.00%

NRP LP | 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018

Debt Instrument [Line Items]

Rate of senior notes

9.125%

Senior Notes, Face Amount

$ 425,000,000

Principal balance

$ 0

$ 425,000,000

NRP LP | Senior Notes

Debt Instrument [Line Items]

Rate of senior notes

10.50%

Long-term Debt

$ 344,000,000

Opco

Debt Instrument [Line Items]

Ratio of consolidated EBITDDA to consolidated fixed charges

3.5

Percentage of consolidated net tangible assets debt of subsidiaries not permitted to exceed

10.00%

Opco | Revolving Credit Facility

Debt Instrument [Line Items]

Debt Instrument, Interest Rate During Period

5.32%

4.46%

Debt issuance cost capitalized

$ 4,600,000

$ 4,000,000

Debt Instrument, Asset Sales Proceeds, Required to Repay Outstanding Debt, Percent

75.00%

Ratio of consolidated EBITDDA to consolidated fixed charges

3.5

Secured Debt

$ 649,700,000

$ 673,000,000

Commitment fee (as a percent)

0.50%

Opco | 8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019 [Member]

Debt Instrument [Line Items]

Rate of senior notes

8.38%

8.38%

Principal balance

$ 42,670,000

$ 64,029,000

Opco | 8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024 [Member]

Debt Instrument [Line Items]

Rate of senior notes

8.92%

8.92%

Principal balance

$ 31,733,000

$ 36,272,000

Opco | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Covenant, Asset Sales

300,000,000

Debt Instrument, Asset Sales Proceeds, Required to Repay Outstanding Debt, Percent

25.00%

25.00%

Principal balance

$ 422,200,000

503,000,000

Principal payments on its senior notes

(80,800,000)

$ (82,900,000)

$ (80,800,000)

$ (80,800,000)

Partnership leverage ratio

3.75

Additional interest accrue

2.00%

Opco | Floating Rate Revolving Credit Facility Due April Two Thousand Twenty [Member]

Debt Instrument [Line Items]

Floating rate revolving credit facility

150,000,000

Principal balance

60,000,000

$ 210,000,000

Line of Credit Facility, Remaining Borrowing Capacity

$ 90,000,000

Opco | Floating Rate Revolving Credit Facility Due April Two Thousand Twenty Two [Member]

Debt Instrument [Line Items]

Distribution amount (in dollars per share) | $ / shares

$ 0.45

Opco | Maximum

Debt Instrument [Line Items]

Ratio of consolidated indebtedness to consolidated EBITDDA

4

Opco | Scenario, Forecast [Member] | Floating Rate Revolving Credit Facility Due April Two Thousand Twenty [Member]

Debt Instrument [Line Items]

Floating rate revolving credit facility

$ 100,000,000

Opco | Federal Funds Rate [Member] | Revolving Credit Facility

Debt Instrument [Line Items]

Basis spread on variable rate (percent)

0.50%

Opco | London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility

Debt Instrument [Line Items]

Basis spread on variable rate (percent)

1.00%

Opco | London Interbank Offered Rate (LIBOR) [Member] | Maximum | Revolving Credit Facility Basis Spread Condition One [Member] | Revolving Credit Facility

Debt Instrument [Line Items]

Additional basis spread (percent)

3.50%

Opco | London Interbank Offered Rate (LIBOR) [Member] | Maximum | Revolving Credit Facility Basis Spread Condition Two [Member] | Revolving Credit Facility

Debt Instrument [Line Items]

Additional basis spread (percent)

4.50%

Opco | London Interbank Offered Rate (LIBOR) [Member] | Minimum | Revolving Credit Facility Basis Spread Condition One [Member] | Revolving Credit Facility

Debt Instrument [Line Items]

Additional basis spread (percent)

2.50%

Opco | London Interbank Offered Rate (LIBOR) [Member] | Minimum | Revolving Credit Facility Basis Spread Condition Two [Member] | Revolving Credit Facility

Debt Instrument [Line Items]

Additional basis spread (percent)

3.50%

Debt Instrument, Redemption, Period Two | Senior Notes due 2022 [Member] | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

105.25%

Debt Instrument, Redemption, Period Three | Senior Notes due 2022 [Member] | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

102.625%

Debt Instrument, Redemption, Period Four [Member] | Senior Notes due 2022 [Member] | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

100.00%

Debt Instrument, Redemption, Period One | Senior Notes due 2022 [Member] | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

110.50%

Restricted Payments Covenant [Member] | Senior Notes due 2022 [Member] | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Covenant, Consolidated Leverage Ratio, Maximum

4

Debt Instrument, Covenant, Dividend Payment Restriction, Percent

50.00%

Debt Incurrence Covenant [Member] | Senior Notes due 2022 [Member] | Senior Notes

Debt Instrument [Line Items]

Debt Instrument, Covenant, Consolidated Leverage Ratio, Maximum

3

Debt Instrument, Covenant, Debt Limit Numerator

$ 150,000,000

Dividend at or Below $0.45 per Share [Member] | Opco | Floating Rate Revolving Credit Facility Due April Two Thousand Twenty Two [Member]

Debt Instrument [Line Items]

Debt Instrument, Covenant, Maximum Leverage Ratio

4

4

Dividend Above $0.45 per Share [Member] | Opco | Floating Rate Revolving Credit Facility Due April Two Thousand Twenty Two [Member]

Debt Instrument [Line Items]

Debt Instrument, Covenant, Maximum Leverage Ratio

3

Debt - Principal Payments Due (

Debt - Principal Payments Due (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
2,018	$ 80,385
2,019	75,799
2,020	114,464
2,021	46,815
2,022	392,453
Thereafter	117,928
Principal Payments	827,844
NRP LP | Senior Notes
Debt Instrument [Line Items]
2,018	0
2,019	0
2,020	0
2,021	0
2,022	345,638
Thereafter	0
Principal Payments	$ 345,638
Rate of senior notes	10.50%
Opco | Senior Notes
Debt Instrument [Line Items]
2,018	$ 80,385
2,019	75,799
2,020	54,464
2,021	46,815
2,022	46,815
Thereafter	117,928
Principal Payments	422,206
Opco | Revolving Credit Facility
Debt Instrument [Line Items]
2,018	0
2,019	0
2,020	60,000
2,021	0
2,022	0
Thereafter	0
Principal Payments	$ 60,000

Fair Value Measurements - Contr

Fair Value Measurements - Contractual Override, Note Receivable and Long-Term Debt (Detail) - USD ($)	Dec. 31, 2017	Mar. 02, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value	$ 827,844,000		$ 1,138,932,000
Contracts receivable (including affiliates), current and long-term	43,826,000		46,742,000
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	$ 0
Fair Value, Inputs, Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Contracts receivable (including affiliates), current and long-term	30,517,000		32,554,000
Senior Notes due 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value	0		420,097,000
Senior Notes due 2018 | Fair Value, Inputs, Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Estimated Fair Value	0		412,250,000
Senior Notes due 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value	330,404,000		0
Senior Notes due 2022 [Member] | Fair Value, Inputs, Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Estimated Fair Value	366,376,000		0
Opco Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value	418,944,000		500,174,000
Opco Senior Notes | Fair Value, Inputs, Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Estimated Fair Value	447,538,000		488,814,000
Opco Revolving Credit Facility And Term Loan Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value	60,000,000		210,000,000
Opco Revolving Credit Facility And Term Loan Facility | Fair Value, Inputs, Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Estimated Fair Value	$ 60,000,000		$ 210,000,000

Related Party Transactions - Su

Related Party Transactions - Summary of Reimbursements (Detail) - USD ($) $ in Thousands, shares in Millions	May 09, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Operating and maintenance expenses—affiliates, net		$ 9,534	$ 10,925	$ 15,323
General and administrative—affiliates		4,989	3,591	5,312
Cline Affiliates
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	0.5
Operating and maintenance expenses—affiliates, net		452	1,347	1,413
Affiliated Entity | Western Pocahontas Properties and Quintana Minerals Corporation
Related Party Transaction [Line Items]
Operating and maintenance expenses—affiliates, net		$ 7,606	$ 9,891	$ 10,063

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Revenues and other income	$ 100,822	$ 93,116	$ 91,570	$ 88,653	$ 86,311	$ 91,448	$ 119,317	$ 73,902	$ 374,161	$ 370,978	$ 432,748
Gain on reserve swaps											9,300
Operating and maintenance expense									194,042	214,314	610,075
Operating and maintenance expenses—affiliates, net									9,534	10,925	15,323
Operating and maintenance expenses									126,982	119,621	136,943
Accounts receivable, net	47,026				43,202				47,026	43,202
Accounts receivable—affiliates, net	161				6,658				161	6,658
Long-term contracts receivable	40,776				0				40,776	0
Long-term contracts receivable—affiliates	0				43,785				0	43,785
Deferred revenue	100,605				44,931				100,605	44,931
Deferred revenue—affiliates	0				71,632				0	71,632
Amount payable to related parties	562				940				562	940
General and administrative—affiliates									4,989	3,591	5,312
Quintana Minerals
Related Party Transaction [Line Items]
Operating and maintenance expenses—affiliates, net										1,300	700
Amount payable to related parties	400				400				400	400
Western Pocahontas Properties
Related Party Transaction [Line Items]
Amount payable to related parties	100				600				100	600
Cline Affiliates
Related Party Transaction [Line Items]
Operating and maintenance expenses—affiliates, net									452	1,347	1,413
Cline Affiliates
Related Party Transaction [Line Items]
Accounts receivable, net	6,127				0				6,127	0
Accounts receivable—affiliates, net	0				6,496				0	6,496
Deferred revenue	53,778				0				53,778	0
Deferred revenue—affiliates	0				71,632				0	71,632
Foresight Energy Lp
Related Party Transaction [Line Items]
Operating and maintenance expense									1,066	0	0
Operating and maintenance expenses									1,518	1,347	1,413
Foresight Energy Lp | Affiliated Entity
Related Party Transaction [Line Items]
Lease receivable, next year	5,000								5,000
Operating Leases, Future Minimum Payments Receivable, Per Quarter	1,250								1,250
Foresight Energy Lp | Coal Sales
Related Party Transaction [Line Items]
Revenues									43,273	0	0
Coal royalty and other—affiliates									27,216	63,355	86,614
Revenues and other income									70,489	63,355	86,614
Sugar Camp
Related Party Transaction [Line Items]
Projected remaining payments	71,452				76,424				71,452	76,424
Unearned income	28,366				31,803				28,366	31,803
Long-term contracts receivable	40,776				0				40,776	0
Long-term contracts receivable—affiliates	0				43,785				0	43,785
Sugar Camp | Affiliated Entity
Related Party Transaction [Line Items]
Lease receivable, year two	5,000								5,000
Lease receivable, year three	5,000								5,000
Lease receivable, year four	5,000								5,000
Lease receivable, year five	5,000								5,000
Corsa
Related Party Transaction [Line Items]
Accounts receivable—affiliates, net	200				200				200	200
Royalty Revenue from Coal									1,300	2,200	3,100
Western Pocahontas Properties Limited Partnership | Affiliated Entity
Related Party Transaction [Line Items]
Operating and maintenance expenses—affiliates, net									1,500	700	$ 400
Other assets—affiliate	$ 200				1,000				200	1,000
Quinwood Coal Company [Member]
Related Party Transaction [Line Items]
Deferred Revenue, Revenue Recognized									$ 900
Discontinued Operations, Held-for-sale | Quintana Minerals
Related Party Transaction [Line Items]
Amount payable to related parties					$ 100					$ 100

Major Customers (Detail)

Major Customers (Detail) - Foresight Energy Lp - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Revenues	$ 70,489	$ 63,355	$ 86,614
Sales Revenue | Customer Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	18.60%	15.80%	19.70%

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended	36 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2017	Dec. 31, 2015	Jul. 31, 2013	Jan. 31, 2013
Lawsuit Against Macoupin Energy, LLC
Commitments And Contingencies [Line Items]
Damages sought, value				$ 9.5
Anadarko Holding Company
Commitments And Contingencies [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High							$ 50
Ciner Wyoming | Anadarko Holding Company
Commitments And Contingencies [Line Items]
Equity Investment Contingent Consideration Paid					$ 11.5
Ciner Wyoming
Commitments And Contingencies [Line Items]
Percentage of partnership interest owned (percent)				49.00%		49.00%	48.51%
Ciner Wyoming | Anadarko Holding Company
Commitments And Contingencies [Line Items]
Equity Investment Contingent Consideration Paid	$ 7.2	$ 3.8	$ 0.5
Pending Litigation | Lawsuit Against Hillsboro Energy LLC
Commitments And Contingencies [Line Items]
Minimum quarterly deficiency payments				$ 7.5
Loss contingency				76
Pending Litigation | Minimum | Anadarko Holding Company
Commitments And Contingencies [Line Items]
Minimum deficiency payments				0
Pending Litigation | Maximum | Anadarko Holding Company
Commitments And Contingencies [Line Items]
Minimum deficiency payments				$ 40

Deferred Revenue and Deferred77

Deferred Revenue and Deferred Revenue - Affiliate Schedule of Deferred Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred Revenue Arrangement [Line Items]
Deferred revenue	$ 100,605	$ 44,931
Deferred revenue—affiliates	0	71,632
Deferred Revenue, Including Related Party	100,605	116,563
Coal Royalty and Other
Deferred Revenue Arrangement [Line Items]
Deferred Revenue, Revenue Recognized	16,767	49,284	$ 3,451
Deferred Revenue, Revenue Recognized, Including Related Party	30,822	64,591	15,489
Coal Royalty and Other | Affiliated Entity
Deferred Revenue Arrangement [Line Items]
Deferred Revenue, Revenue Recognized	14,055	15,307	12,038
Lease Modifications of Existing Coal Royalty Leases
Deferred Revenue Arrangement [Line Items]
Deferred Revenue, Revenue Recognized	$ 3,400	$ 40,500	$ 100

Unit-Based Compensation Additio

Unit-Based Compensation Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of Grants (in years)	4 years
Grant date fair value			$ 4.2
Compensation expense	$ 0.3	$ 1.4	(3.4)
Unaccrued Cost Associated With Outstanding Grants And Related Distribution Equivalent Rights	0.2	0.8
General Partner
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payments of Stock Issuance Costs	$ 1.8	$ 1.5	$ 4.4
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of trading days (in days)	20 days

Unit-Based Compensation Summary

Unit-Based Compensation Summary of Activity in Outstanding Grants (Details)	12 Months Ended
	Dec. 31, 2017shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding grants at beginning of period (in shares)	86,000
Grants during the period (in shares)	0
Grants vested and paid during the period (in shares)	(28,000)
Forfeitures during the period (in shares)	(5,000)
Outstanding grants at the end of the period (in shares)	53,000

Supplemental Quarterly Inform80

Supplemental Quarterly Information (Unaudited) - Selected Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Oct. 02, 2017	Mar. 02, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues (including affiliates)			$ 100,822	$ 93,116	$ 91,570	$ 88,653	$ 86,311	$ 91,448	$ 119,317	$ 73,902	$ 374,161	$ 370,978	$ 432,748
Gain (loss) on asset sales			280	171	3,361	44	1,801	6,426	(1,071)	21,925	3,856	29,081	6,900
Asset impairments			1,253	0	0	1,778	9,245	5,697	91	1,893	3,031	16,926	384,545
Income from operations			49,998	46,531	50,404	37,042	27,106	38,907	70,741	48,991	183,975	185,745	(170,427)
Write off of Deferred Debt Issuance Cost			0	0	132						7,939
Loss on extinguishment of debt			0	0		0					4,107	0	0
Net income (loss) from continuing operations			30,741	26,499	25,857	6,111	3,811	16,419	48,633	26,351	89,208	95,214	(260,171)
Net income (loss) from discontinued operations			(34)	(433)	133	(207)	(323)	7,112	(2,187)	(2,924)	(541)	1,678	(311,549)
Net Income			30,707	26,066	25,990	5,904	3,488	23,531	46,446	23,427	88,667	96,892	(571,720)
Net income (loss) attributable to common unitholders and general partner			$ 22,942	$ 18,416	$ 18,452	$ 3,404	$ 3,488	$ 23,531	$ 46,446	$ 23,427	$ 63,214	$ 96,892	$ (571,720)
Basic net income (loss) per common unit			$ 1.84	$ 1.48	$ 1.47	$ 0.28					$ 5.06	$ 7.78	$ (45.75)
Diluted net income (loss) per common unit			$ 1.26	$ 1.07	$ 1.13	$ 0.28					$ 3.96	$ 7.78	$ (45.75)
Weighted average number of common units outstanding (basic)			12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232	12,232
Weighted average number of common units outstanding (diluted)			23,874	23,980	22,459	14,945					21,950	12,232	12,232
Net Income (Loss), Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax							$ 0.28	$ 1.89	$ 3.73	$ 1.88		$ 7.78
Debt Instrument, Redemption Premium Above Par, Percentage		4.563%
Leasing Arrangement
Deferred Revenue, Revenue Recognized									$ 35,000
Senior Notes | Senior Notes due 2018
Write off of Deferred Debt Issuance Cost						$ 7,807
Debt extinguished	$ 94,400					$ 241,000
Loss on extinguishment of debt					$ 4,107
Debt Instrument, Redemption Premium Above Par, Percentage					4.563%

Uncategorized Items - nrp-20171

Label	Element	Value
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents	us-gaap_DisposalGroupIncludingDiscontinuedOperationCashAndCashEquivalents	$ 1,105,000