Foresight Energy (FELPQ) 10-K 1 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 24, 2017	Jun. 30, 2016
Document And Entity Information [Line Items]
Entity Registrant Name	Foresight Energy LP
Entity Central Index Key	1,540,729
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2,016
Trading Symbol	FELP
Document Fiscal Period Focus	FY
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Public Float			$ 41,702,566
Common Units
Document And Entity Information [Line Items]
Entity Units Outstanding		66,104,908
Subordinated Units
Document And Entity Information [Line Items]
Entity Units Outstanding		64,954,691

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 103,690	$ 17,538
Accounts receivable	54,905	61,325
Due from affiliates	16,891	16,615
Financing receivables - affiliate	2,904	2,689
Inventories, net	43,052	50,652
Prepaid expenses	8,482	5,498
Prepaid royalties	3,136	5,386
Deferred longwall costs	13,310	18,476
Coal derivative assets	7,650	26,596
Other current assets	12,961	5,565
Total current assets	266,981	210,340
Property, plant, equipment and development, net	1,318,937	1,433,193
Due from affiliates	1,843	2,691
Financing receivables - affiliate	67,235	70,139
Prepaid royalties	13,765	70,300
Coal derivative assets		22,027
Other assets	20,250	12,493
Total assets	1,689,011	1,821,183
Current liabilities:
Current portion of long-term debt and capital lease obligations	368,993	1,434,566
Current portion of sale-leaseback financing arrangements	1,372
Accrued interest	29,760	24,574
Accounts payable	60,971	55,192
Accrued expenses and other current liabilities	43,592	35,807
Asset retirement obligations	7,273	18
Due to affiliates	20,904	8,536
Total current liabilities	532,865	1,558,693
Long-term debt and capital lease obligations	1,022,070
Sale-leaseback financing arrangements	190,497	193,434
Asset retirement obligations	37,644	43,277
Warrant liability	51,169
Other long-term liabilities	9,359	6,896
Total liabilities	1,843,604	1,802,300
Limited partners' capital (deficit):
Total limited partners' (deficit) capital	(154,593)	20,599
Noncontrolling interests		(1,716)
Total partners' (deficit) capital	(154,593)	18,883
Total liabilities and partners' (deficit) capital	1,689,011	1,821,183
Common Units
Limited partners' capital (deficit):
Total limited partners' (deficit) capital	100,628	186,660
Subordinated Units
Limited partners' capital (deficit):
Total limited partners' (deficit) capital	$ (255,221)	$ (166,061)

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares shares in Thousands	Dec. 31, 2016	Dec. 31, 2015
Common Units
Capital units, Outstanding	66,105	65,192
Subordinated Units
Capital units, Outstanding	64,955	64,955

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues
Coal sales	$ 866,628	$ 979,179	$ 1,109,404
Other revenues	9,204	5,674
Total revenues	875,832	984,853	1,109,404
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)	423,995	509,170	449,905
Cost of coal purchased	13,541	17,444	18,232
Transportation	139,659	171,733	221,178
Depreciation, depletion and amortization	164,212	195,415	169,767
Accretion on asset retirement obligations	3,376	2,267	1,621
Selling, general and administrative	25,265	31,357	33,683
Long-lived asset impairments	74,575	12,592	34,700
Transition and reorganization costs	6,889	21,433
Loss (gain) on commodity derivative contracts	23,752	(45,691)	(76,330)
Other operating income, net	(22,161)	(13,424)	(2,837)
Operating income	22,729	82,557	259,485
Other expenses:
Interest expense, net	149,201	117,311	113,030
Debt restructuring costs	21,821	3,930
Change in fair value of warrants	17,124
Loss on early extinguishment of debt	13,203		4,979
Net (loss) income	(178,620)	(38,684)	141,476
Less: net income attributable to noncontrolling interests	169	770	3,909
Net (loss) income attributable to controlling interests	(178,789)	(39,454)	137,567
Less: net income attributable to predecessor equity		23	67,375
Net (loss) income available to limited partner units - basic and diluted:
Net (loss) income attributable to limited partner units	(178,789)	$ (39,477)	$ 70,192
Weighted average limited partner units outstanding - basic and diluted:
Distributions declared per limited partner unit		$ 1.17	$ 0.38
Common Units
Net (loss) income available to limited partner units - basic and diluted:
Net (loss) income attributable to limited partner units	$ (90,015)	$ (16,043)	$ 35,154
Net (loss) income per limited partner unit - basic and diluted	$ (1.37)	$ (0.25)	$ 0.54
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted	65,829	65,098	64,790
Subordinated Units
Net (loss) income available to limited partner units - basic and diluted:
Net (loss) income attributable to limited partner units	$ (88,774)	$ (23,434)	$ 35,038
Net (loss) income per limited partner unit - basic and diluted	$ (1.37)	$ (0.36)	$ 0.54
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted	64,955	64,934	64,739

Consolidated Statements of Part

Consolidated Statements of Partners' (Deficit) Capital - USD ($) $ in Thousands	Total	Noncontrolling Interest	Limited PartnersCommon Units	Limited PartnersSubordinated Units
Beginning Balance (Predecessor Equity (Deficit)) at Dec. 31, 2013	$ (104,407)
Beginning Balance at Dec. 31, 2013	(95,163)	$ 9,244
Net (loss) income | Predecessor Equity (Deficit)	67,375
Net (loss) income	141,476	3,909	$ 35,154	$ 35,038
Non-cash distributions | Predecessor Equity (Deficit)	(12,187)
Non-cash distributions	(12,187)
Contribution of net assets to Foresight Energy LP | Predecessor Equity (Deficit)	104,878
Contribution of net assets to Foresight Energy LP			(51,354)	$ (53,524)
Issuance of common units, net of offering costs	322,813		$ 322,813
Issuance of common units, net of offering costs (in units)			64,738,895	64,738,895
Cash distributions | Predecessor Equity (Deficit)	(4,949)
Cash distributions	(174,391)	(5,222)	$ (71,537)	$ (92,683)
Equity-based compensation	5,024		$ 5,024
Issuance of equity-based awards			92,417
Distribution equivalent rights on LTIP awards	(231)		$ (231)
Net settlement of withholding taxes on issued LTIP awards	(944)		(944)
Ending Balance (Predecessor Equity (Deficit)) at Dec. 31, 2014	50,710
Ending Balance at Dec. 31, 2014	186,397	7,931	$ 238,925	$ (111,169)
Ending Balance (in units) at Dec. 31, 2014			64,831,312	64,738,895
Net (loss) income | Predecessor Equity (Deficit)	23
Net (loss) income	(38,684)	770	$ (16,043)	$ (23,434)
Capital contribution from Foresight Reserves LP	11,319		5,665	5,654
Contribution of net assets to Foresight Energy LP | Predecessor Equity (Deficit)	(50,733)
Contribution of net assets to Foresight Energy LP		(9,898)	25,643	34,988
Cash distributions	(152,352)	(519)	(79,733)	$ (72,100)
Equity-based compensation	13,704		$ 13,704
Issuance of equity-based awards			361,077	215,796
Distribution equivalent rights on LTIP awards	(623)		$ (623)
Net settlement of withholding taxes on issued LTIP awards	(878)		(878)
Ending Balance at Dec. 31, 2015	18,883	(1,716)	$ 186,660	$ (166,061)
Ending Balance (in units) at Dec. 31, 2015			65,192,389	64,954,691
Net (loss) income	(178,620)	169	$ (90,015)	$ (88,774)
Capital contribution from Foresight Reserves LP	1,046		525	521
Cash distributions	(182)	(182)
Deemed distribution - acquisition of variable interest entities	(100)	$ 1,729	(922)	(907)
Equity-based compensation	5,106		$ 5,106
Issuance of equity-based awards			912,284
Distribution equivalent rights on LTIP awards	84		$ 84
Net settlement of withholding taxes on issued LTIP awards	(810)		(810)
Ending Balance at Dec. 31, 2016	$ (154,593)		$ 100,628	$ (255,221)
Ending Balance (in units) at Dec. 31, 2016			66,104,673	64,954,691

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities
Net (loss) income	$ (178,620)	$ (38,684)	$ 141,476
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	164,212	195,415	169,767
Amortization of debt issuance costs and debt discount	12,580	6,878	7,022
Equity-based compensation	5,106	13,704	4,749
Loss (gain) on commodity derivative contracts	23,752	(45,691)	(76,330)
Settlements of commodity derivative contracts	12,644	61,223	19,204
Realized gains on commodity derivative contracts included in investing activities		(19,073)	(7,345)
Change in fair value of warrants	17,124
Long-lived asset impairments	74,575	12,592	34,700
Transition and reorganization expenses paid by Foresight Reserves (affiliate)	2,333	10,032
Current period interest expense converted into debt	31,484
Non-cash debt extinguishment expense	11,124		4,681
Other	4,897	5,208	2,097
Changes in operating assets and liabilities:
Accounts receivable	6,420	19,586	(21,921)
Due from/to affiliates, net	12,940	(25,345)	5,930
Inventories	7,858	27,994	(13,787)
Prepaid expenses and other current assets	(7,608)	(250)	(7,807)
Prepaid royalties	(15,790)	(18,945)	(23,475)
Commodity derivative assets and liabilities	3,938	(1,911)	(1,891)
Accounts payable	5,779	(5,014)	9,424
Accrued interest	22,905	(562)	(2,509)
Accrued expenses and other current liabilities	5,537	874	1,189
Other	2,030	2,381	(4,392)
Net cash provided by operating activities	225,220	200,412	240,782
Cash flows from investing activities
Investment in property, plant, equipment and development	(54,584)	(85,026)	(229,725)
Investment in financing arrangements with Murray Energy (affiliate)		(75,000)
Settlement of certain coal derivatives		19,073	7,345
Return of investment on financing arrangements with Murray Energy (affiliate)	2,689	2,172
Acquisition of an affiliate	(100)		(3,822)
Proceeds from sale of equipment	4,366		1,619
Net cash used in investing activities	(47,629)	(138,781)	(224,583)
Cash flows from financing activities
Net change in borrowings under revolving credit facility		33,000	60,500
Net change in borrowings under A/R securitization program	(26,800)	41,000
Proceeds from other long-term debt and capital lease obligations		59,325	85,620
Payments on other long-term debt and capital lease obligations	(45,692)	(44,440)	(307,607)
Payments on short-term debt	(739)	(2,559)
Distributions paid	(182)	(152,352)	(174,391)
Proceeds from issuance of common units (net of underwriters' discount)			329,875
Initial public offering costs paid (other than underwriters' discount)			(7,206)
Debt issuance costs paid	(15,735)	(2,751)	(297)
Other	(2,291)	(1,825)	(971)
Net cash used in financing activities	(91,439)	(70,602)	(14,477)
Net increase (decrease) in cash and cash equivalents	86,152	(8,971)	1,722
Cash and cash equivalents, beginning of period	17,538	26,509	24,787
Cash and cash equivalents, end of period	$ 103,690	$ 17,538	$ 26,509

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	1. Organization and Basis of Presentation Foresight Energy LLC (“FELLC”), a perpetual-term Delaware limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves, LP (“Foresight Reserves”) owned 99.333% of FELLC and a member of FELLC’s management owned 0.667%. On June 23, 2014, in connection with the initial public offering (“IPO”) of Foresight Energy LP (“FELP”), Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common and subordinated units in FELP. FELP has been managed by Foresight Energy GP LLC (“FEGP”) since the IPO. On April 16, 2015, Murray Energy Corporation (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% noncontrolling economic interest in FEGP and all of the outstanding subordinated units of FELP, representing a 50% ownership percentage of the Partnership’s limited partner units. As used hereafter in this report, the terms “Foresight Energy LP,” “FELP,” the “Partnership,” “we,” “us” or like terms, refer to the combined consolidated results of Foresight Energy LP, and FELLC and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated. The information presented in this Annual Report on Form 10-K contains, for all periods presented, the combined consolidated financial results of Foresight Energy LP, FELLC, and VIEs for which FELLC or its subsidiaries are the primary beneficiary. The Partnership operates in a single reportable segment and currently has four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). Mining operations at our Hillsboro complex have been idled since March 2015 due to a combustion event (the “Hillsboro combustion event”). We are uncertain as to when production will resume at this operation. Our mined coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern half of the United States, as well as overseas markets. Intercompany transactions, including those between consolidated VIEs, and FELP and its consolidated subsidiaries, are eliminated in consolidation.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and loss during the reporting period. Actual results could differ from those estimates. Revenue Recognition Once mines are in production, coal sales include sales to customers of coal produced and, from time to time, the re-sale of coal purchased from third parties or from one of our affiliates. The Partnership recognizes sales at the time legal title and risk of loss pass to the customer at contracted amounts that are fixed or determinable. For domestic coal sales, this generally occurs when coal is loaded onto railcars at the mine or onto barges at terminals. For coal sales to international markets, this generally occurs when coal is loaded onto an ocean vessel. Quality and weight adjustments are recorded as necessary based on contract specifications as a reduction or increase to coal sales and accounts receivable. Transportation Expenses Costs related to the handling and transporting of coal to the point of sale are included in coal inventory in the consolidated balance sheets. Upon the recognition of the sale, these costs are included in transportation expenses in the consolidated statements of operations. Cash and Cash Equivalents The Partnership considers cash deposits with original maturities of less than three months to be cash and cash equivalents. Cash and cash equivalents are stated at cost, which approximates fair value. Allowance for Doubtful Accounts The Partnership evaluates the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables and disputed amounts. Historically, credit losses have been insignificant. At December 31, 2016 and 2015, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible. Inventories, Net Inventories are valued at the lower of average cost or market. Parts and supplies inventory consists of spare parts for equipment and supplies used in the mining process. A reserve is established for items determined to be obsolete or in excess of quantities needed. Raw coal represents coal stockpiles that require processing through a preparation plant prior to shipment to a customer. Clean coal represents coal stockpiles that will be sold in its current condition. Coal inventory costs include labor, equipment costs, supplies, transportation costs incurred prior to the transfer of title to customers, depreciation, depletion, amortization and direct mine operating overhead. Deferred Longwall Costs The Partnership defers the direct costs associated with longwall moves, including longwall set-up costs, labor and supply costs to perform the move and refurbishment costs of longwall equipment. These deferred costs are expensed on a units-of-production basis into cost of coal produced (excluding depreciation, amortization and depreciation) over the panel benefited by these costs, which has historically approximated one year. Prepaid Royalties Prepaid royalties consist of recoupable minimum royalty payments due under various lease agreements entered into by the Partnership. Prepaid royalties expected to be recouped within one year are classified as current assets in the Partnership’s consolidated balance sheets. The Partnership continually evaluates its ability to recoup prepaid royalty balances, which includes, among other factors, assessing mine production plans, sales commitments, future coal market conditions and remaining years available for recoupment. The contractual recoupment periods on the prepaid royalty balances generally range from five to ten years from the date the minimum royalty was paid. Murray Energy Transport Lease and Overriding Royalty Agreements In April 2015, American Century Transport LLC (“American Transport”), a subsidiary of the Partnership, entered into a purchase and sale agreement (the “PSA”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, pursuant to which American Energy sold to American Transport certain mining and transportation assets for $63.0 million. Concurrent with the PSA, American Transport entered into a lease agreement (the “Transport Lease”) with American Energy pursuant to which (i) American Transport leased to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at the Transport Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport receives from American Energy a fee ranging from $1.15 to $1.75 for every ton of coal mined, processed and/or transported using such assets, subject to a quarterly recoupable minimum fee of $1.7 million. The Transport Lease is being accounted for as a direct financing lease. The unearned income is reflected as other revenue over the term of the lease using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned. Also, in April 2015, American Century Minerals LLC (“Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement (“ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company (collectively, “AEC”), pursuant to which AEC granted to Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The ORRA is subject to a minimum recoupable quarterly fee of $0.5 million. This overriding royalty was accounted for as a financing arrangement. The payments the Partnership receives with respect to the ORRA are reflected partially as a return of the initial investment (reduction in the affiliate financing receivable) and partially as other revenue over the life of the agreement using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned. Property, Plant, Equipment and Development, Net Property, plant and equipment are recorded at cost. Costs that extend the useful lives or increase the productivity of the assets are capitalized, while normal repairs and maintenance that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Asset retirement obligations for the various assets have been recorded as components of the primary assets to which they Machinery and equipment 3–20 years Buildings and structures 3–40 years Other 3–20 years Costs of developing new mines or expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the mineral reserves benefited by the development. Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred. During the development phase, the Partnership establishes access to the mineral reserves and makes other preparations for commercial production. Development costs principally include clearing land, building roads, sinking shafts, driving slopes and developing refuse areas, ventilation and transportation passageways at the mines. Development costs also include the build-out of the Partnership’s transportation infrastructure. Costs incurred during the mine development phase are capitalized and proceeds from the incidental sale of coal during development are recorded as a reduction of the related mine development costs. For reporting in the statements of cash flows, cash expended in the investment in mining rights, equipment and development during the development phase is reported net of capitalized coal sales. Impairment of Depreciable Assets The Partnership records impairment losses on de preciable assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. Debt Issuance Costs The Partnership capitalizes costs incurred in connection with the issuance of debt and the establishment of credit facilities and capital leasing arrangements. Debt financing costs related to revolving credit facilities are recorded as an asset in our consolidated balance sheets and deferred issuance costs related to non-revolving facilities is recorded as a contra to the debt balance. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using either the effective interest method or straight-line method, as applicable. Amortization expense of $7.5 million, $6.0 million and $6.1 million is included in interest expense for the years ended December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016 and 2015, unamortized debt issuance costs were $19.3 million and $21.4 million, respectively. Sale-Leaseback Financing Arrangements The Partnership is party to two arrangements in which it sold assets to an affiliate and immediately leased those assets back from the affiliates. Because the Partnership has continued involvement in the assets sold, the proceeds received on the sale of the assets were recorded as long-term financing arrangements (liabilities) in our consolidated balance sheets. Under both of these arrangements, the Partnership pays a fixed minimum payment, as well as contingent payments for volumes in excess of the contractual minimum payments. Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in expected amounts and timing of future payments based on the mine plans. Payments are first applied against accrued interest and any excess is applied against the outstanding principal. The Partnership accounts for such changes by adjusting in the current period, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied). If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant. Asset Retirement Obligations The Partnership’s asset retirement obligations (“ARO”) consist primarily of spending estimates related to reclaiming surface land, refuse areas, slurry ponds and support facilities at the Partnership’s underground mines in accordance with federal and state reclamation laws as required by each mining permit. These obligations are typically incurred at the time development of a mine commences for underground mines or when construction begins for support facilities, refuse areas and slurry ponds. The Partnership estimates its ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and a market risk premium and then discounted at a credit-adjusted, risk-free rate. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value and the capitalized cost is amortized over the useful life of the related asset on a units-of-production basis. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate. Derivative Financial Instruments The Partnership from time to time utilizes derivative financial instruments principally to manage exposures to non-domestic coal prices. The Partnership records the fair value of each instrument as either an asset or liability in the consolidated balance sheets and the change in fair value of each instrument is recorded in the consolidated statements of operations. Coal contracts provide for the physical purchase or sale of coal in quantities expected to be used or sold by the Partnership over a reasonable period in the normal course of business, and are not recognized in the consolidated balance sheets. Warrant Liability Our warrant liability is required to be accounted for at fair value and the fair value must be revalued at each balance sheet date until the earlier of the exercise of the warrants, their expiration, or until any of the features requiring liability treatment expires or is modified. The resulting non-cash gain or loss on the fair value revaluation at each balance sheet date is recorded as non-operating expense (income) in our consolidated statements of operations. Fair Value 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 a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs. A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy, as defined below, gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. Level 1 is defined as observable inputs, such as quoted prices in active markets for identical assets. Level 2 is defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities 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 is defined as unobservable inputs in which little or no market data exists, therefore, requiring an entity to develop its own assumptions. The carrying value of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. Variable Interest Entities (VIEs) VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. VIEs must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIEs economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes. To determine a VIE's primary beneficiary, the Partnership performs a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether the Partnership is the primary beneficiary of a VIE, the Partnership performs a qualitative analysis that considers the design of the VIE, the nature of the Partnership’s involvement and the variable interests held by other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary. The income attributable to consolidated variable interest entities is recorded as net income attributable to noncontrolling interests in the consolidated statements of operations. Income Taxes We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. While Section 7704(a) of the tax code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the mining, transportation and marketing of minerals and natural resources, such as coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We currently meet the Qualifying Income Exception and expect to continue to qualify prospectively for this exception. As such, each of our unitholders will take into account their respective share of our items of income, gain, loss and deduction in computing their federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis. 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 and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment basis depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting methods, which are partially dependent upon the unitholder’s tax position, differs from the accounting methods followed in our consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership is not available to us. Our tax counsel provided an opinion at the time of the IPO that FELP will be treated as a partnership. However, as is customary, no ruling has been or will be requested from the Internal Revenue Service (“IRS”) regarding our classification as a partnership for federal income tax purposes. FELLC, its subsidiaries and controlled entities were established as limited liability companies, and thus for federal and, if applicable, state and local income tax purposes, are treated as pass-through entities. Therefore, no provision for income taxes was included in the consolidated financial statements. Supplemental Cash Flow Information The following is supplemental information to the consolidated statements of cash flows: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Supplemental disclosure of cash flow information: Cash interest paid, net of amount capitalized $ 80,542 $ 111,155 $ 108,517 Supplemental disclosure of noncash investing and financing activities: Interest converted into debt $ 49,203 $ — $ — Fair value of warrants issued $ 34,045 $ — $ — Noncash capital contribution from Foresight Reserves LP (affiliate) $ 1,046 $ 11,319 $ — Noncash member distribution to Foresight Reserves $ — $ — $ 12,187 Modifications to capital lease obligations $ 663 $ — $ — Short-term insurance financing $ 4,252 $ 2,806 $ — Newly Adopted Accounting Standards In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Payments and annual periods beginning after December 15, 2017. We early adopted this standard during the current year and as a result presented all cash costs for debt prepayment and debt extinguishment as cash outflows from financing activities. The prior periods presented had no such cash costs which required reclassification as a result of adoption of this standard. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern New Accounting Standards Issued and Not Yet Adopted In January 2017, the FASB issued ASU 2017-01, which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This standard is effective for fiscal years beginning after December 15, 2017. We do not expect this new guidance to have a material impact on our consolidated financial statements. In November 2016, the FASB issued ASU 2016-18 which clarifies the presentation requirement of restricted cash within the statement of cash flows. Under ASU 2016-18, the changes in restricted cash and restricted cash equivalents during the period should be included in the beginning and ending cash and cash equivalents balance reconciliation on the statement of cash flows. When cash, cash equivalents, restricted cash or restricted cash equivalents are presented in more than one line item within the statement of financial position, an entity shall calculate a total cash amount in a narrative or tabular format that agrees to the amount shown on the statement of cash flows. Details on the nature and amounts of restricted cash should also be disclosed. This standard is effective for fiscal years beginning after December 15, 2017. We expect this new guidance to require adjustments to the presentation of our consolidated financial statements. As of December 31, 2016, we had restricted cash of $13.3 million, of which $10.7 million is included in current assets and $2.6 million is included in other long-term assets. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation, In May 2014, the FASB issued ASU 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In July 2015, the FASB delayed the effective date until annual and interim periods beginning after December 31, 2017. In February 2016, the FASB updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements. In July 2015, the FASB issued ASU 2015-11, Inventory: Simplifying the Measurement of Inventory

Restructuring Transactions

Restructuring Transactions	12 Months Ended
	Dec. 31, 2016
Restructuring And Related Activities [Abstract]
Restructuring Transactions	3. Restructuring Transactions On December 4, 2015, the Delaware Court of Chancery issued a memorandum opinion concluding, among other things, that the purchase and sale agreement between Foresight Reserves and Murray Energy (see Note 15) constituted a change of control under the indenture (the “2021 Senior Notes Indenture”) governing our 7.875% Senior Notes due 2021 (the “2021 Senior Notes”) and that an event of default occurred under the 2021 Senior Notes Indenture when we failed to offer to purchase the 2021 Senior Notes on or about May 18, 2015 (the “2015 Delaware Court of Chancery change-of-control litigation”). Because of the existence of “change of control” provisions and cross-default or cross-event of default provisions in our debt agreements, the purchase and sale agreement between Foresight Reserves and Murray Energy also resulted, directly or indirectly, in events of default under FELLC’s credit agreement governing its senior secured credit facilities (the “Credit Agreement”), Foresight Receivables LLC’s securitization program and certain other financing arrangements, including our longwall financing arrangements. The existence of an event of default prohibited us access to borrowings or other extensions of credit under our revolving credit facility and our failure to pay the semi-annual interest payments on the 2021 Senior Notes of $23.6 million due on February 15, 2016 and August 15, 2016 resulted in additional events of default. On August 30, 2016 (the “Closing Date”), we completed a global restructuring of our indebtedness. The restructuring transactions (the “Restructuring Transactions”) alleviated existing defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Court of Chancery change-of-control litigation related to the purchase and sale agreement between Foresight Reserves and Murray Energy. See Notes 10 and 15 for additional discussion on the debt restructuring and certain governance and other matters impacted by the Restructuring Transactions. During the years ended December 31, 2016 and 2015, we incurred legal and financial advisor fees of $21.8 million and $3.9 million, respectively, related to the above issues, which have been recorded as debt restructuring costs in the consolidated statements of operations.

Transition and Reorganization C

Transition and Reorganization Costs	12 Months Ended
	Dec. 31, 2016
Restructuring Charges [Abstract]
Transition and Reorganization Costs	4. Transition and Reorganization Costs In April 2015, in connection with Murray Energy acquiring an ownership interest in the Partnership and its general partner, we entered into a Management Services Agreement (the “MSA”) with Murray American Coal Inc. (the “Manager”), a subsidiary of Murray Energy, with the intent of optimizing and reorganizing certain corporate administrative functions and generating synergies between the two companies through the elimination of headcount and duplicate selling, general and administrative expenses (see Note 15). The costs were primarily comprised of retention compensation to certain employees during the transition period and termination benefits to employees whose positions were eliminated as a result of the MSA. Transition and reorganization costs were comprised of the following for the years ended December 31, 2016, 2015 and 2014: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Retention compensation paid by Foresight Reserves and pushed down to FELP $ 2,333 $ 10,032 $ — Equity-based compensation 4,315 4,322 — Cash retention and termination benefits — 5,878 — Legal and other charges 241 1,201 — Transition and reorganization costs $ 6,889 $ 21,433 $ —

Commodity Derivative Contracts

Commodity Derivative Contracts	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts	5. Commodity Derivative Contracts The Partnership has commodity price risk for its coal sales as a result of changes in the market value of its coal. To minimize this risk, we enter into long-term, fixed price coal supply sales agreements and coal derivative swap contracts. As of December 31, 2016 and 2015, we had outstanding coal derivative swap contracts to fix the selling price on 0.5 million tons and 1.1 million tons, respectively. Swaps are designed so that the Partnership receives or makes payments based on a differential between fixed and variable prices for coal. The coal derivative contracts are economic hedges to certain future unpriced (indexed) sales commitments and expected sales through 2017. The coal derivative swap contracts are indexed to the Argus API 2 price index, the benchmark price for coal imported into northwest Europe. The coal derivative contracts are accounted for as freestanding derivatives and any gains or losses resulting from adjusting these contracts to fair value are recorded into earnings. We record the fair value of all positions with a given counterparty on a gross basis in the consolidated balance sheets (see Note 17). We have diesel fuel price exposure in our transportation and production processes and therefore are subject to commodity price risk as a result of changes in the market value of diesel fuel. During the years ended December 31, 2016 and 2015 . We have master netting agreements with all of our counterparties that allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default. We manage counterparty risk through the utilization of investment grade commercial banks, diversification of counterparties and our counterparty netting arrangements. The settlements of commodity derivative contracts and (loss) gain on commodity derivative contracts for the years ended December 31, 2016, 2015 and 2014 are as follows: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Settlements of commodity derivative contracts $ 12,644 $ 61,223 $ 19,204 (Loss) gain on commodity derivative contracts $ (23,752 ) $ 45,691 $ 76,330 We received $19.1 million and $7.3 million in proceeds during the years ended December 31, 2015 and 2014, respectively, from the settlement of derivatives that were reclassified from an operating cash flow activity to an investing activity in the consolidated statements of cash flows because the derivative contracts were settled prior to the expiration of their contractual maturities and prior to the delivery date of the underlying sales contracts.

Accounts Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2016
Receivables [Abstract]
Accounts Receivable	6. Accounts Receivable Accounts receivable consists of the following: December 31, 2016 December 31, 2015 (In Thousands) Trade accounts receivable $ 42,862 $ 56,013 Other receivables 12,043 5,312 Total accounts receivable $ 54,905 $ 61,325

Inventories, Net

Inventories, Net	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventories, Net	7. Inventories, Net Inventories, net consist of the following: December 31, 2016 December 31, 2015 (In Thousands) Parts and supplies $ 18,712 $ 24,276 Raw coal 4,907 1,906 Clean coal 19,433 24,470 Total inventories, net $ 43,052 $ 50,652

Property, Plant, Equipment and

Property, Plant, Equipment and Development, Net	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Property, Plant, Equipment and Development, Net	8. Property, Plant, Equipment and Development, Net Property, plant, equipment and development, net consist of the following: December 31, 2016 December 31, 2015 (In Thousands) Land, land rights and mineral rights $ 99,909 $ 99,676 Machinery and equipment 1,186,450 1,140,256 Machinery and equipment under capital leases 102,662 126,401 Buildings and structures 246,132 248,946 Development costs 774,297 750,177 Other 9,156 9,369 Property, plant, equipment and development 2,418,606 2,374,825 Less: accumulated depreciation, depletion and amortization (1,099,669 ) (941,632 ) Property, plant, equipment and development, net $ 1,318,937 $ 1,433,193

Accrued Expenses and Other Curr

Accrued Expenses and Other Current Liabilities	12 Months Ended
	Dec. 31, 2016
Payables And Accruals [Abstract]
Accrued Expenses and Other Current Liabilities	9. Accrued Expenses and Other Current Liabilities Accrued expenses and other current liabilities consist of the following: December 31, 2016 December 31, 2015 (In Thousands) Employee compensation, benefits and payroll taxes $ 13,065 $ 12,393 Taxes other than income 6,819 6,560 Liquidated damages 5,828 6,404 Litigation reserve 4,800 2,347 Royalties (non-affiliate) 4,117 3,707 Other 8,963 4,396 Total accrued expenses and other current liabilities $ 43,592 $ 35,807

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Lease Obligations	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt and Capital Lease Obligations	10. Long-Term Debt and Capital Lease Obligations Long-term debt and capital lease obligations consist of the following: December 31, 2016 December 31, 2015 (In Thousands) 2021 Second Lien Notes $ 349,100 $ — 2017 Exchangeable PIK Notes 299,859 — 2021 Senior Notes — 600,000 Revolving Credit Facility 352,500 352,500 Term Loan 295,667 297,750 Trade A/R Securitization Program 14,200 41,000 5.78% longwall financing arrangement 39,217 50,423 5.555% longwall financing arrangement 41,250 51,563 Capital lease obligations 41,457 62,710 Subtotal - Total principal outstanding on long-term debt and capital lease obligations 1,433,250 1,455,946 Unamortized deferred financing costs and debt discounts (42,187 ) (21,380 ) Total long-term debt and capital lease obligations 1,391,063 1,434,566 Less: current portion (368,993 ) (1,434,566 ) Non-current portion of long-term debt and capital lease obligations $ 1,022,070 $ — On August 30, 2016, we completed a global restructuring of our indebtedness. The Restructuring Transactions described below alleviated the then existing defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Court of Chancery change-of-control litigation. As a result of the Restructuring Transactions and the resolution of the 2015 Delaware Court of Chancery change-of-control litigation, certain of our outstanding long-term debt and capital lease obligations are no longer reflected as a current liability in the consolidated balance sheets and we are no longer subject to default interest rates. Also, as a result of the Restructuring Transactions, a loss on the early extinguishment of debt of $13.2 million was recognized during the year ended December 31, 2016 for the write-off of $11.0 million of unamortized debt discount and debt issuance costs associated with the extinguishment of our 7.875% Senior Notes due 2021 and the reduction in borrowing capacity under our Revolving Credit Facility and due to the incurrence of $2.2 million in costs related to the modification of our debt which were expensed in accordance with the authoritative accounting literature on debt modifications. Lender and third-party professional fees totaling $13.5 million were deferred and will be amortized over the remaining lives of the respective debt instruments. Exchange of 2021 Senior Notes for New Notes and Warrants On the Closing Date, the Partnership exchanged $599.8 million in aggregate principal amount of our 2021 Senior Notes and the accrued and unpaid interest thereon for the following consideration: • (i) $349.1 million in aggregate principal of Senior Secured Second Lien PIK Notes due 2021 (the “Second Lien Notes”); • (ii) $299.9 million in aggregate principal of Senior Secured Second Lien Exchangeable PIK Notes due 2017 (the “Exchangeable PIK Notes,” and, together with the Second Lien Notes, the “New Notes”); and • (iii) 516,825 warrants (the “Warrants”) to acquire newly issued common units of FELP (the “Common Units”) equal to 4.5% of the total limited partner units of FELP outstanding on the date of a Note Redemption (as defined below) (after giving effect to the full exercise thereof and the Note Redemption). On the Closing Date, we also redeemed the remaining $175,000 in aggregate principal amount of 2021 Senior Notes that were not exchanged. Upon such redemption, the obligations under the 2021 Senior Notes and the 2021 Senior Notes Indenture were satisfied and discharged. A liability of $34.0 million for the fair value of the Warrants was recorded in our consolidated balance sheet as of the Closing Date and the offset was recognized as a debt discount to the New Notes. The discount was allocated pro rata between the Second Lien Notes and the Exchangeable PIK Notes in proportion to the relative fair value of each instrument held by a person other than the Reserves Investor Group (as defined in Note 15) on the Closing Date (only the unaffiliated holders of the New Notes received the Warrants on the Closing Date). The $25.0 million discount allocated to the Second Lien Notes and the $9.0 million discount allocated to the Exchangeable PIK Notes is being amortized using the effective interest method over their respective maturities. Terms of the New Notes The Second Lien Notes were issued pursuant to an indenture and have a maturity date of August 15, 2021. The Second Lien Notes bear interest at a rate of: (i) 9.0% per annum until August 15, 2018 and 10.0% per annum thereafter, in each case, payable in cash on each interest payment date; and (ii) 1.0% per annum payable in kind. Interest is payable semi-annually on February 15th and August 15th, commencing on February 15, 2017. Interest expense on the Second Lien Notes is being recorded such that a constant effective interest rate is recognized over the duration of the notes. The Partnership may redeem the Second Lien Notes in whole or in part subject to the redemption premiums and provisions in the indenture. The Exchangeable PIK Notes were issued pursuant to an indenture (the “Exchangeable PIK Notes Indenture) and have a maturity date of October 3, 2017 (the “Exchangeable PIK Notes Maturity Date”). The Exchangeable PIK Notes bear interest payable in kind at a rate of 15.0% per annum, payable on March 1, 2017 and October 3, 2017. We may redeem, repurchase, refinance, defease or otherwise retire (any of the foregoing, a “redemption”) all of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at 100% of the principal amount thereof plus accrued interest (any such redemption, an “Exchangeable PIK Note Retirement”). In addition to the Exchangeable PIK Note Retirement, Murray Energy, an affiliate of Murray Energy or a group of persons which includes Murray Energy or any of its affiliates (collectively, the “Murray Group”) shall have the right to purchase all (but not less than all) of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at a price equal to 100% of the principal amount of the Exchangeable PIK Notes plus accrued interest (a “Murray Purchase,” and together with an Exchangeable PIK Note Retirement and any repayment of the Exchangeable PIK Notes in full in cash that occurs on the Exchangeable PIK Notes Maturity Date, a “Note Redemption”). Upon a Murray Purchase, the Murray Group will receive FELP units equal to the principal and interest settlement amount multiplied by the lesser of: (a) a number equal to one divided by 92.5% of the last thirty days weighted-average trading price or (b) 1.12007 common units per $1.00 principal amount of Exchangeable PIK Notes. The Partnership and Murray Energy may each purchase less than all of the outstanding Exchangeable PIK Notes, so long as the combination results in redemption of all of the Exchangeable PIK Notes. The Exchangeable PIK Note Retirement may be funded with the proceeds from an investment The obligations under the New Notes are unconditionally guaranteed on a senior secured basis by each of FELP’s wholly owned domestic subsidiaries that guarantee the Senior Secured Credit Facilities (other than Foresight Energy Finance Corporation) and on a senior unsecured basis by FELP and are or will be secured by second-priority perfected liens on substantially all of our and the subsidiary guarantors’ existing and future assets, subject to certain exceptions. Senior Secured Credit Facilities On the Closing Date, FELLC entered into an amendment to its senior secured credit facilities (as amended, the “Senior Secured Credit Facilities”), pursuant to which outstanding defaults under its existing credit agreement were waived and the credit agreement was amended and restated as set forth in the third amended and restated credit agreement (the “Amended Credit Agreement”). Pursuant to the Amended Credit Agreement, $297.8 million in term loans remained outstanding on the Closing Date and mature in August 2020 (the “Term Loan”) and the commitments under our $550.0 million revolving credit facility (the “Revolving Credit Facility”), which terminates in August 2018, was reduced to $450.0 million on December 31, 2016. The Amended Credit Agreement also adds an anti-hoarding provision under our Revolving Credit Facility which prohibits new borrowings if the aggregate amount of our unrestricted cash and cash equivalents (taking into account certain pending applications of cash) exceeds $35.0 million both before and after giving effect to such borrowings when taking into account the intended use of such loan proceeds for bona fide purposes within 60 days. Mandatory term loan prepayments are required to be made based on an excess cash flow calculation, as defined by the Amended Credit Agreement, for the second half of fiscal year 2016 and full fiscal year 2017, sales of assets, certain proceeds from net insurance recoveries and condemnation awards and certain incurrence of indebtedness, subject, in each case, to customary exceptions and thresholds. The excess cash flow generated during the second half of fiscal year 2016 and business interruption insurance recoveries from the Hillsboro combustion event require that we prepay $26.9 million of Term Loan principal, $2.1 million of which was paid in 2016 and the remainder is due during the first quarter of 2017. Under the Amended Credit Agreement, borrowings under our Revolving Credit Facility bear interest at a rate equal to, at our option: (i) LIBOR (subject to a LIBOR floor of 0%) plus an applicable margin ranging from 3.50% to 4.50%; or (ii) a base rate plus an applicable margin ranging from 2.50% to 3.50%; in each case, determined in accordance with our consolidated net leverage ratio. Our Term Loans bear interest of a rate equal to, at our option: (i) LIBOR (subject to a LIBOR floor of 1.00%) plus 5.50%; or (ii) a base rate plus 4.50%. We are also required to pay a commitment fee of 0.50% to the lenders under the Revolving Credit Facility in respect of unutilized commitments thereunder and pay a fronting fee equal to 0.125% per annum of the amount available to be drawn under letters of credit. As of December 31, 2016, we had $352.5 million in borrowings outstanding under the Revolving Credit Facility and $7.0 million in letters of credit. As of December 31, 2016, the weighted-average interest rate on Revolving Credit Facility and Term Loan borrowings was 5.3% and 6.5%, respectively. The obligations under the Senior Secured Credit Facilities are unconditionally guaranteed on a senior unsecured basis by FELP and on a senior secured basis by our direct and indirect domestic subsidiaries and are or will be secured by first-priority perfected liens on substantially all of our and the subsidiary guarantors’ existing and future assets, subject to certain exceptions. The Senior Secured Credit Facilities require that we comply on a quarterly basis with certain financial covenants, including a minimum consolidated interest coverage ratio of 2.00:1.00 and a maximum senior secured net leverage ratio ranging from 3.50:1.00 for the fiscal quarter ended December 31, 2016 to 2.75:1.00 for the fiscal quarter ending March 31, 2021 and thereafter. Our Senior Secured Credit Facilities prohibit certain restricted payments, including discretionary dividends, until the later to occur of: (i) June 30, 2018 and (ii) the date on which our obligations under our revolving credit facility have been paid in full, after which restricted payments can be made of up to $25.0 million per year, subject to certain adjustments and exceptions. The Senior Secured Credit Facilities also require compliance with certain covenants that significantly restricts our ability to, among other things, (i) incur additional indebtedness, (ii) incur liens, (iii) pay dividends or make certain other restricted payments, investments or acquisitions, (iv) enter into certain transactions with affiliates, (v) merge or consolidate with another person, (vi) sell, assign, lease or otherwise dispose of all or substantially all of our assets, and (vii) make voluntary prepayments of certain debt, in each case subject to exceptions. Longwall Financing Arrangements and Capital Lease Obligations In January 2010, Sugar Camp Energy LLC entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing arrangement is collateralized by the longwall mine equipment. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually in June and December until maturity. On the Closing Date, we entered into an amendment to the 5.78% longwall financing credit agreement under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last three semi-annual amortization payments. The new maturity date of the 5.78% longwall financing arrangement is June 2019. In addition, the senior secured leverage ratio financial maintenance covenant was amended to be consistent with the Amended Credit Agreement. The outstanding balance as of December 31, 2016 was $39.2 million. In May 2010, Hillsboro Energy LLC entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing arrangement is collateralized by the longwall mine equipment. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually in March and September until maturity. On the Closing Date, we entered into an amendment to the 5.555% longwall financing credit agreement under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last four semi-annual amortization payments. The new maturity date of the 5.555% longwall financing arrangement is September 2019. In addition, the senior secured leverage ratio financial maintenance covenant was amended to be consistent with the Amended Credit Agreement. The outstanding balance as of December 31, 2016 was $41.3 million. In March 2012, FELLC entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment during the third quarter of 2012, this interim longwall finance agreement was converted into individual leases with maturities of four and five years beginning on September 1, 2012. These leases contain a bargain purchase option at the end of the lease term and are accounted for as capital lease obligations. Principal and interest payments are due monthly over the terms of the leases. In connection with the Restructuring Transactions, we executed waivers to cure outstanding defaults under the master lease agreements to our capital lease obligations. These waivers, among other things, ratified the existing terms of each applicable equipment financing agreement, provided the lessor with a waiver fee equal to one hundred basis points of the outstanding amount due under the agreement, increased the interest rate by one percent per annum, and, with respect to certain arrangements, released the lessor from any claims that such parties may have against the lessor with respect to the lease. These capital lease obligations bear interest ranging from 5.4% to 6.3%, and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2016, $5.2 million was outstanding under these capital lease obligations. In November 2014, the Partnership entered into a sale-leaseback financing arrangement with a financial institution under which it sold a set of longwall shields and related equipment to a financial institution for $55.9 million and leased the shields back under three individual leases. We account for these leases as capital lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases. In connection with the Restructuring Transactions, we also executed waivers to cure outstanding defaults under the master lease agreements to our capital lease obligations. These waivers, among other things, ratified the existing terms of each applicable equipment financing agreement, provided the lessor with a waiver fee equal to one hundred basis points of the outstanding amount due under the agreement, increased the interest rate by one percent per annum, and, with respect to certain arrangements, released the lessor from any claims that such parties may have against the lessor with respect to the lease. These capital lease obligations bear interest at 5.762% and principal and interest payments are due monthly over the five-year terms of the leases. Aggregate termination payments of $2.8 million are due at the end of the lease terms. As of December 31, 2016, $36.3 million was outstanding under these capital lease obligations. Trade Accounts Receivable Securitization Program In January 2015, Foresight Energy LP and certain of its wholly-owned subsidiaries, entered into a $70 million receivables securitization program (the “Securitization Program”). Under this Securitization Program, our subsidiaries sell all of their customer trade receivables (the “Receivables”), on a revolving basis, to Foresight Receivables LLC, a wholly-owned and consolidated special purpose subsidiary of Foresight Energy LP (the “SPV”). The SPV then pledges its interests in the Receivables to the securitization program lenders, which make loans to the SPV. When cash is collected from customers on the Receivables, it is temporarily held in a restricted cash account for a short duration and then is transferred to an unrestricted cash account, subject to the sufficiency of our borrowing base and certain other contractual provisions. The Securitization Program has a three-year maturity which expires on January 12, 2018. The borrowings under the Securitization Program are variable-rate and also carry a commitment fee for unutilized commitments. In August 2016, we entered into an amended and restated receivables financing agreement pursuant to which commitments under the facility were reduced to $50.0 million. We recorded a loss on extinguishment of debt charge of $0.1 million to write-off a portion of the deferred debt issue costs for the reduction in commitments as part of a forbearance agreement with the lenders. As of December 31, 2016, we had borrowings outstanding of $14.2 million under the Securitization Program. Maturity Tables The following summarizes the contractual principal maturities of long-term debt and capital lease obligations as of December 31, 2016: Long-Term Debt Capital Lease Obligations (In Thousands) 2017 $ 360,392 $ 15,986 2018 386,644 11,471 2019 24,806 14,000 2020 — — 2021 619,951 — Thereafter — — Total $ 1,391,793 $ 41,457 The aggregate amounts of remaining minimum lease payments on the Partnership’s capital lease obligations are $ 45.0 2017 2018 2019 2020 2021 Minimum lease payments $ 17,915 $ 12,635 $ 14,471 $ — $ —

Sale-Leaseback Financing Arrang

Sale-Leaseback Financing Arrangements - Affiliate	12 Months Ended
	Dec. 31, 2016
Leases Capital [Abstract]
Sale-Leaseback Financing Arrangements – Affiliate	11. Sale-Leaseback Financing Arrangements – Affiliate Macoupin Energy Sale-Leaseback Financing Arrangement In January 2009, Macoupin entered into a sales agreement with WPP, LLC (“WPP”) and HOD, LLC (“HOD”) (subsidiaries of Natural Resource Partners LP (“NRP”)) to sell certain mineral reserves and rail facility assets (the “Macoupin Sales Arrangement”). NRP is an affiliate of the Partnership (see Note 15). Macoupin received $143.5 million in cash in exchange for certain mineral reserve and transportation assets. Simultaneous with the closing, Macoupin entered into a lease with WPP for mining the mineral reserves (the “Mineral Reserves Lease”) and with HOD for the use of the rail loadout and rail loop (the “Macoupin Rail Loadout Lease” and the “Rail Loop Lease,” respectively). The Mineral Reserves Lease is a 20-year noncancelable lease that contains renewal elections for six additional five-year terms. The Macoupin Rail Loadout Lease and the Rail Loop Lease are 99 year noncancelable leases. Under the Mineral Reserves Lease, Macoupin makes monthly payments equal to the greater of $5.40 per ton or 8.00% of the sales price, plus $0.60 per ton for each ton of coal sold from the leased mineral reserves, subject to a minimum royalty of $4.0 million per quarter through December 31, 2028. After the initial 20-year term, the annual minimum royalty is $10,000 per year. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty under the Mineral Reserves Lease and tonnage fees paid under the Macoupin Rail Loadout and Rail Loop Leases discussed below exceed $4.0 million, Macoupin may generally recoup any unrecouped quarterly payments made during the preceding 20 quarters on a first paid, first recouped basis. The Macoupin Rail Loadout Lease and Rail Loop Lease require an aggregate payment of $3.00 ($1.50 for the rail loop facility and $1.50 for the rail load-out facility) for each ton of coal loaded through the facility for the first 30 years, up to 3.4 million tons per year. After the initial 30-year term, Macoupin would pay an annual rental payment of $20,000 per year for usage of the rail loadout and rail loop. The Macoupin Sales Arrangement, Mineral Reserves Lease, Macoupin Rail Loadout Lease and Rail Loop Lease are collectively accounted for as a financing arrangement (the “Macoupin Sale-Leaseback”). This financing arrangement is recourse to Macoupin and not recourse to Foresight Energy LP or any of its other subsidiaries. We are currently in dispute with WPP in regards to the application of the recoupment provision within the Mineral Reserves Lease (see Note 22). At December 31, 2016 and 2015, the amount outstanding under the Macoupin Sale-Leaseback was $141.9 million and $143.5 million, respectively. The effective interest rate on the financing obligation was 13.7% and 13.9% as of December 31, 2016 and 2015, respectively. Interest expense was $16.3 million, $18.8 million and $16.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016 and 2015, interest of $0 and $0.5 million, respectively, was accrued in the consolidated balance sheets for the Macoupin Sale-Leaseback. Sugar Camp Energy Sale-Leaseback Financing Arrangement In March 2012, Sugar Camp entered into a sales agreement with HOD for which it received a total of $50.0 million in cash in exchange for certain rail loadout assets (“Sugar Camp Sales Agreement”). Simultaneous with the closing, Sugar Camp entered into a lease transaction with HOD for the use of the rail loadout (the “Sugar Camp Rail Loadout Lease”). The Sugar Camp Rail Loadout Lease is a 20-year noncancelable lease that contains renewal elections for 16 additional five-year terms. Under the Sugar Camp Rail Loadout Lease, Sugar Camp will pay a monthly royalty of $1.10 per ton for every ton of coal mined from specified reserves and loaded through the rail loadout. The royalty is subject to adjustment based on the time it takes for Sugar Camp to complete each longwall move. The royalty payments are subject to a minimum payment amount of $1.3 million per quarter for the first twenty years the lease is in effect. After the initial 20-year term, Sugar Camp would pay an annual rental payment of $10,000 per year. To the extent the minimum payment exceeds amounts owed based on actual coal loaded, the excess is recoupable within two years of payment. The Sugar Camp Sales Agreement and Sugar Camp Rail Loadout Lease are collectively accounted for as a financing arrangement (the “Sugar Camp Sale-Leaseback”). At December 31, 2016 and 2015, the amount outstanding under the Sugar Camp Sale-Leaseback was $50.0 million. The effective interest rate on the financing, which is derived from the timing and tons of coal to be mined as set forth in the current mine plan and the related cash payments, was 13.7% and 13.2% at December 31, 2016 and 2015, respectively. Interest expense recorded on the Sugar Camp Sale-Leaseback was $7.8 million, $5.4 million and $6.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016 and 2015, interest of $2.9 million and $1.6 million, respectively, was accrued in the consolidated balance sheets for the Sugar Camp Sale-Leaseback. Maturity Tables The following summarizes the maturities of expected principal payments, based on current mine plans, on the Partnership’s sale-leaseback financing arrangements, and accrued interest at December 31, 2016: Sale-Leaseback Financing Arrangements Accrued Interest (In Thousands) 2017 $ 1,372 $ 2,930 2018 1,415 — 2019 2,454 — 2020 4,203 — 2021 4,239 — Thereafter 178,186 — Total $ 191,869 $ 2,930 The aggregate amounts of remaining minimum lease payments on the Partnership’s sale-leaseback financing arrangements are $ 268.3 2017 2018 2019 2020 2021 Minimum lease payments $ 21,000 $ 21,000 $ 21,000 $ 21,000 $ 21,000

Contractual Arrangements and Op

Contractual Arrangements and Operating Leases	12 Months Ended
	Dec. 31, 2016
Leases Operating [Abstract]
Contractual Arrangements and Operating Leases	12. Contractual Arrangements and Operating Leases The Partnership leases certain surface rights, mineral reserves, mining, transportation and other equipment under various lease agreements with related entities under common control, other affiliated entities and independent third parties in the normal course of business. The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The lease agreements typically require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (typically five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Under the terms of certain mineral reserve leases, the Partnership is to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and is responsible for the acquisition costs and the assets are to be titled to the lessor. Transportation throughput agreements generally require a per ton fee amount for coal transported and contain certain escalation clauses and/or renegotiation clauses. For certain transportation assets, the Partnership is responsible for operations, repairs, and maintenance and for keeping the transportation facilities in good working order. Surface rights, mining, and other equipment leases require monthly payments based upon the specified agreements. Certain of these leases provide options for the purchase of the property at various times during the life of the lease, generally at its then-fair market value. The Partnership also leases certain office space, rail cars and equipment under leases with varying expiration dates. The following table presents future minimum payments, by year, required under contractual royalty and throughput arrangements with related entities and third parties as of December 31, 2016: Royalties – Third Party Royalties – Related Party Transportation Minimums – Third Party (In Thousands) 2017 $ 2,004 $ 57,667 $ 49,580 2018 2,004 57,667 50,880 2019 2,004 57,667 52,230 2020 2,004 43,667 53,630 2021 2,004 38,834 51,050 Thereafter 7,181 232,500 54,900 Total $ 17,201 $ 488,002 $ 312,270 The following presents future minimum lease payments, by year, required under noncancelable operating leases with initial terms greater than one year, as of December 31, 2016: Operating Leases – Third Party Operating Leases – Related Party (In Thousands) 2017 $ 3,190 $ 155 2018 2,214 155 2019 539 150 2020 — 150 2021 — 100 Thereafter — — Total $ 5,943 $ 710 Total rental expense from operating leases for the years ended December 31, 2016, 2015, and 2014 was $12.4 million, $14.3 million, and $16.1 million, respectively. Included in rental expense is $8.5 million, $9.0 million, and $9.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, of contingent rental payments to Williamson Transport, a subsidiary of NRP, for the rail loadout facility at Williamson Energy. We pay contingent rental fees, net of a fixed per ton amount received for maintaining the facility, on each ton of coal passed through the rail loadout facility.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	13. Asset Retirement Obligations The change in the carrying amount of asset retirement obligations was as follows: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Balance at beginning of period (including current portion) $ 43,295 $ 35,580 $ 21,225 Accretion expense 3,376 2,267 1,621 Adjustments for liabilities incurred or changes in estimates (1,283 ) 6,579 13,747 Expenditures for reclamation activities (471 ) (1,131 ) (1,013 ) Balance at end of period (including current portion) 44,917 43,295 35,580 Less: current portion of asset retirement obligations (7,273 ) (18 ) (4,207 ) Noncurrent portion of asset retirement obligations $ 37,644 $ 43,277 $ 31,373 The credit-adjusted, risk-free interest rates used in determining the asset retirement obligations were 8.5%, 9.8% and 6.6% at December 31, 2016, 2015, and 2014, respectively.

Coal Workers Pneumoconiosis and

Coal Workers Pneumoconiosis and Workers Compensation	12 Months Ended
	Dec. 31, 2016
Postemployment Benefits [Abstract]
Coal Workers' Pneumoconiosis and Workers' Compensation	14. Coal Workers’ Pneumoconiosis and Workers’ Compensation Certain of our consolidated affiliates are responsible under Illinois statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease (“CWP”). In addition, state statutes dictate that we provide income replacement and medical treatment for work-related traumatic injury claims, including survivor benefits for employment related deaths. Effective July 1, 2014, we terminated our guaranteed cost program in favor of a high deductible insurance program. Our liability for CWP benefits was estimated by an independent actuary based on assumptions regarding medical costs, allocated loss adjustment expense, claim development patterns and interest rates. For the years ended December 31, 2016, 2015 and 2014, we recorded CWP (benefit)/expense of $(0.4) million, $1.4 million and $1.5 million, respectively, and have an aggregate CWP liability of $2.2 million and $3.0 million recorded in the consolidated balance sheets as of December 31, 2016 and 2015, respectively. Our liability for workers compensation benefits was determined by a third-party administrator based on actual claims incurred and the expected development of those claims and claims incurred but not yet reported. For the years ended December 31, 2016, 2015 and 2014, we recorded workers’ compensation claim expense of $3.9 million, $3.0 million and $1.4 million, respectively, and have a workers’ compensation liability of $4.2 million and $2.2 million recorded in accrued expenses and other current liabilities in the consolidated balance sheets as of December 31, 2016 and 2015, respectively.

Related-Party Transactions

Related-Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related-Party Transactions	15. Related-Party Transactions The chairman of our general partner’s board of directors and the controlling member of Foresight Reserves, Christopher Cline, directly and indirectly beneficially owns a 31% and 4% interest in the general and limited partner interests of NRP, respectively. We routinely engage in transactions in the normal course of business with NRP and its subsidiaries and Foresight Reserves and its affiliates. These transactions include production royalties, transportation services, administrative arrangements, supply agreements, service agreements, land leases and sale-leaseback financing arrangements (see Note 11, sale-leaseback financing arrangements are excluded from the discussion and tables below). Also, in connection with the reorganization of the Partnership pursuant to the execution of the MSA, Foresight Reserves paid retention bonuses to certain Partnership employees which were recorded as capital contributions during the period of payment (see Note 18). On April 16, 2015, Foresight Reserves and Murray Energy executed a purchase and sale agreement whereby Murray Energy paid Foresight Reserves $1.37 billion to acquire a 34% voting interest in FEGP, 77.5% of FELP’s incentive distribution rights (“IDR”) and 100% of the outstanding subordinated units in FELP. FEGP has continued to govern the Partnership subsequent to this transaction. Murray Energy has an option (the “GP Option”), as amended as part of the Restructuring Transactions, to purchase an additional 46% of the voting interests in FEGP for $15 million and is also conditioned upon a Note Redemption prior to the Exchangeable PIK Notes Maturity Date (see Note 10 for additional discussion on the Note Redemption). Reserves Investor Group Tender Offer and Exchange In connection with the Restructuring Transactions, on the Closing Date, the Reserves Investor Group (as defined below) acquired, with cash, $105.4 million of the outstanding 2021 Senior Notes (the “Tender Offer”). The Reserves Investor Group includes Christopher Cline, the four trusts established for the benefit of Mr. Cline’s children, Michael J. Beyer, the former Chief Executive Officer of FEGP, and owner of 0.66% of the voting and 0.225% of the economic interests of FEGP, and certain other limited liability companies owned or controlled by individuals with limited partner interests in Foresight Reserves through indirect ownership. Prior to the commencement of the Tender Offer, the Reserves Investor Group owned $83.0 million of the 2021 Senior Notes. The Reserves Investor Group then exchanged its aggregate $188.4 million of 2021 Senior Notes, plus $6.8 million of accrued and unpaid interest, for $179.9 million of Exchangeable PIK Notes and $15.2 million of Second Lien Notes (see Note 10 for additional discussion on the terms of the Exchangeable PIK Notes and Second Lien Notes). As of December 31, 2016, we have accrued $9.6 million of interest under the New Notes attributed to the Reserves Investor Group’s ownership interest. Murray Purchase Right The Murray Group has the right to purchase all of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at a price equal to 100% of the principal amount of the Exchangeable PIK Notes plus accrued interest. Upon a Murray Purchase, the Murray Group will receive FELP units equal to the principal and interest settlement amount multiplied by the lesser of: (a) a number equal to one divided by 92.5% of the last thirty days weighted-average trading price or (b) 1.12007 common units per $1.00 principal amount of Exchangeable PIK Notes. See Note 10 for additional discussion. Murray Energy Management Services Agreement On April 16, 2015, the MSA was entered into pursuant to which the Manager will provide certain management and administration services to FELP for a quarterly fee of $3.5 million ($14.0 million on an annual basis), subject to contractual increases and other adjustments. To the extent FELP or FEGP directly incurs costs for certain services covered under the MSA, then the Manager’s quarterly fee is reduced accordingly. Also, to the extent the Manager utilizes outside service providers to perform any of the services under the MSA, then the Manager is responsible for those outside service provider costs. The initial term of the MSA extends through December 31, 2022 and is subject to termination provisions, including termination if the Note Redemption does not occur prior to the Exchangeable PIK Notes Maturity Date and Murray Energy does not execute its GP Option. If Murray executes its GP Option, it has the right to increase the annual MSA fee to $20.0 million per year, subject to certain adjustments. After taking into account the contractual adjustments for direct costs incurred by FELP, the amount of net expense due to the Manager for the years ended December 31, 2016 and 2015 was $8.9 million and $4.7 million, respectively. Murray Energy Transport Lease and Overriding Royalty Agreements For the years ended December 31, 2016 and 2015, we recorded other revenues of $5.9 million and $4.0 million, respectively, under the Transport Lease. The total remaining minimum payments under the Transport Lease was $91.8 million at December 31, 2016, with unearned income equal to $33.3 million. As of December 31, 2016, the outstanding Transport Lease financing receivable was $58.5 million, of which $2.7 million was classified as current in the consolidated balance sheet. For the years ended December 31, 2016 and 2015, we recorded other revenues of $2.1 million and $1.4 million, respectively, under the ORRA. The total remaining minimum payments under the ORRA was $32.1 million at December 31, 2016, with unearned income equal to $20.4 million. As of December 31, 2016, the outstanding ORRA financing receivable was $11.7 million, of which $0.2 million was classified as current in the consolidated balance sheet. Other Murray Transactions During the years ended December 31, 2016 and 2015, we purchased $8.3 million and $3.3 million, respectively, in equipment, supplies and rebuild and other services from affiliates of Murray Energy. During the years ended December 31, 2016 and 2015, our subsidiaries provided $0.9 million and $0.2 million, respectively, in equipment, supplies and rebuild services to affiliates of Murray Energy. From time to time, we purchase and sell coal to Murray Energy and its affiliates to, among other things, meet each of our customer contractual obligations. We also sell coal to Javelin Global Commodities Limited (“Javelin”), an international commodities marketing and trading joint venture owned by Murray Energy, Uniper (formerly E.ON Global Commodities SE), and management of Javelin. As of December 31, 2016, we had commitments to purchase $28.1 million in coal from Murray Energy and its affiliates and sell $37.0 million in coal to Murray Energy and its affiliates (including Javelin). During the years ended December 31, 2016 and 2015, Murray Energy transported coal under our transportation agreement with a third-party rail company resulting in usage fees owed to the third-party rail company of $4.1 million and $11.0 million, respectively. These usage fees were billed to Murray Energy, resulting in no impact to our consolidated statements of operations. The usage of the railway line with this third-party rail company by Murray Energy counts towards the minimum annual throughput volumes with the third-party rail company, thereby reducing the Partnership’s exposure to contractual liquidated damage charges. Similarly, during the years ended December 31, 2016 and 2015, we incurred $0 million and $0.2 million, respectively, of transportation fees incurred for shipments under one of Murray Energy’s third-party transloading contracts. During the year ended December 31, 2016 and 2015, we earned $1.2 million and $0.3 million, respectively, in other revenues for Murray Energy’s usage of our Sitran terminal. From time to time, we also reimburse Murray Energy for costs paid by them on our behalf, including certain insurance premiums. 2021 Senior Notes On August 23, 2013, Cline Resource and Development Company (“CRDC”) acquired $16.5 million of outstanding principal amounts of our 2021 Senior Notes (the “Original Purchase”). During September and October 2013, CRDC sold the Original Purchase primarily to affiliates, including $8.0 million to Chris Cline, $4.0 million to an entity controlled by John F. Dickinson, a director of our general partner’s board of directors until December 31, 2015, and $3.7 million to two former executives of the Partnership. Additional amounts were acquired independently in 2015 by Chris Cline and The Cline Trust Company LLC, as discussed below. As of December 31, 2015, Chris Cline owned $44.5 million of the outstanding principal on our 2021 Senior Notes. Chris Cline acquired $8.0 million in principal of the Original Purchase and during the year ended December 31, 2015, acquired an additional $36.5 million in principal from third parties in open market transactions. During the years ended December 31, 2015 and 2014, $1.9 million and $0.6 million, respectively, of interest on the 2021 Senior Notes was paid to Chris Cline. As of December 31, 2015, $1.3 million of interest on the 2021 Senior Notes was accrued to the benefit of Chris Cline. The entity controlled by Mr. Dickinson owned $4.0 million of the outstanding principal on our 2021 Senior Notes as of December 31, 2015 and 2014, all of which was acquired from the Original Purchase. During the years ended December 31, 2015 and 2014, $0.3 million of interest on the 2021 Senior Notes was paid to Mr. Dickinson. As of December 31, 2015, $0.1 million of interest on the 2021 Senor Notes was accrued to the benefit of the entity controlled by Mr. Dickinson. As of December 31, 2015, The Cline Trust Company LLC owned $10.0 million in principal of our 2021 Senior Notes, all of which was acquired during the year ended December 31, 2015. During the year ended December 31 2015, no interest had been paid to The Cline Trust Company LLC. As of December 31, 2015, $0.3 million of interest on the 2021 Senior Notes was accrued to the benefit of The Cline Trust Company LLC. Also, Michael Beyer, the former chief executive officer of FELP, who resigned in May 2015, and Drexel Short, a former executive of our predecessor, who retired in March 2014, acquired $3.2 million and $0.5 million, respectively, from the Original Purchase. Mr. Beyer disposed of his 2021 Senior Notes in September of 2015. These former executives were no longer affiliates of the Partnership subsequent to their termination dates. For each of the years ended December 31, 2015 and 2014, $0.3 million of interest was paid to Mr. Beyer and Mr. Short, collectively, while they were affiliates of the Partnership. Mineral Reserve Leases Our mines have a series of mineral reserve leases with Colt, LLC (“Colt”) and Ruger, LLC (“Ruger”), subsidiaries of Foresight Reserves. Each of these leases have initial terms of 10 years with six renewal periods of five years each, at the election of the lessees, and generally require the lessees to pay the greater of $3.40 per ton or 8.0% of the gross sales price, as defined in the respective agreements, of such coal. We also have overriding royalty agreements with Ruger pursuant to which we pay royalties equal to 8.0% of the gross selling prices, as defined in the agreements. Each of these mineral reserve leases generally require a minimum annual royalty payment, which is recoupable only against actual production royalties from future tons mined during the period of ten years following the date on which any such royalty is paid. As of December 31, 2016, we have established a $74.6 million reserve against our contractual prepaid royalties between Colt and our Hillsboro and Macoupin subsidiaries. We determined that our ability to recoup these minimum royalty payments within the remaining recoupment period was improbable in light of, among other factors: • the remaining recoupment period available, as a whole, on these minimum annual royalty payments and the necessary time required to obtain permits on these reserves, • our ability to raise the capital necessary to develop the reserves and the necessary infrastructure was unfavorably impacted by the Restructuring Transactions which resulted in covenants that significantly restrict our ability to incur any additional indebtedness, and • current and forecasted near-term market conditions. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, assessing mine production plans, our access to capital markets, sales commitments, current and forecasted future coal market conditions, the time necessary to obtain required permits and the remaining years available for recoupment. We also lease mineral reserves under lease agreements with subsidiaries of NRP, including WPP, HOD, and Independence Energy, LLC (“Independence”). The initial terms of these agreements vary, however, each carries an option by the lessee to extend the leases until all merchantable and mineable coal has been mined and removed. Royalty payments under these arrangements are generally determined based on the greater of a minimum per ton amount (ranging from $2.50 per ton to $5.40 per ton) or a percentage of the gross sales price (generally 8.0% - 9.0%), as defined in the respective agreements. We are also subject under certain of these mineral reserve agreements to overriding royalties and/or wheelage fees. Our mineral reserve leases with NRP subsidiaries also require minimum quarterly or annual royalties which are generally recoupable on future tons mined and sold during the preceding five-year period from the excess tonnage royalty payments on a first paid, first recouped basis. In July 2015, we provided notice to WPP declaring a force majeure event at our Hillsboro mine due to elevated carbon monoxide levels as a result of a mine fire, which has required the stoppage of mining operations since March 2015. As a result of the force majeure event, we have not made $46.0 million in minimum deficiency payments to WPP in accordance with the force majeure provisions of the royalty agreement. WPP is asserting that the stoppage of mining operations as a result of the combustion event does not constitute an event of force majeure under the royalty agreement (see Note 22). As of December 31, 2016 and 2015, we have established a $34.0 million and $46.3 million reserve, respectively, against contractual prepaid royalties between Hillsboro and WPP given that the recoupment of these prior minimum royalty payments was improbable given the remaining recoupment period available and the Hillsboro combustion event, which has idled this mine since March 2015. The year over year decline in the reserve is attributed to the expiration of the recoupment period on certain of the minimum royalty payments. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, the status of the Hillsboro combustion event, assessing mine production plans, sales commitments, current and forecasted future coal market conditions, and remaining years available for recoupment. Transloading Agreements Convent Marine Terminal Amendment In August 2011, an affiliated company owned by Foresight Reserves acquired the IC RailMarine Terminal in Convent, Louisiana. This terminal, commonly referred to as the Convent Marine Terminal (“CMT”), is owned by Raven Energy LLC (“Raven”), an entity once controlled and beneficially owned by Christopher Cline. The terminal is designed to ship and receive commodities via rail, river barge and ocean vessel. We have a material handling agreement contract for throughput at the terminal under which we pay fees based on the tonnages of coal we move through the terminal, subject to minimum annual take-or-pay volume commitments. Effective May 1, 2015, the Partnership amended its material handling agreement with Raven to reduce the minimum annual throughput volume at CMT to 5.0 million tons and to extend the duration of the contract. In August 2015, The Cline Group sold Raven to an entity under which it does not have significant influence; therefore the business activities with Raven are no longer considered affiliate transactions subsequent to the sale date. Limited Partnership Agreement FEGP manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. Foresight Reserves and Murray Energy have the right to select the directors of the general partner. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to reelection by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership’s business. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses incurred or payments made by the general partner on behalf of the Partnership. No amounts were incurred by the general partner or reimbursed under the partnership agreement from the IPO date to December 31, 2016. Other Williamson leases property from Williamson Transport, an affiliate of NRP, under two surface leases with initial terms through October 15, 2031 and an option to extend the leases in five-year increments until all the coal leased from an NRP affiliate is mined on Williamson’s premises. Williamson Transport has the option to put the land to Williamson for its fair market value as determined by an independent appraiser at any time during the lease term. Additionally, under a separate lease with an initial term through March 12, 2018, Williamson pays $5,000 per year for use of the premises and a fee, currently at $1.84 per ton, for each ton of coal produced at Williamson that is loaded through the Williamson rail loadout facility. Williamson Transport may elect to renew or extend the sublease for successive five-year periods. If Williamson Transport elects not to renew the sublease, Williamson has the option to buy the Williamson rail loadout facility for its fair market value as determined by an independent appraiser. Williamson receives a fee of $0.25 per ton from Williamson Transport for each ton of coal that is loaded through the Williamson rail loadout facility in exchange for operating the loadout. We are party to two surface leases in relation to the coal preparation plant and rail loadout facility at Williamson with New River Royalty, a subsidiary of Foresight Reserves. The primary terms of the leases expire on October 15, 2021, but may be extended by New River Royalty for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases. Additionally, New River Royalty may require Williamson to purchase any portion of either of the leased properties at any time while the leases are in effect for $3,000 per acre. Williamson Transport has the option to purchase any property optioned under the leases if Williamson does not perform its purchase obligation within fifteen days of receiving notice of its purchase obligation. Our Sitran terminal also leases land with New River Royalty for $50,000 per year under a lease that expires in 2020, and which can be extended at the option of the lessee in five year increments. In January 2007, Chris Cline, Foresight Reserves, Adena Minerals LLC and their respective affiliates (collectively, “Adena Entities”) and NRP executed a restricted business contribution agreement. The restricted business contribution agreement obligates the Adena Entities and their affiliates to offer NRP any business owned, operated or invested in by the Adena Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in identified transportation infrastructure relating to certain future mine developments by the Adena Entities in Illinois. NRP’s acquisition of certain coal reserves and infrastructure assets related to our Macoupin, Hillsboro and Sugar Camp mining complexes, discussed above and in Note 11, were deals consummated under the restricted business contribution agreement with the Adena Entities. The Adena Entities are required to offer and could consummate additional deals under the restricted business contribution agreement in the future. During the years ended December 31, 2016, 2015 and 2014, we purchased $6.6 million, $14.5 million and $18.1 million, respectively, in mining supplies from an affiliated joint venture under a supply agreement entered into in May 2013 (see Note 16). The following table presents the affiliate amounts included in our consolidated balance sheets: As of December 31, Affiliated Company Balance Sheet Location 2016 2015 (In Thousands) Foresight Reserves and affiliated entities (1) Due from affiliates - current $ — $ 145 Murray Energy and affiliated entities (2) Due from affiliates - current 16,784 16,316 NRP and affiliated entities Due from affiliates - current 107 154 Total $ 16,891 $ 16,615 Murray Energy and affiliated entities Financing receivables - affiliate - current $ 2,904 $ 2,689 Total $ 2,904 $ 2,689 Murray Energy and affiliated entities Due from affiliates - noncurrent $ 1,843 $ 2,691 Total $ 1,843 $ 2,691 Murray Energy and affiliated entities Financing receivables - affiliate - noncurrent $ 67,235 $ 70,139 Total $ 67,235 $ 70,139 Foresight Reserves and affiliated entities (3) Prepaid royalties - current and noncurrent $ 7,599 $ 69,555 NRP and affiliated entities (3) Prepaid royalties - current and noncurrent 1,246 — Total $ 8,845 $ 69,555 Foresight Reserves and affiliated entities (1) Due to affiliates - current $ 1,373 $ 1,054 Murray Energy and affiliated entities Due to affiliates - current 17,021 5,020 NRP and affiliated entities Due to affiliates - current 2,510 2,462 Total $ 20,904 $ 8,536 (1) – Includes amounts due to/from a joint venture partially owned by an affiliate of The Cline Group – see Note 16. (2) – Includes amounts due from Javelin, a joint venture partially owned by Murray Energy. (3) – Prepaid royalties with Foresight Reserves and affiliated entities is presented net of a $74,575 reserve as of December 31, 2016. Prepaid royalties with NRP and affiliated entities is presented net of a $33,965 and $46,306 reserve as of December 31, 2016 and 2015, respectively. A summary of expenses/income incurred with affiliated entities is as follows for the years ended December 31, 2016, 2015 and 2014: Year Ended December 31, 2016 2015 2014 (In Thousands) Coal sales – Murray Energy and affiliated entities (1) $ 58,395 $ 23,060 $ — Overriding royalty and lease revenues – Murray Energy and affiliated entities (2) $ 7,978 $ 5,387 $ — Terminal revenues - Murray Energy and affiliated entities (2) $ 1,226 $ 282 $ — Royalty expense – (3) $ 17,606 $ 29,773 $ 48,652 Royalty expense – Foresight Reserves and affiliated entities (3) $ 13,921 $ 3,319 $ 11,282 Loadout services – NRP and affiliated entities (3) $ 8,510 $ 9,032 $ 9,878 Purchased goods and services – Murray Energy and affiliated entities (4) $ 8,305 $ 3,326 $ — Purchased coal - Murray Energy and affiliated entities (5) $ 13,541 $ 17,399 $ — Land leases - Foresight Reserves and affiliated entities (3), (6) $ 177 $ — $ 100 Terminal fees – Foresight Reserves and affiliated entities (6) $ — $ 19,327 $ 43,951 Sales commissions - Murray Energy and affiliated entities (7) $ 216 $ — $ — Management services – Murray Energy and affiliated entities (7) $ 8,919 $ 4,667 $ — Administrative fee income – Foresight Reserves and affiliated entities (8) $ — $ 52 $ 256 Principal location in the consolidated financial statements: (1) – Coal sales (2) – Other revenues (3) – Cost of coal produced (excluding depreciation, depletion and amortization) (4) – Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment, as applicable (5) – Cost of coal purchased (6) – Transportation (7) – Selling, general and administrative (8) – Other operating income, net The contractual commitment tables for operating leases and royalty agreements with affiliated parties are disclosed in Note 12. The contractual commitment tables for sales-leaseback arrangements with affiliated parties are disclosed in Note 11.

Variable Interest Entities (VIE

Variable Interest Entities (VIEs)	12 Months Ended
	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Variable Interest Entities (VIEs)	16. Variable Interest Entities (VIEs) Our financial statements have historically included VIEs for which the Partnership or one of its subsidiaries was the primary beneficiary. Among those VIEs consolidated by the Partnership and its subsidiaries were Mach Mining, LLC; M-Class Mining, LLC; MaRyan Mining LLC; Patton Mining LLC; Viking Mining LLC; Coal Field Construction Company LLC; Coal Field Repair Services LLC; Logan Mining LLC; and LD Labor Company LLC (collectively, the “Contractor VIEs”). Each of the Contractor VIEs held a contract to provide one or more of the following services to a Partnership subsidiary: contract mining, processing and loading services, or construction and maintenance services. The Contractor VIEs generally received a nominal per ton fee ($0.01 to $0.02 per ton) above its cost of operations as compensation for services performed. All of these entities were determined not to have sufficient equity at risk and were therefore VIEs. The Partnership was determined to be the primary beneficiary of each of these entities given it controlled these entities under a contractual cost-plus arrangement. During the years ended December 31, 2016, 2015 and 2014, in aggregate, the Contractor VIEs earned income of $0.2 million, $0.5 million and $0.5 million, respectively, under the contractual arrangements with the Partnership which was classified as net income attributable to noncontrolling interests in the consolidated statements of operations. On August 1, 2016, we acquired 100% of the outstanding equity units in each of the Contractor VIEs for aggregate cash consideration of $0.1 million. Because the Contractor VIEs have historically been consolidated as VIEs, and therefore represented entities under common control, the cash proceeds paid in excess of the net book values of the Contractor VIEs on the acquisition date was recorded as a deemed distribution in the statement of partners’ (deficit) capital. We have not experienced any material changes to our operations from the acquisitions of the Contractor VIEs. In January 2016, we contributed $2.5 million to a new entity, Foresight Surety LLC (“Foresight Surety”), whose purpose was to obtain and maintain a letter of credit for the benefit of one of our surety bond providers. We hold all of the economic units of Foresight Surety and a professional service provider with which we have had a long-standing relationship holds all of its voting rights. Foresight Surety is a VIE given that the holder of all of the economic rights has no ability to exercise power over it. We were determined to be the primary beneficiary of Foresight Surety, and therefore consolidate Foresight Surety, as the professional service provider with all of the voting rights was determined to be acting as our de facto agent and therefore we would aggregate voting power. In February 2016, Foresight Surety obtained a $2.5 million letter of credit with a lender for the benefit of one of our surety bond providers. The letter of credit is secured by the $2.5 million of cash we contributed to Foresight Surety. In August 2013, FELLC effected a reorganization pursuant to which certain transportation assets were distributed to its members (the “2013 Reorganization”). Among the assets distributed were Adena and Hillsboro Transport. Subsequent to the 2013 Reorganization, both of these entities were identified as VIEs and continued to be consolidated by FELLC. As such, the aggregate net book values of Adena and Hillsboro Transport of $10.1 million on the distribution date was reclassified from predecessor members’ equity to noncontrolling interest equity on the 2013 Reorganization date. During the years ended December 31, 2015 and 2014, Adena and Hillsboro Transport as VIEs earned income, in aggregate, of $0.3 million and $3.4 million, respectively, which was classified as net income attributable to noncontrolling interests in the consolidated statements of operations. During the first quarter of 2015, Adena and Hillsboro Transport were contributed to us by Foresight Reserves and a member of management (see Note 18) and are therefore no longer consolidated as VIEs. The aggregate net book values of Adena and Hillsboro Transport of $9.9 million was reclassified from noncontrolling interest equity to limited partners’ capital on the contribution dates. The liabilities recognized as a result of consolidating the VIEs do not necessarily represent additional claims on the general assets of the Partnership outside of the VIEs; rather, they represent claims against the specific assets of the consolidated VIEs. Conversely, assets recognized as a result of consolidating these VIEs do not necessarily represent additional assets that could be used to satisfy claims against the Partnership’s general assets. Long-term assets in the table below is comprised of restricted cash which provided collateral to an outstanding letter of credit. There are no other restrictions on the VIE assets that are reported in our general assets. The total consolidated VIE assets and liabilities reflected in the Partnership’s consolidated balance sheets are as follows: December 31, 2016 December 31, 2015 (In Thousands) Assets: Current assets $ — $ 4,933 Long-term assets 2,500 — Total assets $ 2,500 $ 4,933 Liabilities: Current liabilities $ — $ 12,835 Long-term liabilities — 2,955 Total liabilities $ — $ 15,790 In May 2013, an affiliate owned by The Cline Group and a third-party supplier of mining supplies formed a joint venture whose purpose is the manufacture and sale of supplies primarily for use by the Partnership in the conduct of its mining operations. The agreement obligates the Partnership’s coal mines to purchase at least 90% of their aggregate annual requirements for certain mining supplies from the supplier parties, subject to exceptions as set forth in the agreement. The initial term of the amended agreement is five years and expires in April 2018. The supplies sold under this arrangement result in an agreed-upon fixed profit percentage for the joint venture. This joint venture was determined to be a VIE given that the equity holders do not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the joint venture as a result of the Partnership effectively guaranteeing a fixed-profit percentage on the supplies it purchases from the joint venture. We are not the primary beneficiary of this joint venture and, therefore, do not consolidate the joint venture, given that the power over the joint venture is conveyed through the board of directors of the joint venture and no party controls the board of directors.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	17. Fair Value of Financial Instruments The tables below set forth, by level, the Partnership’s net financial assets and liabilities for which fair value is measured on a recurring basis: Fair Value at December 31, 2016 Total Level 1 Level 2 Level 3 (In Thousands) Coal derivative contracts $ 7,315 $ — $ 7,315 $ — Warrant liability (51,169 ) — — (51,169 ) Total $ (43,854 ) $ — $ 7,315 $ (51,169 ) Fair Value at December 31, 2015 Total Level 1 Level 2 Level 3 (In Thousands) Coal derivative contracts $ 48,623 $ — $ 48,623 $ — Diesel derivative contracts (1,029 ) — (1,029 ) — Total $ 47,594 $ — $ 47,594 $ — The Partnership’s commodity derivative contracts are valued based on direct broker quotes and corroborated with market pricing data. During the years ended December 31, 2016, 2015 and 2014, there were no assets or liabilities that were transferred between Level 1 and Level 2. The classification and amount of the Partnership’s financial instruments measured at fair value on a recurring basis, which are presented on a gross basis in the consolidated balance sheets as of December 31, 2016 and 2015, are as follows: Fair Value at December 31, 2016 Current – Long-Term – Coal Derivative Assets Accrued Expenses Warrant Liability (In Thousands) Coal derivative contracts $ 7,650 $ — $ (335 ) $ — Warrant liability — — — (51,169 ) Total $ 7,650 $ — $ (335 ) $ (51,169 ) Fair Value at December 31, 2015 Current – Long-Term – Coal Derivative Assets Accrued Expenses Warrant Liability (In Thousands) Coal derivative contracts $ 26,596 $ 22,027 $ — $ — Diesel derivative contracts — — (1,029 ) — Total $ 26,596 $ 22,027 $ (1,029 ) $ — The following is a reconciliation of the beginning and ending balances for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3): Warrant Liability (In Thousands) Balance at January 1, 2016 $ — Purchases, issuances and settlements 34,045 Recorded fair value losses: Included in earnings - loss / (gain) 17,124 Balance at December 31, 2016 $ 51,169 On the Closing Date, FELP issued Warrants to the unaffiliated owners of the Second Lien Notes to purchase an amount of common units equal to an aggregate of 4.5% of the total limited partner units of FELP outstanding on the date of a Note Redemption (after giving effect to the full exercise of the Warrants and the Note Redemption, subject to certain anti-dilution protections), exercisable upon a Note Redemption and until the tenth anniversary of the Note Redemption. The exercise price of the Warrants is $0.8928 per Common Unit, subject to certain adjustments. The number of common units issuable upon the conversion of the Warrants will be determinable as of the date of a Note Redemption. If a Note Redemption does not occur on or prior to the Exchangeable PIK Notes Maturity Date, the Warrants will not become exercisable. The Warrants are required to be accounted for as a liability at fair value and the fair value must be revalued at each balance sheet date until the earlier of the exercise of the Warrants, their expiration, or until any of the features requiring liability treatment expires or is modified. The resulting non-cash gain or loss on the fair value revaluation at each balance sheet date is recorded as non-operating loss in our consolidated statements of operations The fair value of the Warrants was calculated using the Black-Scholes pricing model (including the use of a binomial lattice to model the conversion and redemption scenarios for the Exchangeable PIK Notes) which is based, in part, upon unobservable inputs for which there is little or no market data (Level 3), requiring the Partnership to develop its own assumptions. A stock price volatility of 70%, a dividend yield of 0% and a risk-free forward rate of 2.61% was used in the Black-Scholes pricing model. Long-Term Debt The fair value of long-term debt as of December 31, 2016 and 2015 was $1,378.6 million and $1,244.3 million, respectively. The fair value of long-term debt was calculated based on the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms. This is considered a Level 3 fair value measurement.

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Partners' Capital	18. Partners’ Capital Common and Subordinated Units All subordinated units are currently held by Murray Energy. The principal difference between our common units and subordinated units is that subordinated unitholders are not entitled to receive a distribution from operating surplus until the holders of common units have received the minimum quarterly distribution (“MQD”) from operating surplus. The MQD is $0.3375 per unit for such quarter plus any cumulative arrearages of previously unpaid MQDs from previous quarters. Also, subordinated unitholders are not entitled to receive arrearages. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, on the first business day after the Partnership has paid the MQD for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2017 and there are no outstanding arrearages on the common units. Notwithstanding the foregoing, the subordination period will end on the first business day after the Partnership has paid an aggregate amount of at least $2.025 per unit (150.0% of the MQD on an annualized basis) on the outstanding common and subordinated units and the Partnership has paid the related distribution on the incentive distribution rights, for any four-quarter period ending on or after March 31, 2015 and there are no outstanding arrearages on the common units. Given that distributions have not been paid beginning with the quarter ended December 31, 2015 arrearages have accrued to the benefit of common unitholders, should future distributions be paid. Our partnership agreement provides that our general partner will make a determination as to whether a distribution will be made, subject to, among other factors, compliance with our debt agreements. Our partnership agreement does not require us to pay distributions at any time or at any amount. Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders. Incentive Distribution Rights (“IDRs”) Our IDRs are held by Murray Energy, Chris Cline and a former member of management. IDRs represent the right to receive an increasing percentage of quarterly distributions from operating surplus after the MQD and the target distribution levels (described below) have been achieved. Our general partner may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. The IDR holders will have the right, subsequent to the subordination period and subject to distributions exceeding the MQD by at least 150% for four consecutive quarters, to reset the target distribution levels and receive common units. Allocation of Net Income (Loss) Our partnership agreement contains provisions for the allocation of net income and loss to the unitholders and the general partner. For purposes of maintaining partner capital accounts, the partnership agreement generally specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interest. Percentage Allocation of Distributions from Operating Surplus The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our IDRs based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the IDR holders and the unitholders of any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Common Unit”. The percentage interests shown for our unitholders and the IDR holders for the MQD are also applicable to quarterly distribution amounts that are less than the MQD. The percentage interests set forth below excludes the impact of arrearages which would first be due to common unitholders before the IDR holders would receive a distribution. Total Quarterly Distribution Marginal Percentage Unitholders IDR Holders Minimum quarterly distribution $0.3375 100.0 % — First target distribution Above $0.3375 up to $0.3881 100.0 % — Second target distribution Above $0.3881 up to $0.4219 85.0 % 15.0 % Third target distribution Above $0.4219 up to $0.5063 75.0 % 25.0 % Thereafter Above $0.5063 50.0 % 50.0 % Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders and general partner will receive. Equity Contributions and Distributions The follow table summarizes the quarterly distribution paid per limited partner unit (except as noted) during the years ended December 31, 2016, 2015 and 2014: Year Ended December 31, 2016 2015 2014 (Per limited partner unit, except as noted) First Quarter $ — $ 0.36 n/a Second Quarter $ — $ 0.37 n/a Third Quarter $ — $ 0.38 $ 0.03 Fourth Quarter (a) $ — $ 0.06 $ 0.35 (a) – In November 2015, we paid a quarterly distribution of $0.17 per unit payable to common unitholders, while suspending the distribution on all subordinated units. Chris Cline and one additional common unitholder elected to forego the $0.17 per common unit distribution on their collective 21.2 million common units. During the year ended December 31, 2016, Foresight Reserves incurred $1.0 million of one-time employee compensation costs classified as transition and reorganization costs for which it will not seek reimbursement from the Partnership. The noncash contribution from Foresight Reserves increased the Partnership’s limited partners’ capital accounts. During the first quarter of 2015 (the “Contribution Date”), Foresight Reserves and a member of management contributed back to FELP, for no consideration, 100% of the equity of Sitran LLC (“Sitran”), Adena and Hillsboro Transport (the “Contributed Companies”). In addition, Foresight Reserves and a member of management contributed, for no consideration, Akin Energy LLC, an entity holding certain permits and development costs for a natural gas power generation facility. Because Sitran and Akin Energy were under common control, the Partnership’s historical financial statements have been retrospectively adjusted to combine their financial position at historical cost and their results of operations. The equity values of Sitran and Akin Energy prior to the Contribution Date are included in predecessor equity in the statement of partners’ capital (deficit). Hillsboro Transport and Adena were previously consolidated by the Partnership as VIEs; therefore the contribution did not result in a change in reporting entity (see Note 16). On the Contribution Date, the net book values of the Contributed Companies were reclassified from either predecessor equity or noncontrolling interest, as applicable, to limited partners’ capital in the statement of partners’ capital (pro rata between the common and subordinated units based on the number of units held by the contributing parties on the Contribution Date). The aggregate net book value of the Contributed Companies on the Contribution Date was $60.6 million. During the year ended December 31, 2015, Foresight Reserves incurred $11.3 million of one-time employee compensation costs classified as transition and reorganization costs for which it will not seek reimbursement from the Partnership. The noncash contribution from Foresight Reserves increased the Partnership’s limited partners’ capital accounts. Of the $11.3 million contribution amount, $1.3 million was deferred as a prepaid expense and amortized over the required remaining retention period in 2016. On June 23, 2014, in connection with the IPO, Foresight Reserves and a member of management each contributed their membership interests in FELLC to the Partnership in exchange for common and subordinated units of FELP. As a result, the members’ deficit balance of $104.9 million at the time of the transfer was allocated, pro rata based on units outstanding, to common and subordinated unitholder capital accounts. In connection with the acquisition of Seneca Rebuild on April 1, 2014, a deemed distribution in the amount of $0.3 million was recorded to reflect the excess of the purchase price paid by FELLC over the carrying value of the net assets acquired. Noncontrolling Interests Noncontrolling interests’ equity and net income attributable to noncontrolling interests result from the consolidation of variable interest entities for which the Partnership has no equity interests. On August 1, 2016, we acquired 100% of the outstanding equity units in each of the Contractor VIEs for aggregate cash consideration of $0.1 million. Because the Contractor VIEs have historically been consolidated as VIEs, and therefore represented entities under common control, the cash proceeds paid in excess of the net book values of the Contractor VIEs on the acquisition date was recorded as a deemed distribution in the statement of partners’ (deficit) capital and the net book value of the Contractor VIEs on the acquisition date was reclassified from noncontrolling interest equity to limited partners equity. We do not expect any material changes to our operations from the acquisitions of the Contractor VIEs.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity-Based Compensation	19. Equity-Based Compensation Long-Term Incentive Plan The Partnership has adopted a Long-Term Incentive Plan ("LTIP" or the “Plan”) for employees, directors, officers and certain key third-parties (collectively, the "Participants"). The Plan allows for the issuance of equity-based compensation in the form of phantom units, unit awards, unit options, unit appreciation rights, restricted units, other unit-based awards, distribution equivalent rights, performance awards, and substitute awards to Participants. The LTIP awards granted thus far are phantom units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive FELP common units. The Board of Directors of the Partnership authorized 7.0 million common units to be granted under the LTIP, with 4.8 million units available for grant as of December 31, 2016. Grant levels and vesting requirements are recommended by the Partnership's chief executive officer, subject to the review and approval by the board of directors. LTIP Awards During the years ended December 31, 2016, 2015 and 2014, the Partnership granted 0, 1,838,099 and 595,075 phantom units, respectively, to employees under the LTIP. Of the phantom unit LTIP awards granted during the years ended December 31, 2015 and 2014, 431,750 and 72,500, respectively, were vested immediately on the grant date. This includes an equity award granted to the former chief executive officer of the Partnership in February 2015 of 215,954 common units and 215,796 subordinated units which fully-vested on the grant date. The remaining awards are considered time-based unit awards and generally cliff-vest, subject to continued employment, over the required service period (with accelerated vesting under certain instances). The required service periods vary but are generally three-year periods. Compensation expense for these awards is recognized on a straight-line basis over the requisite service period. Upon vesting, the Partnership will issue authorized and unissued shares of the Partnership’s common units to the recipient. As of December 31, 2016, 203,918 phantom units granted to employees under the LTIP were non-vested. Director Awards During the years ended December 31, 2016, 2015 and 2014, the Partnership granted 58,851, 35,324 and 7,919 phantom units, respectively, to non-employee directors under the LTIP. These awards are considered time-based unit awards and vest ratably over a three-year period. Compensation expense for these awards is recognized on a straight-line basis over the requisite service period. As of December 31, 2016, 74,621 phantom units granted to nonemployee directors under the LTIP were non-vested. Summary For the year ended December 31, 2016, 2015 and 2014, our equity-based compensation expense was $5.1 million, $13.7 million and $5.0 million, respectively, net of forfeitures. During the year ended December 31, 2014, $0.3 million of equity-based compensation was capitalized into mine development costs. During the years ended December 31, 2016, 2015 and 2014, the Partnership’s equity-based compensation is recorded in the consolidated statements of operations as follows: December 31, Location in statements of operations: 2016 2015 2014 Selling, general and administrative 2 % 58 % 63 % Transition and reorganization costs 84 % 31 % — Cost of coal produced (excluding depreciation, depreciation and amortization) 14 % 11 % 37 % As of December 31, 2016, the total unrecognized compensation expense for phantom unit awards that are expected to vest was $1.0 million. The non-vested phantom unit awards will be recognized over a weighted-average period of 1.0 year. The intrinsic value of the non-vested LTIP awards was $1.8 million as of December 31, 2016. All non-vested phantom units include tandem distribution incentive rights, which provide for the right to accrue quarterly cash distributions in an amount equal to the cash distributions the Partnership makes to unitholders during the vesting period and will be settled in cash upon vesting. The Partnership has $0.3 million accrued for this liability as of December 31, 2016. Any distributions accrued to a Participants’ account will be forfeited if the related phantom award fails to vest according to the relevant vesting conditions. A summary of LTIP award activity for the years ended December 31, 2015 and 2016 is as follows: Number of Units Weighted Average Grant Date Fair Value per Unit Non-vested grants at January 1, 2015 601,109 $ 19.99 Granted 1,873,423 $ 7.28 Vested (652,786 ) $ 17.25 Forfeited (110,405 ) $ 18.63 Non-vested grants at December 31, 2015 1,711,341 $ 7.21 Granted 58,851 $ 3.82 Vested (1,421,662 ) $ 4.76 Forfeited (69,991 ) $ 19.60 Non-vested grants at December 31, 2016 278,539 $ 15.88 During the years ended December 31, 2016, 2015 and 2014, the Partnership settled 509,378, 75,522 and 53,745 units, respectively, of vested equity awards in cash to satisfy the individual statutory minimum tax obligations of the LTIP participants.

Earnings per Limited Partner Un

Earnings per Limited Partner Unit	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings per Limited Partner Unit	20. Earnings per Limited Partner Unit Limited partners’ interest in net (loss) income attributable to the Partnership and basic and diluted earnings per unit reflect net (loss) income attributable to the Partnership subsequent to the June 23, 2014 closing date of the IPO. We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in Accounting Standards Codification (“ASC”) 260, Earnings Per Share The Partnership’s net (loss) income is allocated to the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to any special income or expense allocations and incentive distributions paid to the general partner, if any. The partnership agreement contractually limits distributions to available cash as determined by our general partner; therefore, undistributed earnings of the Partnership are not allocated to the IDR holder. There were no allocations of earnings to participating securities during the periods presented below. Basic EPU is computed by dividing net earnings attributable to unitholders by the weighted-average number of units outstanding during each period. Diluted EPU reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units. The following table illustrates the Partnership’s calculation of net (loss) income per common and subordinated unit for the period indicated: Year Ended December 31, 2016 2015 2014 Common Units Subordinated Units Total Common Units Subordinated Units Total Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Distributed earnings $ — $ — $ — $ 79,733 $ 72,100 $ 151,833 $ 24,619 $ 24,601 $ 49,220 Distributions in excess of earnings and undistributed (loss) earnings (90,015 ) (88,774 ) (178,789 ) (95,776 ) (95,534 ) (191,310 ) 10,535 10,437 20,972 Net (loss) income available to limited partner units $ (90,015 ) $ (88,774 ) $ (178,789 ) $ (16,043 ) $ (23,434 ) $ (39,477 ) $ 35,154 $ 35,038 $ 70,192 Denominator: Weighted-average units to calculate basic EPU 65,829 64,955 130,784 65,098 64,934 130,032 64,790 64,739 129,529 Less: effect of dilutive securities (1) — — — — — — — — — Weighted-average units to calculate diluted EPU 65,829 64,955 130,784 65,098 64,934 130,032 64,790 64,739 129,529 Basic net (loss) income per unit $ (1.37 ) $ (1.37 ) $ (1.37 ) $ (0.25 ) $ (0.36 ) $ (0.30 ) $ 0.54 $ 0.54 $ 0.54 Diluted net (loss) income per unit $ (1.37 ) $ (1.37 ) $ (1.37 ) $ (0.25 ) $ (0.36 ) $ (0.30 ) $ 0.54 $ 0.54 $ 0.54 (1) Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the years ended December 31, 2016, 2015 and 2014, approximately 0.3 million, 1.7 million and 0.6 million, respectively, phantom units were anti-dilutive, and therefore were excluded from the diluted EPU calculation. Diluted EPU also is not impacted during the periods presented by any units which could be issued as a result of the Warrants or the Exchangeable PIK Notes. See Notes 10 and 17.

Risk Concentrations

Risk Concentrations	12 Months Ended
	Dec. 31, 2016
Risks And Uncertainties [Abstract]
Risk Concentrations	21. Risk Concentrations Sales and Credit Risk We determine creditworthiness for trade customers based on an evaluation of the customer’s financial condition. Credit losses have historically been minimal. The aggregate outstanding trade receivable balance as of December 31, 2016 from customers representing greater than 10% of our total sales was $14.0 million. Also, as of December 31, 2016, we had outstanding accounts receivable and financing receivables with Murray Energy and its affiliates of $18.6 million and $70.1 million, respectively (see Note 15). For the years ended December 31, 2016, 2015 and 2014, the following customers (aggregated at the parent company level) exceeded 10% of total coal sales: For the Year Ended December 31, 2016 2015 2014 (Percentage of Total Coal Sales) Customer A 30% 22% 16% Customer B 10% 12% 12% Customer C 13% 11% (A) Customer D (A) (A) 11% (A) – Less than 10% of total coal sales for this period. During the years ended December 31, 2016, 2015 and 2014, export tons represented 17%, 24% and 30% of tons sold, respectively. Tons exported into Europe/UK during the years ended December 31, 2016, 2015 and 2014 represented approximately 16%, 22% and 26%, respectively, of total tons sold during those years. No other international geographic regions exceeded 10% of tons sold during the years ended December 31, 2016, 2015 and 2014. Our domestic coal sales are principally to electric utility companies in the eastern United States with installed pollution control devices. Transportation The Partnership depends on rail, barge, and export terminal systems to deliver coal to its customers. Disruption of these services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Partnership’s ability to supply coal to its customers, resulting in decreased shipments. As such, the Partnership has sought to diversify transportation options and has entered into long-term contracts with transportation providers to ensure transportation is available to transport its coal.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Contingencies	22. Contingencies In December 2016, we reached settlement with the U.S. Equal Employment Opportunity Commission regarding discriminatory hiring practices. The aggregate settlement amount was $4.3 million of which our insurance covered $3.8 million. In December 2016, we paid $3.7 million to settle the outstanding claims against us from certain railcar lessors asserting that our use of the railcars during the lease term cause damage to the railcars. In August 2016, FELP completed its global restructuring. The restructuring transactions alleviated existing defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Court of Chancery Court change-of-control litigation related to the purchase and sale agreement between the significant equity holders in the Partnership’s general partner, Foresight Reserves and Murray Energy. In conjunction with the completion of the global restructuring, the litigation has been dismissed with prejudice. See Note 3 for additional discussion. In January 2016, certain plaintiffs filed suit against us In January 2016, WPP sent a demand letter to Macoupin claiming it had misapplied the royalty recoupment provision involving a coal mining lease and a rail infrastructure lease resulting in underpayments of $3.3 million. In April 2016, WPP and HOD filed a complaint in the Circuit Court of Macoupin County, Illinois. We do not believe that the royalty recoupment provision was misapplied and have continued to apply the recoupment provision consistently with prior periods. While we believe that the language of the agreements and the parties’ course of performance thereunder support Macoupin’s position, should we not prevail, we would be responsible for paying WPP for any recoupment taken that is found to contravene the contractual language. In July 2015, we provided notice to WPP, a subsidiary of NRP, declaring a force majeure event at our Hillsboro mine due to a combustion event. As a result of the force majeure event, as of December 31, 2016, we have not made $46.0 million in minimum deficiency payments to WPP in accordance with the force majeure provisions of the royalty agreement. On November 24, 2015, WPP filed a Complaint in the Circuit Court of Montgomery County, Illinois, against Hillsboro. After we prevailed on various motions to dismiss the Complaint, as well as the First and Second Amended Complaints, WPP filed its Third Amended Complaint on January 16, 2017. In the Third Amended Complaint, WPP alleges that (i) the stoppage of mining operations as a result of the spontaneous combustion event does not constitute an event of force majeure under the royalty agreement, (ii) Hillsboro’s reliance on the force majeure language is a breach of the royalty agreement, and (iii) that Hillsboro’s failure to recommence mining is a further breach of the royalty agreement. Hillsboro denies each of these allegations. In addition, WPP, in the Third Amended Complaint, names Foresight Energy GP, LLC; Foresight Energy, LP; Foresight Energy, LLC; Foresight Energy Services, LLC; Coal Field Construction Company, LLC; and Patton Mining, LLC as defendants. The Third Amended Complaint alleges that the Foresight Defendants (i) are alter egos of Hillsboro, (ii) are direct participants in Hillsboro’s conduct, and (iii) have tortiously interfered with the royalty agreement. Additionally, the Third Amended Complaint alleges that all of the defendants were negligent in the operation of the mine, and, further, the Third Amended Complaint seeks an order compelling “specific performance” of the royalty agreement by directing Hillsboro to recommence mining in a separate area of the mine. Motions to Dismiss have been filed addressing each of the non-contractual claims. . While we believe this is a force majeure event, as contemplated by the royalty agreement, and that the alleged claims are without merit, should we not prevail, we would be responsible for funding any minimum deficiency payment amounts during the shutdown period to WPP and potentially additional fees. In November 2012, six citizens filed requests for administrative review of Revision No. 1 to Permit No. 399 for the Hillsboro mine. Revision No. 1 allowed for conversion of the currently permitted coal refuse disposal facility from a non-impounding to an impounding structure. On February 14, 2017, the Circuit Court of Montgomery County, Illinois upheld the hearing officer’s decision that Revision No. 1 to Permit No. 399 for the Hillsboro mine was properly issued by IDNR. To the extent necessary, Hillsboro intends to continue its defense of the issuance of the permit. We are also party to various other litigation matters, in most cases involving ordinary and routine claims incidental to our business. We cannot reasonably estimate the ultimate legal and financial liability with respect to all pending litigation matters. However, we believe, based on our examination of such matters, that the ultimate liability will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. As of December 31, 2016, we have $4.8 million accrued, in aggregate, for various litigation matters. Insurance Recoveries We are currently in discussions with our insurance provider in regards to further potential recoveries under our policy related to the combustion event at our Hillsboro operation. During the year ended December 31, 2016, we recorded $10.5 million to cost of coal produced (excluding depreciation, depletion and amortization) in our consolidated statement of operations for the insurance recovery of mitigation costs (net of our policy deductible) and $20.0 million to other operating (income) expense related to business interruption insurance proceeds. However, there can be no assurances that we will receive any further insurance recoveries related to this incident. Performance Bonds We had outstanding surety bonds with third parties of $83.4 million as of December 31, 2016 to secure reclamation and other performance commitments. In February 2016, we were required to post cash collateral of $2.5 million to our surety bond provider and Foresight Reserves has provided a guarantee on $50.5 million of the surety bonds.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2016
Compensation And Retirement Disclosure [Abstract]
Employee Benefit Plans	23. Employee Benefit Plans The Partnership offers safe harbor 401(k) plans (the “Plans”) for all employees who are eligible to participate. Employees are immediately eligible to participate upon becoming a full-time employee with the Partnership and its subsidiaries and affiliates. The Plans allow for the deferral of all or part of a participant’s compensation, as defined by the Plans, up to the current limits provided by the Internal Revenue Service. The safe harbor matching feature calls for the Partnership to contribute 100% of the first 3% of compensation a participant contributes, and 50% of the next 2% of compensation contributed by the participant. Partnership contributions under the Plans for the years ended December 31, 2016, 2015, and 2014 were $3.0 million, $3.3 million, and $3.1 million, respectively.

Selected Quarterly Financial In

Selected Quarterly Financial Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Information	24. Selected Quarterly Financial Information A summary of the unaudited quarterly results for the years ended December 31, 2016 and 2015 is presented below: For the Year Ended December 31, 2016 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (In Thousands, Except per Unit Data) Revenues $ 166,085 $ 226,000 $ 230,825 $ 252,922 Operating income (loss) $ 1,205 $ 12,585 $ 31,414 $ (22,475 ) Net loss $ (41,607 ) $ (27,670 ) $ (24,331 ) $ (85,012 ) Net loss attributable to limited partner units $ (41,704 ) $ (27,786 ) $ (24,287 ) $ (85,012 ) Basic and diluted loss per limited partner unit $ (0.32 ) $ (0.21 ) $ (0.19 ) $ (0.65 ) For the Year Ended December 31, 2015 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (In Thousands, Except per Unit Data) Revenues $ 238,915 $ 251,222 $ 253,066 $ 241,650 Operating income (loss) $ 70,058 $ 4,079 $ 38,079 $ (29,659 ) Net income (loss) $ 42,717 $ (25,280 ) $ 8,188 $ (64,309 ) Net income (loss) attributable to limited partner units $ 42,283 $ (25,403 ) $ 8,070 $ (64,427 ) Basic and diluted income (loss) per limited partner unit $ 0.33 $ (0.20 ) $ 0.06 $ (0.49 ) During the first, second and third quarters of 2016, we recognized debt restructuring costs of $9.7 million, $5.9 million, and $6.1 million, respectively. During the third quarter of 2016, we recognized $10.5 million of insurance recoveries in cost of coal sales (excluding depreciation, depletion and amortization) related to the direct mitigation costs we incurred during 2015 and 2016 from the Hillsboro combustion event. During the third quarter of 2016, we recognized a $13.2 million loss related to the early extinguishment of debt due to the restructuring of our debt. During the fourth quarter of 2016, we recorded a long-lived asset impairment charge of $74.6 million related to certain affiliate prepaid royalties for which we determined recoupment was improbable. During the fourth quarter of 2016, we recognized $20.0 million of other operating income related to business interruption insurance recoveries from the Hillsboro combustion event, which has idled the mine since March 2015. During the fourth quarter of 2016, we recorded an $18.6 million loss for the change in fair value of the Warrants. In the first quarter of 2015, $13.5 million was recognized as other operating income for a settlement agreement with Murray Energy resolving litigation between the Partnership and Murray Energy. In the second, third and fourth quarters of 2015, we recorded transition and reorganization costs of $12.3 million, $5.0 million and $4.1 million, respectively, to reorganize certain corporate administrative functions to optimize synergies between the Partnership and Murray Energy. In the fourth quarter of 2015, we recorded long-lived asset impairment charges of $12.6 million to impair $11.6 million of Hillsboro prepaid royalties with an affiliate and to write-off $1.0 million of deferred longwall costs at Hillsboro which are being abandoned as a result of the mine fire.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	25. Subsequent Events On February 13, 2017, we announced that we have commenced a process to refinance and extend the maturities of all or a portion of our existing indebtedness with the net proceeds from a combination of debt, equity financing and/or cash on hand. There can be no assurance regarding the results of the Partnership’s refinancing and maturity extension efforts.

Valuation and Qualifying Accoun

Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2016
Valuation And Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	Foresight Energy LP Schedule II — Description Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Deductions Written-off / Other Balance at End of Period (In Thousands) 2016 Reserves deducted from asset accounts: Prepaid royalty recoupment reserve $ 46,306 $ 74,575 $ — $ — $ (12,341 ) $ 108,540 Reserve for materials and supplies 458 516 — — (254 ) 720 2015 Reserves deducted from asset accounts: Prepaid royalty recoupment reserve $ 34,700 $ 11,606 $ — $ — $ — $ 46,306 Reserve for materials and supplies — 458 — — — 458 2014 Reserves deducted from asset accounts: Prepaid royalty recoupment reserve $ — $ 34,700 $ — $ — $ — $ 34,700 Reserve for materials and supplies — — — — — —

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and loss during the reporting period. Actual results could differ from those estimates.
Revenue Recognition	Revenue Recognition Once mines are in production, coal sales include sales to customers of coal produced and, from time to time, the re-sale of coal purchased from third parties or from one of our affiliates. The Partnership recognizes sales at the time legal title and risk of loss pass to the customer at contracted amounts that are fixed or determinable. For domestic coal sales, this generally occurs when coal is loaded onto railcars at the mine or onto barges at terminals. For coal sales to international markets, this generally occurs when coal is loaded onto an ocean vessel. Quality and weight adjustments are recorded as necessary based on contract specifications as a reduction or increase to coal sales and accounts receivable.
Transportation Expenses	Transportation Expenses Costs related to the handling and transporting of coal to the point of sale are included in coal inventory in the consolidated balance sheets. Upon the recognition of the sale, these costs are included in transportation expenses in the consolidated statements of operations.
Cash and Cash Equivalents	Cash and Cash Equivalents The Partnership considers cash deposits with original maturities of less than three months to be cash and cash equivalents. Cash and cash equivalents are stated at cost, which approximates fair value.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts The Partnership evaluates the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables and disputed amounts. Historically, credit losses have been insignificant. At December 31, 2016 and 2015, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.
Inventories, Net	Inventories, Net Inventories are valued at the lower of average cost or market. Parts and supplies inventory consists of spare parts for equipment and supplies used in the mining process. A reserve is established for items determined to be obsolete or in excess of quantities needed. Raw coal represents coal stockpiles that require processing through a preparation plant prior to shipment to a customer. Clean coal represents coal stockpiles that will be sold in its current condition. Coal inventory costs include labor, equipment costs, supplies, transportation costs incurred prior to the transfer of title to customers, depreciation, depletion, amortization and direct mine operating overhead.
Deferred Longwall Costs	Deferred Longwall Costs The Partnership defers the direct costs associated with longwall moves, including longwall set-up costs, labor and supply costs to perform the move and refurbishment costs of longwall equipment. These deferred costs are expensed on a units-of-production basis into cost of coal produced (excluding depreciation, amortization and depreciation) over the panel benefited by these costs, which has historically approximated one year.
Prepaid Royalties	Prepaid Royalties Prepaid royalties consist of recoupable minimum royalty payments due under various lease agreements entered into by the Partnership. Prepaid royalties expected to be recouped within one year are classified as current assets in the Partnership’s consolidated balance sheets. The Partnership continually evaluates its ability to recoup prepaid royalty balances, which includes, among other factors, assessing mine production plans, sales commitments, future coal market conditions and remaining years available for recoupment. The contractual recoupment periods on the prepaid royalty balances generally range from five to ten years from the date the minimum royalty was paid.
Murray Energy Transport Lease and Overriding Royalty Agreements	Murray Energy Transport Lease and Overriding Royalty Agreements In April 2015, American Century Transport LLC (“American Transport”), a subsidiary of the Partnership, entered into a purchase and sale agreement (the “PSA”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, pursuant to which American Energy sold to American Transport certain mining and transportation assets for $63.0 million. Concurrent with the PSA, American Transport entered into a lease agreement (the “Transport Lease”) with American Energy pursuant to which (i) American Transport leased to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at the Transport Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport receives from American Energy a fee ranging from $1.15 to $1.75 for every ton of coal mined, processed and/or transported using such assets, subject to a quarterly recoupable minimum fee of $1.7 million. The Transport Lease is being accounted for as a direct financing lease. The unearned income is reflected as other revenue over the term of the lease using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned. Also, in April 2015, American Century Minerals LLC (“Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement (“ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company (collectively, “AEC”), pursuant to which AEC granted to Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The ORRA is subject to a minimum recoupable quarterly fee of $0.5 million. This overriding royalty was accounted for as a financing arrangement. The payments the Partnership receives with respect to the ORRA are reflected partially as a return of the initial investment (reduction in the affiliate financing receivable) and partially as other revenue over the life of the agreement using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned.
Property, Plant, Equipment and Development, Net	Property, Plant, Equipment and Development, Net Property, plant and equipment are recorded at cost. Costs that extend the useful lives or increase the productivity of the assets are capitalized, while normal repairs and maintenance that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Asset retirement obligations for the various assets have been recorded as components of the primary assets to which they Machinery and equipment 3–20 years Buildings and structures 3–40 years Other 3–20 years Costs of developing new mines or expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the mineral reserves benefited by the development. Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred. During the development phase, the Partnership establishes access to the mineral reserves and makes other preparations for commercial production. Development costs principally include clearing land, building roads, sinking shafts, driving slopes and developing refuse areas, ventilation and transportation passageways at the mines. Development costs also include the build-out of the Partnership’s transportation infrastructure. Costs incurred during the mine development phase are capitalized and proceeds from the incidental sale of coal during development are recorded as a reduction of the related mine development costs. For reporting in the statements of cash flows, cash expended in the investment in mining rights, equipment and development during the development phase is reported net of capitalized coal sales.
Impairment of Depreciable Assets	Impairment of Depreciable Assets The Partnership records impairment losses on de preciable assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount.
Debt Issuance Costs	Debt Issuance Costs The Partnership capitalizes costs incurred in connection with the issuance of debt and the establishment of credit facilities and capital leasing arrangements. Debt financing costs related to revolving credit facilities are recorded as an asset in our consolidated balance sheets and deferred issuance costs related to non-revolving facilities is recorded as a contra to the debt balance. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using either the effective interest method or straight-line method, as applicable. Amortization expense of $7.5 million, $6.0 million and $6.1 million is included in interest expense for the years ended December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016 and 2015, unamortized debt issuance costs were $19.3 million and $21.4 million, respectively.
Sale-Leaseback Financing Arrangements	Sale-Leaseback Financing Arrangements The Partnership is party to two arrangements in which it sold assets to an affiliate and immediately leased those assets back from the affiliates. Because the Partnership has continued involvement in the assets sold, the proceeds received on the sale of the assets were recorded as long-term financing arrangements (liabilities) in our consolidated balance sheets. Under both of these arrangements, the Partnership pays a fixed minimum payment, as well as contingent payments for volumes in excess of the contractual minimum payments. Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in expected amounts and timing of future payments based on the mine plans. Payments are first applied against accrued interest and any excess is applied against the outstanding principal. The Partnership accounts for such changes by adjusting in the current period, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied). If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant.
Asset Retirement Obligations	Asset Retirement Obligations The Partnership’s asset retirement obligations (“ARO”) consist primarily of spending estimates related to reclaiming surface land, refuse areas, slurry ponds and support facilities at the Partnership’s underground mines in accordance with federal and state reclamation laws as required by each mining permit. These obligations are typically incurred at the time development of a mine commences for underground mines or when construction begins for support facilities, refuse areas and slurry ponds. The Partnership estimates its ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and a market risk premium and then discounted at a credit-adjusted, risk-free rate. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value and the capitalized cost is amortized over the useful life of the related asset on a units-of-production basis. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate.
Derivative Financial Instruments	Derivative Financial Instruments The Partnership from time to time utilizes derivative financial instruments principally to manage exposures to non-domestic coal prices. The Partnership records the fair value of each instrument as either an asset or liability in the consolidated balance sheets and the change in fair value of each instrument is recorded in the consolidated statements of operations. Coal contracts provide for the physical purchase or sale of coal in quantities expected to be used or sold by the Partnership over a reasonable period in the normal course of business, and are not recognized in the consolidated balance sheets.
Warrant Liability	Warrant Liability Our warrant liability is required to be accounted for at fair value and the fair value must be revalued at each balance sheet date until the earlier of the exercise of the warrants, their expiration, or until any of the features requiring liability treatment expires or is modified. The resulting non-cash gain or loss on the fair value revaluation at each balance sheet date is recorded as non-operating expense (income) in our consolidated statements of operations.
Fair Value	Fair Value 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 a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs. A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy, as defined below, gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. Level 1 is defined as observable inputs, such as quoted prices in active markets for identical assets. Level 2 is defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities 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 is defined as unobservable inputs in which little or no market data exists, therefore, requiring an entity to develop its own assumptions. The carrying value of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments.
Variable Interest Entities (VIEs)	Variable Interest Entities (VIEs) VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. VIEs must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIEs economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes. To determine a VIE's primary beneficiary, the Partnership performs a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether the Partnership is the primary beneficiary of a VIE, the Partnership performs a qualitative analysis that considers the design of the VIE, the nature of the Partnership’s involvement and the variable interests held by other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary. The income attributable to consolidated variable interest entities is recorded as net income attributable to noncontrolling interests in the consolidated statements of operations.
Income Taxes	Income Taxes We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. While Section 7704(a) of the tax code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the mining, transportation and marketing of minerals and natural resources, such as coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We currently meet the Qualifying Income Exception and expect to continue to qualify prospectively for this exception. As such, each of our unitholders will take into account their respective share of our items of income, gain, loss and deduction in computing their federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis. 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 and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment basis depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting methods, which are partially dependent upon the unitholder’s tax position, differs from the accounting methods followed in our consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership is not available to us. Our tax counsel provided an opinion at the time of the IPO that FELP will be treated as a partnership. However, as is customary, no ruling has been or will be requested from the Internal Revenue Service (“IRS”) regarding our classification as a partnership for federal income tax purposes. FELLC, its subsidiaries and controlled entities were established as limited liability companies, and thus for federal and, if applicable, state and local income tax purposes, are treated as pass-through entities. Therefore, no provision for income taxes was included in the consolidated financial statements.
Supplemental Cash Flow Information	Supplemental Cash Flow Information The following is supplemental information to the consolidated statements of cash flows: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Supplemental disclosure of cash flow information: Cash interest paid, net of amount capitalized $ 80,542 $ 111,155 $ 108,517 Supplemental disclosure of noncash investing and financing activities: Interest converted into debt $ 49,203 $ — $ — Fair value of warrants issued $ 34,045 $ — $ — Noncash capital contribution from Foresight Reserves LP (affiliate) $ 1,046 $ 11,319 $ — Noncash member distribution to Foresight Reserves $ — $ — $ 12,187 Modifications to capital lease obligations $ 663 $ — $ — Short-term insurance financing $ 4,252 $ 2,806 $ —
Newly Adopted Accounting Standards	Newly Adopted Accounting Standards In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Payments and annual periods beginning after December 15, 2017. We early adopted this standard during the current year and as a result presented all cash costs for debt prepayment and debt extinguishment as cash outflows from financing activities. The prior periods presented had no such cash costs which required reclassification as a result of adoption of this standard. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern
New Accounting Standards Issued and Not Yet Adopted	New Accounting Standards Issued and Not Yet Adopted In January 2017, the FASB issued ASU 2017-01, which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This standard is effective for fiscal years beginning after December 15, 2017. We do not expect this new guidance to have a material impact on our consolidated financial statements. In November 2016, the FASB issued ASU 2016-18 which clarifies the presentation requirement of restricted cash within the statement of cash flows. Under ASU 2016-18, the changes in restricted cash and restricted cash equivalents during the period should be included in the beginning and ending cash and cash equivalents balance reconciliation on the statement of cash flows. When cash, cash equivalents, restricted cash or restricted cash equivalents are presented in more than one line item within the statement of financial position, an entity shall calculate a total cash amount in a narrative or tabular format that agrees to the amount shown on the statement of cash flows. Details on the nature and amounts of restricted cash should also be disclosed. This standard is effective for fiscal years beginning after December 15, 2017. We expect this new guidance to require adjustments to the presentation of our consolidated financial statements. As of December 31, 2016, we had restricted cash of $13.3 million, of which $10.7 million is included in current assets and $2.6 million is included in other long-term assets. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation, In May 2014, the FASB issued ASU 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In July 2015, the FASB delayed the effective date until annual and interim periods beginning after December 31, 2017. In February 2016, the FASB updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements. In July 2015, the FASB issued ASU 2015-11, Inventory: Simplifying the Measurement of Inventory

Summary of Significant Accoun34

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Estimated Useful Lives of Property Plant and Equipment	The estimated useful lives of machinery and equipment, buildings and structures and other categories are as follows: Machinery and equipment 3–20 years Buildings and structures 3–40 years Other 3–20 years
Supplemental Cash Flow Information	The following is supplemental information to the consolidated statements of cash flows: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Supplemental disclosure of cash flow information: Cash interest paid, net of amount capitalized $ 80,542 $ 111,155 $ 108,517 Supplemental disclosure of noncash investing and financing activities: Interest converted into debt $ 49,203 $ — $ — Fair value of warrants issued $ 34,045 $ — $ — Noncash capital contribution from Foresight Reserves LP (affiliate) $ 1,046 $ 11,319 $ — Noncash member distribution to Foresight Reserves $ — $ — $ 12,187 Modifications to capital lease obligations $ 663 $ — $ — Short-term insurance financing $ 4,252 $ 2,806 $ —

Transition and Reorganization35

Transition and Reorganization Costs (Tables)	12 Months Ended
	Dec. 31, 2016
Restructuring Charges [Abstract]
Schedule of Transition and Reorganization Costs	Transition and reorganization costs were comprised of the following for the years ended December 31, 2016, 2015 and 2014: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Retention compensation paid by Foresight Reserves and pushed down to FELP $ 2,333 $ 10,032 $ — Equity-based compensation 4,315 4,322 — Cash retention and termination benefits — 5,878 — Legal and other charges 241 1,201 — Transition and reorganization costs $ 6,889 $ 21,433 $ —

Commodity Derivative Contracts

Commodity Derivative Contracts (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of (Loss )/Gain on Commodity Derivative Contracts	The settlements of commodity derivative contracts and (loss) gain on commodity derivative contracts for the years ended December 31, 2016, 2015 and 2014 are as follows: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Settlements of commodity derivative contracts $ 12,644 $ 61,223 $ 19,204 (Loss) gain on commodity derivative contracts $ (23,752 ) $ 45,691 $ 76,330

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2016
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consists of the following: December 31, 2016 December 31, 2015 (In Thousands) Trade accounts receivable $ 42,862 $ 56,013 Other receivables 12,043 5,312 Total accounts receivable $ 54,905 $ 61,325

Inventories, Net (Tables)

Inventories, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories, net consist of the following: December 31, 2016 December 31, 2015 (In Thousands) Parts and supplies $ 18,712 $ 24,276 Raw coal 4,907 1,906 Clean coal 19,433 24,470 Total inventories, net $ 43,052 $ 50,652

Property, Plant, Equipment an39

Property, Plant, Equipment and Development, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Schedule of Property, Plant, Equipment and Development, Net	Property, plant, equipment and development, net consist of the following: December 31, 2016 December 31, 2015 (In Thousands) Land, land rights and mineral rights $ 99,909 $ 99,676 Machinery and equipment 1,186,450 1,140,256 Machinery and equipment under capital leases 102,662 126,401 Buildings and structures 246,132 248,946 Development costs 774,297 750,177 Other 9,156 9,369 Property, plant, equipment and development 2,418,606 2,374,825 Less: accumulated depreciation, depletion and amortization (1,099,669 ) (941,632 ) Property, plant, equipment and development, net $ 1,318,937 $ 1,433,193

Accrued Expenses and Other Cu40

Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Payables And Accruals [Abstract]
Schedule of Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities consist of the following: December 31, 2016 December 31, 2015 (In Thousands) Employee compensation, benefits and payroll taxes $ 13,065 $ 12,393 Taxes other than income 6,819 6,560 Liquidated damages 5,828 6,404 Litigation reserve 4,800 2,347 Royalties (non-affiliate) 4,117 3,707 Other 8,963 4,396 Total accrued expenses and other current liabilities $ 43,592 $ 35,807

Long-Term Debt and Capital Le41

Long-Term Debt and Capital Lease Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long-Term Debt and Capital Lease Obligations	Long-term debt and capital lease obligations consist of the following: December 31, 2016 December 31, 2015 (In Thousands) 2021 Second Lien Notes $ 349,100 $ — 2017 Exchangeable PIK Notes 299,859 — 2021 Senior Notes — 600,000 Revolving Credit Facility 352,500 352,500 Term Loan 295,667 297,750 Trade A/R Securitization Program 14,200 41,000 5.78% longwall financing arrangement 39,217 50,423 5.555% longwall financing arrangement 41,250 51,563 Capital lease obligations 41,457 62,710 Subtotal - Total principal outstanding on long-term debt and capital lease obligations 1,433,250 1,455,946 Unamortized deferred financing costs and debt discounts (42,187 ) (21,380 ) Total long-term debt and capital lease obligations 1,391,063 1,434,566 Less: current portion (368,993 ) (1,434,566 ) Non-current portion of long-term debt and capital lease obligations $ 1,022,070 $ —
Schedule of Contractual Maturities of Long Term Debt Principal and Capital Lease Obligations	The following summarizes the contractual principal maturities of long-term debt and capital lease obligations as of December 31, 2016: Long-Term Debt Capital Lease Obligations (In Thousands) 2017 $ 360,392 $ 15,986 2018 386,644 11,471 2019 24,806 14,000 2020 — — 2021 619,951 — Thereafter — — Total $ 1,391,793 $ 41,457
Schedule of Minimum Lease Payments of Capital Lease Obligation	The aggregate amounts of remaining minimum lease payments on the Partnership’s capital lease obligations are $ 45.0 2017 2018 2019 2020 2021 Minimum lease payments $ 17,915 $ 12,635 $ 14,471 $ — $ —

Sale-Leaseback Financing Arra42

Sale-Leaseback Financing Arrangements - Affiliate (Tables)	12 Months Ended
	Dec. 31, 2016
Leases Capital [Abstract]
Schedule of Maturities Expected Principal Payments	The following summarizes the maturities of expected principal payments, based on current mine plans, on the Partnership’s sale-leaseback financing arrangements, and accrued interest at December 31, 2016: Sale-Leaseback Financing Arrangements Accrued Interest (In Thousands) 2017 $ 1,372 $ 2,930 2018 1,415 — 2019 2,454 — 2020 4,203 — 2021 4,239 — Thereafter 178,186 — Total $ 191,869 $ 2,930
Schedule of Minimum Lease Payments	Minimum payments from 2017 through 2021 are as follows: 2017 2018 2019 2020 2021 Minimum lease payments $ 21,000 $ 21,000 $ 21,000 $ 21,000 $ 21,000

Contractual Arrangements and 43

Contractual Arrangements and Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Contractual Royalty and Throughput Arrangements
Operating Leased Assets [Line Items]
Summary of Future Lease Minimum Payments	The following table presents future minimum payments, by year, required under contractual royalty and throughput arrangements with related entities and third parties as of December 31, 2016: Royalties – Third Party Royalties – Related Party Transportation Minimums – Third Party (In Thousands) 2017 $ 2,004 $ 57,667 $ 49,580 2018 2,004 57,667 50,880 2019 2,004 57,667 52,230 2020 2,004 43,667 53,630 2021 2,004 38,834 51,050 Thereafter 7,181 232,500 54,900 Total $ 17,201 $ 488,002 $ 312,270
Noncancelable Operating Leases
Operating Leased Assets [Line Items]
Summary of Future Lease Minimum Payments	The following presents future minimum lease payments, by year, required under noncancelable operating leases with initial terms greater than one year, as of December 31, 2016: Operating Leases – Third Party Operating Leases – Related Party (In Thousands) 2017 $ 3,190 $ 155 2018 2,214 155 2019 539 150 2020 — 150 2021 — 100 Thereafter — — Total $ 5,943 $ 710

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Changes in Carrying Amount of Asset Retirement Obligations	The change in the carrying amount of asset retirement obligations was as follows: For the Year Ended December 31, 2016 2015 2014 (In Thousands) Balance at beginning of period (including current portion) $ 43,295 $ 35,580 $ 21,225 Accretion expense 3,376 2,267 1,621 Adjustments for liabilities incurred or changes in estimates (1,283 ) 6,579 13,747 Expenditures for reclamation activities (471 ) (1,131 ) (1,013 ) Balance at end of period (including current portion) 44,917 43,295 35,580 Less: current portion of asset retirement obligations (7,273 ) (18 ) (4,207 ) Noncurrent portion of asset retirement obligations $ 37,644 $ 43,277 $ 31,373

Related-Party Transactions (Tab

Related-Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Summary of Affiliate Amounts Included in Consolidated Balance Sheets	The following table presents the affiliate amounts included in our consolidated balance sheets: As of December 31, Affiliated Company Balance Sheet Location 2016 2015 (In Thousands) Foresight Reserves and affiliated entities (1) Due from affiliates - current $ — $ 145 Murray Energy and affiliated entities (2) Due from affiliates - current 16,784 16,316 NRP and affiliated entities Due from affiliates - current 107 154 Total $ 16,891 $ 16,615 Murray Energy and affiliated entities Financing receivables - affiliate - current $ 2,904 $ 2,689 Total $ 2,904 $ 2,689 Murray Energy and affiliated entities Due from affiliates - noncurrent $ 1,843 $ 2,691 Total $ 1,843 $ 2,691 Murray Energy and affiliated entities Financing receivables - affiliate - noncurrent $ 67,235 $ 70,139 Total $ 67,235 $ 70,139 Foresight Reserves and affiliated entities (3) Prepaid royalties - current and noncurrent $ 7,599 $ 69,555 NRP and affiliated entities (3) Prepaid royalties - current and noncurrent 1,246 — Total $ 8,845 $ 69,555 Foresight Reserves and affiliated entities (1) Due to affiliates - current $ 1,373 $ 1,054 Murray Energy and affiliated entities Due to affiliates - current 17,021 5,020 NRP and affiliated entities Due to affiliates - current 2,510 2,462 Total $ 20,904 $ 8,536 (1) – Includes amounts due to/from a joint venture partially owned by an affiliate of The Cline Group – see Note 16. (2) – Includes amounts due from Javelin, a joint venture partially owned by Murray Energy. (3) – Prepaid royalties with Foresight Reserves and affiliated entities is presented net of a $74,575 reserve as of December 31, 2016. Prepaid royalties with NRP and affiliated entities is presented net of a $33,965 and $46,306 reserve as of December 31, 2016 and 2015, respectively.
Summary of Expenses (Income) Incurred With Affiliated Entities	A summary of expenses/income incurred with affiliated entities is as follows for the years ended December 31, 2016, 2015 and 2014: Year Ended December 31, 2016 2015 2014 (In Thousands) Coal sales – Murray Energy and affiliated entities (1) $ 58,395 $ 23,060 $ — Overriding royalty and lease revenues – Murray Energy and affiliated entities (2) $ 7,978 $ 5,387 $ — Terminal revenues - Murray Energy and affiliated entities (2) $ 1,226 $ 282 $ — Royalty expense – (3) $ 17,606 $ 29,773 $ 48,652 Royalty expense – Foresight Reserves and affiliated entities (3) $ 13,921 $ 3,319 $ 11,282 Loadout services – NRP and affiliated entities (3) $ 8,510 $ 9,032 $ 9,878 Purchased goods and services – Murray Energy and affiliated entities (4) $ 8,305 $ 3,326 $ — Purchased coal - Murray Energy and affiliated entities (5) $ 13,541 $ 17,399 $ — Land leases - Foresight Reserves and affiliated entities (3), (6) $ 177 $ — $ 100 Terminal fees – Foresight Reserves and affiliated entities (6) $ — $ 19,327 $ 43,951 Sales commissions - Murray Energy and affiliated entities (7) $ 216 $ — $ — Management services – Murray Energy and affiliated entities (7) $ 8,919 $ 4,667 $ — Administrative fee income – Foresight Reserves and affiliated entities (8) $ — $ 52 $ 256 Principal location in the consolidated financial statements: (1) – Coal sales (2) – Other revenues (3) – Cost of coal produced (excluding depreciation, depletion and amortization) (4) – Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment, as applicable (5) – Cost of coal purchased (6) – Transportation (7) – Selling, general and administrative (8) – Other operating income, net

Variable Interest Entities (V46

Variable Interest Entities (VIEs) (Tables)	12 Months Ended
	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Summary of Consolidated VIE Assets and Liabilities	The liabilities recognized as a result of consolidating the VIEs do not necessarily represent additional claims on the general assets of the Partnership outside of the VIEs; rather, they represent claims against the specific assets of the consolidated VIEs. Conversely, assets recognized as a result of consolidating these VIEs do not necessarily represent additional assets that could be used to satisfy claims against the Partnership’s general assets. Long-term assets in the table below is comprised of restricted cash which provided collateral to an outstanding letter of credit. There are no other restrictions on the VIE assets that are reported in our general assets. The total consolidated VIE assets and liabilities reflected in the Partnership’s consolidated balance sheets are as follows: December 31, 2016 December 31, 2015 (In Thousands) Assets: Current assets $ — $ 4,933 Long-term assets 2,500 — Total assets $ 2,500 $ 4,933 Liabilities: Current liabilities $ — $ 12,835 Long-term liabilities — 2,955 Total liabilities $ — $ 15,790

Fair Value of Financial Instr47

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value of Net Financial Assets and Liabilities Measured on Recurring Basis	The tables below set forth, by level, the Partnership’s net financial assets and liabilities for which fair value is measured on a recurring basis: Fair Value at December 31, 2016 Total Level 1 Level 2 Level 3 (In Thousands) Coal derivative contracts $ 7,315 $ — $ 7,315 $ — Warrant liability (51,169 ) — — (51,169 ) Total $ (43,854 ) $ — $ 7,315 $ (51,169 ) Fair Value at December 31, 2015 Total Level 1 Level 2 Level 3 (In Thousands) Coal derivative contracts $ 48,623 $ — $ 48,623 $ — Diesel derivative contracts (1,029 ) — (1,029 ) — Total $ 47,594 $ — $ 47,594 $ —
Fair Value of Gross Financial Assets and Liabilities Measured on a Recurring Basis	The classification and amount of the Partnership’s financial instruments measured at fair value on a recurring basis, which are presented on a gross basis in the consolidated balance sheets as of December 31, 2016 and 2015, are as follows: Fair Value at December 31, 2016 Current – Long-Term – Coal Derivative Assets Accrued Expenses Warrant Liability (In Thousands) Coal derivative contracts $ 7,650 $ — $ (335 ) $ — Warrant liability — — — (51,169 ) Total $ 7,650 $ — $ (335 ) $ (51,169 ) Fair Value at December 31, 2015 Current – Long-Term – Coal Derivative Assets Accrued Expenses Warrant Liability (In Thousands) Coal derivative contracts $ 26,596 $ 22,027 $ — $ — Diesel derivative contracts — — (1,029 ) — Total $ 26,596 $ 22,027 $ (1,029 ) $ —
Fair Value Liabilities Measured on Recurring Basis with Unobservable Input Reconciliation	The following is a reconciliation of the beginning and ending balances for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3): Warrant Liability (In Thousands) Balance at January 1, 2016 $ — Purchases, issuances and settlements 34,045 Recorded fair value losses: Included in earnings - loss / (gain) 17,124 Balance at December 31, 2016 $ 51,169

Partners' Capital (Tables)

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Schedule of Percentage Allocations of Available Cash from Operating Surplus	The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our IDRs based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the IDR holders and the unitholders of any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Common Unit”. The percentage interests shown for our unitholders and the IDR holders for the MQD are also applicable to quarterly distribution amounts that are less than the MQD. The percentage interests set forth below excludes the impact of arrearages which would first be due to common unitholders before the IDR holders would receive a distribution. Total Quarterly Distribution Marginal Percentage Unitholders IDR Holders Minimum quarterly distribution $0.3375 100.0 % — First target distribution Above $0.3375 up to $0.3881 100.0 % — Second target distribution Above $0.3881 up to $0.4219 85.0 % 15.0 % Third target distribution Above $0.4219 up to $0.5063 75.0 % 25.0 % Thereafter Above $0.5063 50.0 % 50.0 %
Schedule of Quarterly Distribution Paid Per Limited Partner Unit	The follow table summarizes the quarterly distribution paid per limited partner unit (except as noted) during the years ended December 31, 2016, 2015 and 2014: Year Ended December 31, 2016 2015 2014 (Per limited partner unit, except as noted) First Quarter $ — $ 0.36 n/a Second Quarter $ — $ 0.37 n/a Third Quarter $ — $ 0.38 $ 0.03 Fourth Quarter (a) $ — $ 0.06 $ 0.35 (a) – In November 2015, we paid a quarterly distribution of $0.17 per unit payable to common unitholders, while suspending the distribution on all subordinated units. Chris Cline and one additional common unitholder elected to forego the $0.17 per common unit distribution on their collective 21.2 million common units.

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Summary of Partnership Equity-based Compensation Recorded in Consolidated Statements of Operations	During the years ended December 31, 2016, 2015 and 2014, the Partnership’s equity-based compensation is recorded in the consolidated statements of operations as follows: December 31, Location in statements of operations: 2016 2015 2014 Selling, general and administrative 2 % 58 % 63 % Transition and reorganization costs 84 % 31 % — Cost of coal produced (excluding depreciation, depreciation and amortization) 14 % 11 % 37 %
Phantom Share Units (PSUs)
Summary of Non-vested LTIP Award Activity	A summary of LTIP award activity for the years ended December 31, 2015 and 2016 is as follows: Number of Units Weighted Average Grant Date Fair Value per Unit Non-vested grants at January 1, 2015 601,109 $ 19.99 Granted 1,873,423 $ 7.28 Vested (652,786 ) $ 17.25 Forfeited (110,405 ) $ 18.63 Non-vested grants at December 31, 2015 1,711,341 $ 7.21 Granted 58,851 $ 3.82 Vested (1,421,662 ) $ 4.76 Forfeited (69,991 ) $ 19.60 Non-vested grants at December 31, 2016 278,539 $ 15.88

Earnings per Limited Partner 50

Earnings per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Summary of Partnership's Calculation of Net (Loss) Income per Common and Subordinated Unit	The following table illustrates the Partnership’s calculation of net (loss) income per common and subordinated unit for the period indicated: Year Ended December 31, 2016 2015 2014 Common Units Subordinated Units Total Common Units Subordinated Units Total Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Distributed earnings $ — $ — $ — $ 79,733 $ 72,100 $ 151,833 $ 24,619 $ 24,601 $ 49,220 Distributions in excess of earnings and undistributed (loss) earnings (90,015 ) (88,774 ) (178,789 ) (95,776 ) (95,534 ) (191,310 ) 10,535 10,437 20,972 Net (loss) income available to limited partner units $ (90,015 ) $ (88,774 ) $ (178,789 ) $ (16,043 ) $ (23,434 ) $ (39,477 ) $ 35,154 $ 35,038 $ 70,192 Denominator: Weighted-average units to calculate basic EPU 65,829 64,955 130,784 65,098 64,934 130,032 64,790 64,739 129,529 Less: effect of dilutive securities (1) — — — — — — — — — Weighted-average units to calculate diluted EPU 65,829 64,955 130,784 65,098 64,934 130,032 64,790 64,739 129,529 Basic net (loss) income per unit $ (1.37 ) $ (1.37 ) $ (1.37 ) $ (0.25 ) $ (0.36 ) $ (0.30 ) $ 0.54 $ 0.54 $ 0.54 Diluted net (loss) income per unit $ (1.37 ) $ (1.37 ) $ (1.37 ) $ (0.25 ) $ (0.36 ) $ (0.30 ) $ 0.54 $ 0.54 $ 0.54 (1) Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the years ended December 31, 2016, 2015 and 2014, approximately 0.3 million, 1.7 million and 0.6 million, respectively, phantom units were anti-dilutive, and therefore were excluded from the diluted EPU calculation. Diluted EPU also is not impacted during the periods presented by any units which could be issued as a result of the Warrants or the Exchangeable PIK Notes. See Notes 10 and 17.

Risk Concentrations (Tables)

Risk Concentrations (Tables)	12 Months Ended
	Dec. 31, 2016
Risks And Uncertainties [Abstract]
Schedules of Risk Concentrations	For the years ended December 31, 2016, 2015 and 2014, the following customers (aggregated at the parent company level) exceeded 10% of total coal sales: For the Year Ended December 31, 2016 2015 2014 (Percentage of Total Coal Sales) Customer A 30% 22% 16% Customer B 10% 12% 12% Customer C 13% 11% (A) Customer D (A) (A) 11% (A) – Less than 10% of total coal sales for this period.

Selected Quarterly Financial 52

Selected Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summary of the Unaudited Quarterly Results	A summary of the unaudited quarterly results for the years ended December 31, 2016 and 2015 is presented below: For the Year Ended December 31, 2016 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (In Thousands, Except per Unit Data) Revenues $ 166,085 $ 226,000 $ 230,825 $ 252,922 Operating income (loss) $ 1,205 $ 12,585 $ 31,414 $ (22,475 ) Net loss $ (41,607 ) $ (27,670 ) $ (24,331 ) $ (85,012 ) Net loss attributable to limited partner units $ (41,704 ) $ (27,786 ) $ (24,287 ) $ (85,012 ) Basic and diluted loss per limited partner unit $ (0.32 ) $ (0.21 ) $ (0.19 ) $ (0.65 ) For the Year Ended December 31, 2015 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (In Thousands, Except per Unit Data) Revenues $ 238,915 $ 251,222 $ 253,066 $ 241,650 Operating income (loss) $ 70,058 $ 4,079 $ 38,079 $ (29,659 ) Net income (loss) $ 42,717 $ (25,280 ) $ 8,188 $ (64,309 ) Net income (loss) attributable to limited partner units $ 42,283 $ (25,403 ) $ 8,070 $ (64,427 ) Basic and diluted income (loss) per limited partner unit $ 0.33 $ (0.20 ) $ 0.06 $ (0.49 )

Organization and Basis of Pre53

Organization and Basis of Presentation - Additional Information (Details)	Jun. 23, 2014	Dec. 31, 2016segmentMiningComplex	Apr. 16, 2015
Schedule Of Organization And Basis Of Presentation [Line Items]
Number of Reportable Segments | segment		1
Number of underground mining complexes | MiningComplex		4
Murray Energy Transaction
Schedule Of Organization And Basis Of Presentation [Line Items]
Percentage of outstanding limited partner units issued			50.00%
Foresight Energy GP Limited Liability Company | Murray Energy Transaction
Schedule Of Organization And Basis Of Presentation [Line Items]
Percentage of voting interests acquired			34.00%
Foresight Energy LLC | Foresight Reserves, LP
Schedule Of Organization And Basis Of Presentation [Line Items]
Ownership percentage prior	99.333%
Foresight Energy LLC | Member of Management
Schedule Of Organization And Basis Of Presentation [Line Items]
Ownership percentage prior	0.667%

Summary of Significant Accoun54

Summary of Significant Accounting Policies - Additional Information (Details)	1 Months Ended	12 Months Ended
	Apr. 30, 2015USD ($)Facility$ / T	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Summary Of Significant Accounting Policies [Line Items]
Allowance recorded for uncollectible accounts receivable		$ 0	$ 0
Prepaid royalties, description		Prepaid royalties consist of recoupable minimum royalty payments due under various lease agreements entered into by the Partnership. Prepaid royalties expected to be recouped within one year are classified as current assets in the Partnership’s consolidated balance sheets.
Interest costs capitalized into property, plant, equipment and development, net		$ 500,000	1,900,000	$ 5,200,000
Impairment losses recorded		0	0	0
Amortization expense included in interest expense		7,500,000	6,000,000	6,100,000
Unamortized debt issuance cost		19,300,000	21,400,000
Provision for income taxes		$ 0	0	$ 0
New adopted accounting standards, description		In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings of a transferred business before the date of a dropdown transaction should not be allocated to the limited partnership and therefore earnings per unit of the limited partners would not change as a result of the dropdown transaction. We adopted ASU 2015-06 during 2016 and it did not have an effect on our consolidated financial statements or related disclosures. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We adopted ASU 2015-03 on a retrospective basis during 2016. The adoption of ASU 2015-03 did not affect our results of operations or cash flows, but it required us to reclassify the deferred financing costs associated with certain of our long-term debt. We reclassified approximately $15.9 million of our deferred financing costs as of December 31, 2015 to long-term debt and capital lease obligations in our consolidated balance sheet to adhere to ASU 2015-03. The deferred financing costs associated with our revolving credit facility and trade A/R securitization program continue to be presented as an asset on the consolidated balance sheets. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Payments, which provides guidance on eight specific cash flow issues with the objective of reducing diversity in practice. The guidance is effective for interim and annual periods beginning after December 15, 2017. We early adopted this standard during the current year and as a result presented all cash costs for debt prepayment and debt extinguishment as cash outflows from financing activities. The prior periods presented had no such cash costs which required reclassification as a result of adoption of this standard. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which requires management of the entity to evaluate whether there is substantial doubt about the entity’s ability to continue as a going concern. This ASU was effective for the annual reporting period ending after December 15, 2016. We adopted this standard and it did not have an impact on our consolidated financial statements or disclosures given the completion of the debt restructuring in August 2016 and the Partnership's financial condition and expected operating outlook at the time of adoption.
Restricted cash		$ 13,300,000
Restricted cash included in current asset		10,700,000
Restricted cash included in long-term other assets		$ 2,600,000
ASU 2015-03
Summary Of Significant Accounting Policies [Line Items]
Reclassification of deferred financing costs to long term debt and capital lease obligation			$ 15,900,000
American Energy Corporation | Transport and Overriding Royalty Agreements
Summary Of Significant Accounting Policies [Line Items]
Proceeds from sale of equipment	$ 63,000,000
Number of coal preparation plants and related cost handling facilities | Facility	2
American Energy and Consolidated Land Company | Transport and Overriding Royalty Agreements
Summary Of Significant Accounting Policies [Line Items]
Cash paid for overriding royalty rights	$ 12,000,000
Maximum
Summary Of Significant Accounting Policies [Line Items]
Prepaid royalties, contractual recoupment period		10 years
Maximum | American Energy Corporation | Transport and Overriding Royalty Agreements
Summary Of Significant Accounting Policies [Line Items]
Fees per ton of coal mined processed and/or transported using leased assets | $ / T	1.75
Maximum | American Energy and Consolidated Land Company | Transport and Overriding Royalty Agreements
Summary Of Significant Accounting Policies [Line Items]
Overriding royalty interest granted per unit | $ / T	0.50
Maximum | Cash and Cash Equivalents
Summary Of Significant Accounting Policies [Line Items]
Cash deposits with original maturities		3 months
Minimum
Summary Of Significant Accounting Policies [Line Items]
Prepaid royalties, contractual recoupment period		5 years
Minimum | American Energy Corporation | Transport and Overriding Royalty Agreements
Summary Of Significant Accounting Policies [Line Items]
Fees per ton of coal mined processed and/or transported using leased assets | $ / T	1.15
Quarterly minimum Fees for coal mined processed and/or transported using leased assets	$ 1,700,000
Minimum | American Energy and Consolidated Land Company | Transport and Overriding Royalty Agreements
Summary Of Significant Accounting Policies [Line Items]
Overriding royalty interest granted per unit | $ / T	0.30
Cash paid for overriding royalty rights	$ 500,000

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Estimated Useful Lives of Property Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2016
Machinery and Equipment | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment, estimated useful lives	3 years
Machinery and Equipment | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment, estimated useful lives	20 years
Building and Structures | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment, estimated useful lives	3 years
Building and Structures | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment, estimated useful lives	40 years
Other | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment, estimated useful lives	3 years
Other | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment, estimated useful lives	20 years

Summary of Significant Accoun56

Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental disclosure of cash flow information:
Cash interest paid, net of amount capitalized	$ 80,542	$ 111,155	$ 108,517
Supplemental disclosure of noncash investing and financing activities:
Interest converted into debt	49,203
Fair value of warrants issued	34,045
Noncash capital contribution from Foresight Reserves LP (affiliate)	1,046	11,319
Noncash member distribution to Foresight Reserves			$ 12,187
Modifications to capital lease obligations	663
Short-term insurance financing	$ 4,252	$ 2,806

Restructuring Transactions - Ad

Restructuring Transactions - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Aug. 15, 2016	Feb. 15, 2016
Restructuring Cost And Reserve [Line Items]
Debt restructuring costs	$ 6,100	$ 5,900	$ 9,700	$ 21,821	$ 3,930
2021 Senior Notes
Restructuring Cost And Reserve [Line Items]
Debt instrument interest percentage				7.875%
Default of semi-annual interest payments						$ 23,600	$ 23,600

Transition and Reorganization58

Transition and Reorganization Costs - Schedule of Transition and Reorganization Costs (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015
Transition And Reorganization Costs [Line Items]
Transition and reorganization costs	$ 4,100	$ 5,000	$ 12,300	$ 6,889	$ 21,433
Murray Energy Management Services Agreement | Murray Energy Corporation
Transition And Reorganization Costs [Line Items]
Retention compensation paid by Foresight Reserves and pushed down to FELP				2,333	10,032
Equity-based compensation				4,315	4,322
Cash retention and termination benefits					5,878
Legal and other charges				241	1,201
Transition and reorganization costs				$ 6,889	$ 21,433

Commodity Derivative Contract59

Commodity Derivative Contracts - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016Tgal	Dec. 31, 2015USD ($)T	Dec. 31, 2014USD ($)
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Settlement of certain commodity derivative contracts | $		$ 19,073	$ 7,345
Swap Agreements
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	0
Swap Agreements | Coal Derivative Contract
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount, Mass | T	500,000	1,100,000

Commodity Derivative Contract60

Commodity Derivative Contracts - Summary of (Loss)/Gain on Commodity derivative contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Settlements of commodity derivative contracts	$ 12,644	$ 61,223	$ 19,204
(Loss) gain on commodity derivative contracts	$ (23,752)	$ 45,691	$ 76,330

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Trade accounts receivable	$ 42,862	$ 56,013
Other receivables	12,043	5,312
Total accounts receivable	$ 54,905	$ 61,325

Inventories, Net - Schedule of

Inventories, Net - Schedule of Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Inventory [Line Items]
Parts and supplies	$ 18,712	$ 24,276
Total inventories, net	43,052	50,652
Raw coal
Inventory [Line Items]
Coal	4,907	1,906
Clean coal
Inventory [Line Items]
Coal	$ 19,433	$ 24,470

Property, Plant, Equipment an63

Property, Plant, Equipment and Development, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Land, land rights and mineral rights	$ 99,909	$ 99,676
Machinery and equipment	1,186,450	1,140,256
Machinery and equipment under capital leases	102,662	126,401
Buildings and structures	246,132	248,946
Development costs	774,297	750,177
Other	9,156	9,369
Property, plant, equipment and development	2,418,606	2,374,825
Less: accumulated depreciation, depletion and amortization	(1,099,669)	(941,632)
Property, plant, equipment and development, net	$ 1,318,937	$ 1,433,193

Accrued Expenses and Other Cu64

Accrued Expenses and Other Current Liabilities - Schedule of Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Payables And Accruals [Abstract]
Employee compensation, benefits and payroll taxes	$ 13,065	$ 12,393
Taxes other than income	6,819	6,560
Liquidated damages	5,828	6,404
Litigation reserve	4,800	2,347
Royalties (non-affiliate)	4,117	3,707
Other	8,963	4,396
Total accrued expenses and other current liabilities	$ 43,592	$ 35,807

Long-Term Debt and Capital Le65

Long-Term Debt and Capital Lease Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt	$ 1,433,250	$ 1,455,946
Capital lease obligations	41,457	62,710
Unamortized deferred financing costs and debt discounts	(42,187)	(21,380)
Total long-term debt and capital lease obligations	1,391,063	1,434,566
Less: current portion	(368,993)	(1,434,566)
Long-term debt and capital lease obligations	1,022,070
2021 Second Lien Notes
Debt Instrument [Line Items]
Long-term debt	349,100
2021 Senior Notes
Debt Instrument [Line Items]
Long-term debt		600,000
Unamortized deferred financing costs and debt discounts	(11,000)
2017 Exchangeable PIK Notes
Debt Instrument [Line Items]
Long-term debt	299,859
Term Loan
Debt Instrument [Line Items]
Long-term debt	295,667	297,750
Trade A/R Securitization Program
Debt Instrument [Line Items]
Long-term debt	14,200	41,000
5.78% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt	39,217	50,423
5.555% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt	41,250	51,563
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving Credit Facility	$ 352,500	$ 352,500

Long-Term Debt and Capital Le66

Long-Term Debt and Capital Lease Obligations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	May 31, 2010	Jan. 31, 2010
5.78% longwall financing arrangement
Debt Instrument [Line Items]
Debt instrument interest percentage	5.78%	5.78%		5.78%
5.555% longwall financing arrangement
Debt Instrument [Line Items]
Debt instrument interest percentage	5.555%	5.555%	5.555%
2021 Second Lien Notes
Debt Instrument [Line Items]
Debt instrument maturity year	2,021
Debt instrument interest percentage	9.00%
2021 Senior Notes
Debt Instrument [Line Items]
Debt instrument maturity year	2,021	2,021
Debt instrument interest percentage	7.875%
2017 Exchangeable PIK Notes
Debt Instrument [Line Items]
Debt instrument maturity year	2,017
Debt instrument interest percentage	15.00%

Long-Term Debt and Capital Le67

Long-Term Debt and Capital Lease Obligations - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2015
Debt Instrument [Line Items]
Loss on extinguishment of debt	$ 13,200	$ 13,203	$ 4,979
Unamortized debt discount and debt issuance cost		42,187		$ 21,380
Debt modification cost		2,200
Deferred lender and third party professional fees		13,500
2021 Senior Notes
Debt Instrument [Line Items]
Unamortized debt discount and debt issuance cost		$ 11,000
Debt instrument interest percentage		7.875%

Long-Term Debt and Capital Le68

Long-Term Debt and Capital Lease Obligations - Exchange of Old Senior Notes for New Notes and Warrants - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Aug. 30, 2016
Debt Instrument [Line Items]
Long-term debt	$ 1,433,250,000	$ 1,455,946,000
Warrants issued to acquire common units	516,825
Percentage of warrants to purchase of common stock	4.50%
Warrants
Debt Instrument [Line Items]
Fair value of the warrants			$ 34,000,000
2021 Senior Notes
Debt Instrument [Line Items]
Debt Instrument, face amount	$ 599,800,000
Long-term debt		$ 600,000,000
Debt instrument maturity year	2,021	2,021
Remaining aggregate principal amount redeemed			$ 175,000
2021 Second Lien Notes
Debt Instrument [Line Items]
Long-term debt	$ 349,100,000
Debt instrument maturity year	2,021
2017 Exchangeable PIK Notes
Debt Instrument [Line Items]
Long-term debt	$ 299,859,000
Debt instrument maturity year	2,017
Second Lien Notes
Debt Instrument [Line Items]
Debt instrument discount	$ 25,000,000
Exchangeable PIK Notes
Debt Instrument [Line Items]
Debt instrument discount	$ 9,000,000

Long-Term Debt and Capital Le69

Long-Term Debt and Capital Lease Obligations - Terms of the New Notes - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016	Aug. 16, 2018
2021 Second Lien Notes
Debt Instrument [Line Items]
Debt instrument maturity date	Aug. 15, 2021
Debt instrument interest percentage	9.00%
Debt instrument payable in kind interest percentage	1.00%
Debt instrument interest payable description	Interest is payable semi-annually on February 15th and August 15th, commencing on February 15, 2017.
Debt instrument frequency of periodic interest payment	semi-annually
Debt instrument date of first interest payment	Feb. 15, 2017
2017 Exchangeable PIK Notes
Debt Instrument [Line Items]
Debt instrument maturity date	Oct. 3, 2017
Debt instrument interest percentage	15.00%
Debt instrument interest payable description	interest payable in kind at a rate of 15.0% per annum, payable on March 1, 2017 and October 3, 2017.
Debt instrument redemption period end date	Oct. 2, 2017
Debt instrument redemption percentage of principal amount thereof plus accrued interest	100.00%
Debt instrument redemption description	We may redeem, repurchase, refinance, defease or otherwise retire (any of the foregoing, a “redemption”) all of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at 100% of the principal amount thereof plus accrued interest (any such redemption, an “Exchangeable PIK Note Retirement”).
Debt instrument conversion, description	Upon a Murray Purchase, the Murray Group will receive FELP units equal to the principal and interest settlement amount multiplied by the lesser of: (a) a number equal to one divided by 92.5% of the last thirty days weighted-average trading price or (b) 1.12007 common units per $1.00 principal amount of Exchangeable PIK Notes. The Partnership and Murray Energy may each purchase less than all of the outstanding Exchangeable PIK Notes, so long as the combination results in redemption of all of the Exchangeable PIK Notes.
Common units exchangeable per dollar principal amount of notes	1.12007
Percentage of weighted-average trading price	92.50%
Percentage of common units out of total outstanding units	75.00%
Scenario, Forecast | 2021 Second Lien Notes
Debt Instrument [Line Items]
Debt instrument interest percentage		10.00%

Long-Term Debt and Capital Le70

Long-Term Debt and Capital Lease Obligations - Senior Secured Credit Facilities - Additional Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Dec. 31, 2016	Dec. 31, 2016	Aug. 29, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt		$ 1,433,250,000	$ 1,433,250,000		$ 1,455,946,000
Term Loan
Debt Instrument [Line Items]
Long-term debt		295,667,000	295,667,000		297,750,000
Revolving Credit Facility
Debt Instrument [Line Items]
Additional borrowing capacity		$ 352,500,000	$ 352,500,000		$ 352,500,000
Amended Credit Agreement
Debt Instrument [Line Items]
Fronting fee		0.125%	0.125%
Amended Credit Agreement | Term Loan
Debt Instrument [Line Items]
Weighted average interest rate		6.50%	6.50%
Amended Credit Agreement | Term Loan | LIBOR
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility			5.50%
Amended Credit Agreement | Term Loan | Base Rate
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility			4.50%
Amended Credit Agreement | Term Loan | Minimum
Debt Instrument [Line Items]
Debt instrument, LIBOR floor rate		1.00%	1.00%
Amended Credit Agreement | Term Loan
Debt Instrument [Line Items]
Long-term debt		$ 297,800,000	$ 297,800,000
Repayments of term loan principal			2,100,000
Prepayment of term loan principal amount payable		26,900,000	$ 26,900,000
Amended Credit Agreement | Revolving Credit Facility
Debt Instrument [Line Items]
Credit agreement maturity month and year			2020-08
Maximum borrowings capacity under credit facility		450,000,000	$ 450,000,000	$ 550,000,000
Credit agreement termination month and year			2018-08
Unrestricted cash		$ 35,000,000	$ 35,000,000
Commitment fee			0.50%
Weighted average interest rate		5.30%	5.30%
Additional borrowing capacity		$ 352,500,000	$ 352,500,000
Outstanding letters of credit		$ 7,000,000	$ 7,000,000
Minimum required interest coverage ratio			200.00%
Maximum required senior secured loans leverage ratio		350.00%
Restricted payments		$ 25,000,000	$ 25,000,000
Amended Credit Agreement | Revolving Credit Facility | Scenario, Forecast
Debt Instrument [Line Items]
Maximum required senior secured loans leverage ratio	275.00%
Amended Credit Agreement | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Debt instrument, LIBOR floor rate		0.00%	0.00%
Amended Credit Agreement | Revolving Credit Facility | Minimum | LIBOR
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility			3.50%
Amended Credit Agreement | Revolving Credit Facility | Minimum | Base Rate
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility			2.50%
Amended Credit Agreement | Revolving Credit Facility | Maximum | LIBOR
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility			4.50%
Amended Credit Agreement | Revolving Credit Facility | Maximum | Base Rate
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility			3.50%

Long-Term Debt and Capital Le71

Long-Term Debt and Capital Lease Obligations - Longwall Financing Arrangements and Capital Lease Obligations - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Nov. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	May 31, 2010	Jan. 31, 2010
Debt Instrument [Line Items]
Capital lease obligations		$ 41,457	$ 62,710
5.78% longwall financing arrangement
Debt Instrument [Line Items]
Debt instrument interest percentage		5.78%	5.78%		5.78%
Debt instrument, maturity month and year		2019-06
Description of debt instrument maturity		On the Closing Date, we entered into an amendment to the 5.78% longwall financing credit agreement under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last three semi-annual amortization payments. The new maturity date of the 5.78% longwall financing arrangement is June 2019.
Long-term debt		$ 39,200
5.555% longwall financing arrangement
Debt Instrument [Line Items]
Debt instrument interest percentage		5.555%	5.555%	5.555%
Debt instrument, maturity month and year		2019-09
Description of debt instrument maturity		On the Closing Date, we entered into an amendment to the 5.555% longwall financing credit agreement under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last four semi-annual amortization payments. The new maturity date of the 5.555% longwall financing arrangement is September 2019.
Long-term debt		$ 41,300
5.4% to 6.3% Capital Lease Obligations
Debt Instrument [Line Items]
Capital lease obligations		$ 5,200
Commencement date		This interim longwall finance agreement was converted into individual leases with maturities of four and five years beginning on September 1, 2012.
Waiver fee equal percentage of debt outstanding amount		1.00%
Increased percentage on interest rate		1.00%
5.4% to 6.3% Capital Lease Obligations | Minimum
Debt Instrument [Line Items]
Capital lease obligations bear interest rate		5.40%
5.4% to 6.3% Capital Lease Obligations | Maximum
Debt Instrument [Line Items]
Capital lease obligations bear interest rate		6.30%
5.762% Capital Lease Obligations
Debt Instrument [Line Items]
Capital lease obligations bear interest rate	5.762%
Capital lease obligations	$ 55,900	$ 36,300
Waiver fee equal percentage of debt outstanding amount	1.00%
Increased percentage on interest rate	1.00%
Termination fees due end of the lease terms	$ 2,800

Long-Term Debt and Capital Le72

Long-Term Debt and Capital Lease Obligations - Trade Accounts Receivable Securitization Program - Additional Information (Details) - USD ($)	Aug. 30, 2016	Jan. 31, 2015	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2014
Debt Instrument [Line Items]
Loss on extinguishment of debt			$ 13,200,000	$ 13,203,000	$ 4,979,000
Trade Accounts Receivable Securitization Program
Debt Instrument [Line Items]
Maximum borrowings capacity under credit facility	$ 50,000,000	$ 70,000,000
Debt Instrument, Term		3 years
Maturity date of borrowings		Jan. 12, 2018
Loss on extinguishment of debt	$ 100,000
Long-term debt				$ 14,200,000

Long-Term Debt and Capital Le73

Long-Term Debt and Capital Lease Obligations - Summary of Contractual Maturities of Long Term Debt Principal and Capital Lease Obligations (Details) $ in Thousands	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
2,017	$ 360,392
2,018	386,644
2,019	24,806
2,020	0
2,021	619,951
Thereafter	0
Total	1,391,793
2,017	15,986
2,018	11,471
2,019	14,000
2,020	0
2,021	0
Thereafter	0
Total	$ 41,457

Long-Term Debt and Capital Le74

Long-Term Debt and Capital Lease Obligations - Maturity Tables - Additional Information (Details) $ in Millions	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
Aggregate amounts of remaining minimum lease payments of capital lease obligation	$ 45

Long-Term Debt and Capital Le75

Long-Term Debt and Capital Lease Obligations - Schedule of Minimum Lease Payments of Capital Lease Obligation (Details) $ in Thousands	Dec. 31, 2016USD ($)
Leases Capital [Abstract]
2,017	$ 17,915
2,018	12,635
2,019	14,471
2,020	0
2,021	$ 0

Sale-Leaseback Financing Arra76

Sale-Leaseback Financing Arrangements - Affiliate - Additional Information (Details) T in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2009USD ($)	Dec. 31, 2016USD ($)T$ / T	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Sale Leaseback Transaction [Line Items]
Sale-lease back transaction, accrued interest expense		$ 29,760,000	$ 24,574,000
Aggregate amounts of remaining minimum lease payments		$ 268,300,000
Macoupin
Sale Leaseback Transaction [Line Items]
Sale-leaseback transaction, description		In January 2009, Macoupin entered into a sales agreement with WPP, LLC (“WPP”) and HOD, LLC (“HOD”) (subsidiaries of Natural Resource Partners LP (“NRP”)) to sell certain mineral reserves and rail facility assets (the “Macoupin Sales Arrangement”). NRP is an affiliate of the Partnership (see Note 15). Macoupin received $143.5 million in cash in exchange for certain mineral reserve and transportation assets
Proceeds from sale-leaseback financing arrangement	$ 143,500,000
Term of noncancelable lease		20 years
Lease renewal terms		5 years
Payments to noncancelable lease | $ / T		5.40
Payment of lease on sales price rate		8.00%
Additional payments noncancelable lease | $ / T		0.60
Sale leaseback transaction, quarterly royalty payments		$ 4,000,000
Sale leaseback transaction, annual minimum royalty payments		$ 10,000
Initial lease terms, in years		20 years
Sale-leaseback financing arrangements		$ 141,900,000	$ 143,500,000
Sale-leaseback transaction, imputed interest rate		13.70%	13.90%
Sale-lease back transaction, interest expense		$ 16,300,000	$ 18,800,000	$ 16,300,000
Sale-lease back transaction, accrued interest expense		$ 0	500,000
Sugar Camp
Sale Leaseback Transaction [Line Items]
Sale-leaseback transaction, description		In March 2012, Sugar Camp entered into a sales agreement with HOD for which it received a total of $50.0 million in cash in exchange for certain rail loadout assets (“Sugar Camp Sales Agreement”).
Proceeds from sale-leaseback financing arrangement		$ 50,000,000
Term of noncancelable lease		20 years
Lease renewal terms		5 years
Payments to noncancelable lease | $ / T		1.10
Sale leaseback transaction, quarterly royalty payments		$ 1,300,000
Sale leaseback transaction, annual minimum royalty payments		$ 10,000
Initial lease terms, in years		20 years
Sale-leaseback financing arrangements		$ 50,000,000	$ 50,000,000
Sale-leaseback transaction, imputed interest rate		13.70%	13.20%
Sale-lease back transaction, interest expense		$ 7,800,000	$ 5,400,000	$ 6,400,000
Sale-lease back transaction, accrued interest expense		$ 2,900,000	$ 1,600,000
lessee to recoup excess royalty payments		2 years
Macoupin Rail Loadout Lease and Rail Loop
Sale Leaseback Transaction [Line Items]
Term of noncancelable lease		99 years
Initial lease terms, in years		30 years
Lease transactions aggregate payments | $ / T		3
Volume of coal loaded | T		3.4
Sale leaseback transaction, annual rental payments		$ 20,000
Royalty and fees paid		$ 4,000,000
Macoupin Rail Loop
Sale Leaseback Transaction [Line Items]
Lease transactions aggregate payments | $ / T		1.50
Macoupin Rail Load-out
Sale Leaseback Transaction [Line Items]
Lease transactions aggregate payments | $ / T		1.50

Sale-Leaseback Financing Arra77

Sale-Leaseback Financing Arrangements - Affiliate - Summary of Maturities Expected Principal Payments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Sale-Leaseback Financing Arrangements
2,017	$ 1,372
2,018	1,415
2,019	2,454
2,020	4,203
2,021	4,239
Thereafter	178,186
Total	191,869
Accrued Interest
Accrued Interest, 2017	2,930
Accrued Interest, Total	$ 2,930

Sale-Leaseback Financing Arra78

Sale-Leaseback Financing Arrangements - Affiliate - Schedule of Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Leases Capital [Abstract]
2,017	$ 21,000
2,018	21,000
2,019	21,000
2,020	21,000
2,021	$ 21,000

Contractual Arrangements and 79

Contractual Arrangements and Operating Leases - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leased Assets [Line Items]
Total rental expenses from operating leases	$ 12.4	$ 14.3	$ 16.1
Contingent rental payments	$ 8.5	$ 9	$ 9.9
Minimum
Operating Leased Assets [Line Items]
Minimum royalties recoupable time period against production royalties	5 years
Maximum
Operating Leased Assets [Line Items]
Minimum royalties recoupable time period against production royalties	10 years

Contractual Arrangements and 80

Contractual Arrangements and Operating Leases - Summary of Future Minimum Payments With Relate to Contractual Royalty and Throughput Arrangements (Details) $ in Thousands	Dec. 31, 2016USD ($)
Royalties | Third Party
Operating Leased Assets [Line Items]
2,017	$ 2,004
2,018	2,004
2,019	2,004
2,020	2,004
2,021	2,004
Thereafter	7,181
Total	17,201
Royalties | Related Party
Operating Leased Assets [Line Items]
2,017	57,667
2,018	57,667
2,019	57,667
2,020	43,667
2,021	38,834
Thereafter	232,500
Total	488,002
Transportation Minimums | Third Party
Operating Leased Assets [Line Items]
2,017	49,580
2,018	50,880
2,019	52,230
2,020	53,630
2,021	51,050
Thereafter	54,900
Total	$ 312,270

Contractual Arrangements and 81

Contractual Arrangements and Operating Leases - Summary of Future Minimum Lease Payments Under Noncancelable Operating Leases (Details) $ in Thousands	Dec. 31, 2016USD ($)
Operating Leases - Third Party
Operating Leased Assets [Line Items]
2,017	$ 3,190
2,018	2,214
2,019	539
Total	5,943
Operating Leases - Related Party
Operating Leased Assets [Line Items]
2,017	155
2,018	155
2,019	150
2,020	150
2,021	100
Total	$ 710

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Carrying Amount of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$ 43,295	$ 35,580	$ 21,225
Accretion expense	3,376	2,267	1,621
Adjustments for liabilities incurred or changes in estimates	(1,283)	6,579	13,747
Expenditures for reclamation activities	(471)	(1,131)	(1,013)
Ending balance	44,917	43,295	35,580
Less: current portion of asset retirement obligations	(7,273)	(18)	(4,207)
Noncurrent portion of asset retirement obligations	$ 37,644	$ 43,277	$ 31,373

Asset Retirement Obligations 83

Asset Retirement Obligations - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation risk free interest rate	8.50%	9.80%	6.60%

Coal Workers Pneumoconiosis a84

Coal Workers Pneumoconiosis and Workers Compensation - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
CWP and workers' compensation (benefit) expense	$ (0.4)	$ 1.4	$ 1.5
Coal Workers’ Pneumoconiosis
Defined Benefit Plan Disclosure [Line Items]
Aggregate CWP liability	2.2	3
Workers Compensation
Defined Benefit Plan Disclosure [Line Items]
CWP and workers' compensation expense	3.9	3	$ 1.4
CWP current liability	$ 4.2	$ 2.2

Related-Party Transactions - Ad

Related-Party Transactions - Additional Information (Details)

May 02, 2015T / yr

Apr. 16, 2015USD ($)

Oct. 31, 2013USD ($)Executive

Sep. 30, 2013USD ($)Executive

Dec. 31, 2016USD ($)TrustRenewalLease$ / T

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Aug. 15, 2016USD ($)

Feb. 15, 2016USD ($)

Aug. 23, 2015USD ($)

Jul. 31, 2015USD ($)

Aug. 23, 2013USD ($)

Related Party Transaction [Line Items]

Long-term debt

$ 1,433,250,000

$ 1,455,946,000

Total remaining minimum payments of transportation lease

41,457,000

Financing receivables - affiliates

2,904,000

2,689,000

Cost of coal purchased

13,541,000

17,444,000

$ 18,232,000

Coal sales

866,628,000

979,179,000

1,109,404,000

Transportation

139,659,000

171,733,000

221,178,000

Accrued interest

29,760,000

24,574,000

Prepaid royalty reserve

34,000,000

46,300,000

Minimum deficiency payment not made

46,000,000

Rental fee

$ 12,400,000

14,300,000

16,100,000

Purchase obligation period beyond obligation

15 days

Purchase of mining supplies from affiliates

$ 6,600,000

14,500,000

18,100,000

2021 Senior Notes

Related Party Transaction [Line Items]

Long-term debt

600,000,000

Debt Instrument, face amount

599,800,000

Default of semi-annual interest payments

$ 23,600,000

$ 23,600,000

2017 Exchangeable PIK Notes

Related Party Transaction [Line Items]

Long-term debt

$ 299,859,000

Percentage of weighted-average trading price

92.50%

Common units exchangeable per dollar principal amount of notes

1.12007

2021 Second Lien Notes

Related Party Transaction [Line Items]

Long-term debt

$ 349,100,000

Reserves Investor Group

Related Party Transaction [Line Items]

Percentage of voting interests

0.66%

Number of trusts established | Trust

4

Percentage of economic interests

0.225%

Default of semi-annual interest payments

$ 9,600,000

Reserves Investor Group | 2021 Senior Notes

Related Party Transaction [Line Items]

Long-term debt

105,400,000

Debt Instrument, face amount

188,400,000

Accrued and unpaid interest

6,800,000

Reserves Investor Group | Prior To 2021 Senior Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

83,000,000

Reserves Investor Group | 2017 Exchangeable PIK Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

179,900,000

Reserves Investor Group | 2021 Second Lien Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

$ 15,200,000

Murray Purchase Right | 2017 Exchangeable PIK Notes

Related Party Transaction [Line Items]

Long term debt principal amount exchangeable PIK notes plus accrued interest

100.00%

Related party transaction, terms and manner of settlement

The Murray Group has the right to purchase all of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at a price equal to 100% of the principal amount of the Exchangeable PIK Notes plus accrued interest. Upon a Murray Purchase, the Murray Group will receive FELP units equal to the principal and interest settlement amount multiplied by the lesser of: (a) a number equal to one divided by 92.5% of the last thirty days weighted-average trading price or (b) 1.12007 common units per $1.00 principal amount of Exchangeable PIK Notes. See Note 10 for additional discussion.

Percentage of weighted-average trading price

92.50%

Common units exchangeable per dollar principal amount of notes

1.12007

Transport and Overriding Royalty Agreements

Related Party Transaction [Line Items]

Other revenues

$ 5,900,000

4,000,000

Total remaining minimum payments of transportation lease

91,800,000

Unearned income from financing leasing services

33,300,000

Outstanding financing receivable

58,500,000

Financing receivables - affiliates

2,700,000

ORRA

Related Party Transaction [Line Items]

Other revenues

2,100,000

1,400,000

Outstanding financing receivable

11,700,000

Financing receivables - affiliates

200,000

Remaining minimum payments under agreement

32,100,000

Unearned income under agreement

$ 20,400,000

New River Royalty, LLC

Related Party Transaction [Line Items]

Operating lease number of leases | Lease

2

Lease expiration date

Oct. 15, 2021

Lease renewal terms

5 years

Rental fee

$ 100,000

Purchase of leased properties

$ 3,000

Description of Lessee Leasing Arrangements

Williamson Transport has the option to purchase any property optioned under the leases if Williamson does not perform its purchase obligation within fifteen days of receiving notice of its purchase obligation.

Murray Energy Transaction

Related Party Transaction [Line Items]

Proceeds from sale of voting interest

$ 1,370,000,000

Percentage of outstanding subordinated units issued

100.00%

Percentage of voting interests issued

46.00%

NRP

Related Party Transaction [Line Items]

General partner ownership interest

31.00%

Limited partners ownership interest

4.00%

Foresight Energy GP Limited Liability Company | Murray Energy Transaction

Related Party Transaction [Line Items]

Percentage of voting interests acquired

34.00%

Option Price Value

$ 15,000,000

Foresight Energy Limited Liability IDRS | Murray Energy Transaction

Related Party Transaction [Line Items]

Percentage of voting interests acquired

77.50%

Manager

Related Party Transaction [Line Items]

Management and administration services, quarterly payment

$ 3,500,000

Management and administration services, annual payment

14,000,000

Increase in annual MSA fee upon execution of option

$ 20,000,000

Manager | Murray Energy Management Services Agreement

Related Party Transaction [Line Items]

Management and administration expenses, net

$ 8,900,000

4,700,000

Murray Energy And Affiliated Entities

Related Party Transaction [Line Items]

Other revenues

1,200,000

300,000

Purchase of equipment, supplies and rebuild services

[1]

8,305,000

3,326,000

Cost of coal purchased

[2]

13,541,000

17,399,000

Coal sales

[3]

58,395,000

23,060,000

Commitment to purchase coal

28,100,000

Commitment to sell coal

37,000,000

Loadout services

4,100,000

11,000,000

Transportation

0

200,000

Subsidiaries [Member]

Related Party Transaction [Line Items]

Purchase of equipment, supplies and rebuild services

$ 900,000

200,000

Cline Resource and Development Company | 2021 Senior Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

$ 16,500,000

Chris Cline | 2021 Senior Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

36,500,000

$ 8,000,000

Original purchase sold to the affiliates

$ 8,000,000

$ 8,000,000

Outstanding principal amount

44,500,000

Interest paid to affiliated parties

1,900,000

600,000

Accrued interest

1,300,000

John F Dickinson | 2021 Senior Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

4,000,000

Original purchase sold to the affiliates

4,000,000

4,000,000

Outstanding principal amount

4,000,000

4,000,000

Interest paid to affiliated parties

300,000

300,000

Accrued interest

100,000

Former Executives | 2021 Senior Notes

Related Party Transaction [Line Items]

Original purchase sold to the affiliates

$ 3,700,000

$ 3,700,000

Number of executives | Executive

2

2

The Cline Trust Company LLC | 2021 Senior Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

10,000,000

Interest paid to affiliated parties

0

Accrued interest

300,000

Michael Beyer | 2021 Senior Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

3,200,000

Drexel Short | 2021 Senior Notes

Related Party Transaction [Line Items]

Debt Instrument, face amount

$ 500,000

Michael Beyer And Drexel Short | 2021 Senior Notes

Related Party Transaction [Line Items]

Interest paid to affiliated parties

300,000

$ 300,000

Colt LLC

Related Party Transaction [Line Items]

Lease term

10 years

Number of renewals | Renewal

6

Lessor renewal term

5 years

Lease payment per ton | $ / T

3.40

Percentage of gross price

8.00%

Ruger LLC

Related Party Transaction [Line Items]

Lease term

10 years

Number of renewals | Renewal

6

Lessor renewal term

5 years

Lease payment per ton | $ / T

3.40

Percentage of gross price

8.00%

Ruger LLC | Royalties

Related Party Transaction [Line Items]

Percentage of gross price

8.00%

Colt LLC and Hillsboro and Macoupin Subsidiaries

Related Party Transaction [Line Items]

Prepaid royalty reserve

$ 74,600,000

NRP and Affiliated Entities

Related Party Transaction [Line Items]

Prepaid royalty reserve

$ 33,965,000

$ 46,306,000

Minimum deficiency payment not made

$ 46,000,000

Operating lease number of leases | Lease

2

Lease expiration date

Oct. 15, 2031

Lease renewal terms

5 years

NRP and Affiliated Entities | Minimum

Related Party Transaction [Line Items]

Lease payment per ton | $ / T

2.50

Percentage of gross price

8.00%

NRP and Affiliated Entities | Maximum

Related Party Transaction [Line Items]

Lease payment per ton | $ / T

5.40

Percentage of gross price

9.00%

Raven Energy LLC | Convent Marine Terminal Amendment | Adjusted Amount

Related Party Transaction [Line Items]

Minimum annual throughput volume | T / yr

5,000,000

Extended contract term

1 year

Williamson Rail Loadout Facility

Related Party Transaction [Line Items]

Lease payment per ton | $ / T

1.84

Lease expiration date

Mar. 12, 2018

Lease renewal terms

5 years

Rental fee

$ 5,000

Williamson Transport

Related Party Transaction [Line Items]

Lease payment per ton | $ / T

0.25

Sitran Terminal | New River Royalty, LLC

Related Party Transaction [Line Items]

Lease renewal terms

5 years

Rental fee

$ 50,000

Lease expiration year

2,020

[1]

Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment, as applicable

[2]

Cost of coal purchased

[3]

Coal sales

Related-Party Transactions - Su

Related-Party Transactions - Summary of Affiliate Amounts Included in Consolidated Balance Sheets (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Due from affiliates - current		$ 16,891	$ 16,615
Financing receivables - affiliate - current		2,904	2,689
Due from affiliates - noncurrent		1,843	2,691
Financing receivables - affiliate - noncurrent		67,235	70,139
Due to affiliates - current		20,904	8,536
Affiliates
Related Party Transaction [Line Items]
Prepaid royalties - current and noncurrent		8,845	69,555
Foresight Reserves and Affiliated Entities | Affiliates
Related Party Transaction [Line Items]
Due from affiliates - current	[1]		145
Prepaid royalties - current and noncurrent	[2]	7,599	69,555
Due to affiliates - current	[1]	1,373	1,054
Murray Energy And Affiliated Entities | Affiliates
Related Party Transaction [Line Items]
Due from affiliates - current	[3]	16,784	16,316
Financing receivables - affiliate - current		2,904	2,689
Due from affiliates - noncurrent		1,843	2,691
Financing receivables - affiliate - noncurrent		67,235	70,139
Due to affiliates - current		17,021	5,020
NRP and Affiliated Entities | Affiliates
Related Party Transaction [Line Items]
Due from affiliates - current		107	154
Prepaid royalties - current and noncurrent	[2]	1,246
Due to affiliates - current		$ 2,510	$ 2,462
[1]	Includes amounts due to/from a joint venture partially owned by an affiliate of The Cline Group – see Note 16.
[2]	Prepaid royalties with Foresight Reserves and affiliated entities is presented net of a $74,575 reserve as of December 31, 2016. Prepaid royalties with NRP and affiliated entities is presented net of a $33,965 and $46,306 reserve as of December 31, 2016 and 2015, respectively.
[3]	Includes amounts due from Javelin, a joint venture partially owned by Murray Energy.

Related-Party Transactions - 87

Related-Party Transactions - Summary of Affiliate Amounts Included in Consolidated Balance Sheets (Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Prepaid royalty reserve	$ 34,000	$ 46,300
NRP and Affiliated Entities
Related Party Transaction [Line Items]
Prepaid royalty reserve	33,965	$ 46,306
Foresight Reserves and Affiliated Entities
Related Party Transaction [Line Items]
Prepaid royalty reserve	$ 74,575

Related-Party Transactions - 88

Related-Party Transactions - Summary of Expenses (Income) Incurred With Affiliated Entities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Coal sales		$ 866,628	$ 979,179	$ 1,109,404
Purchased coal		13,541	17,444	18,232
Murray Energy And Affiliated Entities
Related Party Transaction [Line Items]
Coal sales	[1]	58,395	23,060
Overriding royalty and lease revenues	[2]	7,978	5,387
Terminal revenues	[2]	1,226	282
Purchased goods and services	[3]	8,305	3,326
Purchased coal	[4]	13,541	17,399
Sales commissions	[5]	216
Management services	[5]	8,919	4,667
NRP and Affiliated Entities
Related Party Transaction [Line Items]
Royalty expense	[6]	17,606	29,773	48,652
Loadout services	[6]	8,510	9,032	9,878
Foresight Reserves and Affiliated Entities
Related Party Transaction [Line Items]
Royalty expense	[6]	13,921	3,319	11,282
Land leases	[6],[7]	$ 177		100
Terminal fees	[7]		19,327	43,951
Administrative fee income	[8]		$ 52	$ 256
[1]	Coal sales
[2]	Other revenues
[3]	Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment, as applicable
[4]	Cost of coal purchased
[5]	Selling, general and administrative
[6]	Cost of coal produced (excluding depreciation, depletion and amortization)
[7]	Transportation
[8]	Other operating income, net

Variable Interest Entities (V89

Variable Interest Entities (VIEs) - Additional Information (Details)	Aug. 01, 2016USD ($)	Dec. 31, 2016USD ($)$ / T	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Feb. 29, 2016USD ($)	Jan. 31, 2016USD ($)	Mar. 31, 2015USD ($)	Aug. 31, 2013USD ($)
Variable Interest Entity [Line Items]
Net income attributable to noncontrolling interests		$ 169,000	$ 770,000	$ 3,909,000
Aggregate net book values reclassified from predecessor members’ equity to noncontrolling interest equity		$ 0
Adena And Hillsboro Transport Assets
Variable Interest Entity [Line Items]
Net income attributable to noncontrolling interests			300,000	3,400,000
Aggregate net book values reclassified from predecessor members’ equity to noncontrolling interest equity								$ 10,100,000
Incentive distribution rights’ equity contributed to Partnership Interest							$ 9,900,000
Contractor VIEs
Variable Interest Entity [Line Items]
Minimum fee received per ton of coal mined or processed | $ / T		0.01
Maximum fee paid per ton of coal mined or processed | $ / T		0.02
Net income attributable to noncontrolling interests		$ 200,000	$ 500,000	$ 500,000
Acquired outstanding equity units	100.00%
Aggregate cash consideration on equity units acquired	$ 100,000
Foresight Surety LLC
Variable Interest Entity [Line Items]
Payment to VIE						$ 2,500,000
Foresight Surety LLC | Letter of Credit
Variable Interest Entity [Line Items]
Debt Instrument, face amount					$ 2,500,000
letter of credit, cash collateral					$ 2,500,000
VIEs which the Partnership is not the Primary Beneficiary
Variable Interest Entity [Line Items]
Percentage of annual mining supply requirements purchased		90.00%
Initial term of agreement as amended		5 years
Amended agreement term expiration date		2018-04

Variable Interest Entities (V90

Variable Interest Entities (VIEs) - Summary of Consolidated VIE Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets
Current assets	$ 266,981	$ 210,340
Total assets	1,689,011	1,821,183
Liabilities:
Current liabilities	532,865	1,558,693
Total liabilities	1,843,604	1,802,300
Variable Interest Entity, Primary Beneficiary
Assets
Current assets		4,933
Long-term assets	2,500
Total assets	$ 2,500	4,933
Liabilities:
Current liabilities		12,835
Long-term liabilities		2,955
Total liabilities		$ 15,790

Fair Value of Financial Instr91

Fair Value of Financial Instruments - Fair Value of Net Financial Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant liability	$ (51,169)
Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Coal derivative contracts	7,315	$ 48,623
Diesel derivative contracts	(335)	(1,029)
Warrant liability	(51,169)
Total	(43,854)	47,594
Fair Value, Measurements, Recurring | Fair Value, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Coal derivative contracts	7,315	48,623
Diesel derivative contracts		(1,029)
Total	7,315	$ 47,594
Fair Value, Measurements, Recurring | Fair Value, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant liability	(51,169)
Total	$ (51,169)

Fair Value Measures and Disclos

Fair Value Measures and Disclosures - Additional Information (Details) - USD ($)	Aug. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Assets or liabilities transferred between level 1 and level 2		$ 0	$ 0	$ 0
Percentage of warrants to purchase of common units	4.50%
Exercise price of the warrants		$ 0.8928
Fair value of Long-Term Debt (Level III)		$ 1,378,600,000	$ 1,244,300,000
Warrants
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stock price volatility rate		70.00%
Dividend yield rate		0.00%
Risk free interest rate		2.61%

Fair Value of Financial Instr93

Fair Value of Financial Instruments - Fair Value of Gross Financial Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets	$ 7,650	$ 26,596
Long-Term – Coal Derivative Assets		22,027
Warrant liability	(51,169)
Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets	7,650	26,596
Long-Term – Coal Derivative Assets		22,027
Accrued Expenses	(335)	(1,029)
Warrant liability	(51,169)
Fair Value, Measurements, Recurring | Coal Derivative Contracts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets	7,650	26,596
Long-Term – Coal Derivative Assets		22,027
Accrued Expenses	(335)
Fair Value, Measurements, Recurring | Diesel Derivative Contracts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Accrued Expenses		$ (1,029)
Fair Value, Measurements, Recurring | Warrant Liability
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant liability	$ (51,169)

Fair Value of Financial Instr94

Fair Value of Financial Instruments - Fair Value Liabilities Measured on Recurring Basis with Unobservable Input Reconciliation (Details) - Warrant Liability $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Purchases, issuances and settlements	$ 34,045
Recorded fair value losses:
Included in earnings - loss / (gain)	17,124
Liability balance, ending	$ 51,169

Partners' Capital - Additional

Partners' Capital - Additional Information (Details) - USD ($)	Aug. 01, 2016	Jun. 23, 2014	Apr. 02, 2014	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Capital Unit [Line Items]
Minimum quarterly distribution per unit				$ 0.3375
Conversion of common units, description				Subordinated units will convert to common units, on a one-for-one basis, on the first business day after the Partnership has paid the MQD for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2017 and there are no outstanding arrearages on the common units. Notwithstanding the foregoing, the subordination period will end on the first business day after the Partnership has paid an aggregate amount of at least $2.025 per unit (150.0% of the MQD on an annualized basis) on the outstanding common and subordinated units and the Partnership has paid the related distribution on the incentive distribution rights, for any four-quarter period ending on or after March 31, 2015 and there are no outstanding arrearages on the common units.
Percentage paid of MQD required for conversion of subordinated units to common units				150.00%
Aggregate per unit annual distribution amount, for conversion of subordinated units to common units				$ 2.025
Employee compensation costs related to restructuring				$ 1,000,000	$ 11,300,000
Aggregate net book value of contributed companies						$ 60,600,000
Deferred prepaid expenses					$ 1,300,000
Members deficit balance allocated, pro rata base		$ 104,900,000
Deemed distribution			$ 300,000
Aggregate net book values reclassified from predecessor members’ equity to noncontrolling interest equity				$ 0
Contractor VIEs
Capital Unit [Line Items]
Acquired outstanding equity units	100.00%
Aggregate cash consideration on equity units acquired	$ 100,000
Foresight Energy LLC
Capital Unit [Line Items]
Percentage of ownership interests contributed						100.00%

Partners' Capital - Schedule of

Partners' Capital - Schedule of Percentage Allocations of Available Cash from Operating Surplus (Details)	12 Months Ended
	Dec. 31, 2016$ / shares
Minimum Quarterly Distribution
Distribution Made To Limited Partner [Line Items]
Total Quarterly Distribution Per Common Unit, maximum	$ 0.3375
Percentage Distributed To Unitholders	100.00%
First Target Distribution
Distribution Made To Limited Partner [Line Items]
Total Quarterly Distribution Per Common Unit, minimum	$ 0.3375
Total Quarterly Distribution Per Common Unit, maximum	$ 0.3881
Percentage Distributed To Unitholders	100.00%
Second Target Distribution
Distribution Made To Limited Partner [Line Items]
Total Quarterly Distribution Per Common Unit, minimum	$ 0.3881
Total Quarterly Distribution Per Common Unit, maximum	$ 0.4219
Percentage Distributed To Unitholders	85.00%
Percentage Distributed to IDR Holders	15.00%
Third Target Distribution
Distribution Made To Limited Partner [Line Items]
Total Quarterly Distribution Per Common Unit, minimum	$ 0.4219
Total Quarterly Distribution Per Common Unit, maximum	$ 0.5063
Percentage Distributed To Unitholders	75.00%
Percentage Distributed to IDR Holders	25.00%
Thereafter
Distribution Made To Limited Partner [Line Items]
Total Quarterly Distribution Per Common Unit, maximum	$ 0.5063
Percentage Distributed To Unitholders	50.00%
Percentage Distributed to IDR Holders	50.00%

Partners' Capital - Schedule 97

Partners' Capital - Schedule of Quarterly Distribution Paid Per Limited Partner Unit (Details) - $ / shares	3 Months Ended
	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014
Equity [Abstract]
Distribution paid per limited partner	$ 0.06	[1]	$ 0.38	$ 0.37	$ 0.36	$ 0.35	$ 0.03
[1]	In November 2015, we paid a quarterly distribution of $0.17 per unit payable to common unitholders, while suspending the distribution on all subordinated units. Chris Cline and one additional common unitholder elected to forego the $0.17 per common unit distribution on their collective 21.2 million common units.

Partners' Capital - Schedule 98

Partners' Capital - Schedule of Quarterly Distribution Paid Per Limited Partner Unit (Parenthetical) (Details) - $ / shares shares in Millions	1 Months Ended	3 Months Ended
	Nov. 30, 2015	Dec. 31, 2015	[1]	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014
Distribution Made To Limited Partner [Line Items]
Distribution paid per limited partner		$ 0.06		$ 0.38	$ 0.37	$ 0.36	$ 0.35	$ 0.03
Common Units
Distribution Made To Limited Partner [Line Items]
Distribution paid per limited partner	$ 0.17
Distribution of common units	21.2
[1]	In November 2015, we paid a quarterly distribution of $0.17 per unit payable to common unitholders, while suspending the distribution on all subordinated units. Chris Cline and one additional common unitholder elected to forego the $0.17 per common unit distribution on their collective 21.2 million common units.

Equity-Based Compensation - Add

Equity-Based Compensation - Additional Information (Details) - USD ($) $ in Thousands	Feb. 05, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation		$ 5,106	$ 13,704	$ 4,749
Shared-based compensation capitalized				$ 300
Unrecognized share based compensation expense		$ 1,000
Weighted average period for recognition of expense		1 year
Intrinsic value of non-vested grants		$ 1,800
Limited partners cash distributions payable		$ 300
Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation award, vesting period		3 years
LTIP Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate number of common units authorized		7,000,000
Share based compensation arrangement by share based payment award number of shares available for grant		4,800,000
Number of Units, Granted		58,851	1,873,423
Issuance of vested LTIP awards		1,421,662	652,786
Equity-based compensation award, vesting period		3 years
Issuance of non-vested awards		278,539	1,711,341	601,109
Units settled in cash to settle minimum tax obligations		509,378	75,522	53,745
LTIP Awards | Subordinated Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Granted	215,796
LTIP Awards | Common Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Granted	215,954
LTIP Awards | Phantom Share Units (PSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Granted		0	1,838,099	595,075
Issuance of vested LTIP awards			431,750	72,500
Issuance of non-vested awards		203,918
LTIP Awards | Phantom Share Units (PSUs) | Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Units, Granted		58,851	35,324	7,919
Issuance of non-vested awards		74,621

Equity-Based Compensation - Sum

Equity-Based Compensation - Summary of Partnership Equity-based Compensation Recorded in Consolidated Statements of Operations (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Selling, general and administrative
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Partnership's equity-based compensation	2.00%	58.00%	63.00%
Transition and reorganization costs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Partnership's equity-based compensation	84.00%	31.00%
Cost of coal produced (excluding depreciation, depreciation and amortization)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Partnership's equity-based compensation	14.00%	11.00%	37.00%

Equity-Based Compensation - 101

Equity-Based Compensation - Summary of Non-vested LTIP Award Activity (Details) - LTIP Awards - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Non-vested grants, Beginning	1,711,341	601,109
Number of Units, Granted	58,851	1,873,423
Number of Units, Vested	(1,421,662)	(652,786)
Number of Units, Forfeited	(69,991)	(110,405)
Non-vested grants, Ending	278,539	1,711,341
Non-vested grants, Beginning	$ 7.21	$ 19.99
Weighted Average Grant Date Fair Value per Unit, Granted	3.82	7.28
Weighted Average Grant Date Fair Value per Unit, Vested	4.76	17.25
Weighted Average Grant Date Fair Value per Unit, Forfeited	19.60	18.63
Non-vested grants, Ending	$ 15.88	$ 7.21

Earnings per Limited Partner102

Earnings per Limited Partner Unit - Summary of Partnership's Calculation of Net (Loss) Income per Common and Subordinated Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made To Limited Partner [Line Items]
Distributed earnings		$ 151,833	$ 49,220
Distributions in excess of earnings and undistributed (loss) earnings	$ (178,789)	(191,310)	20,972
Net (loss) income attributable to limited partner units	$ (178,789)	$ (39,477)	$ 70,192
Weighted-average units to calculate basic EPU	130,784	130,032	129,529
Weighted-average units to calculate diluted EPU	130,784	130,032	129,529
Basic net (loss) income per unit	$ (1.37)	$ (0.30)	$ 0.54
Diluted net (loss) income per unit	$ (1.37)	$ (0.30)	$ 0.54
Common Units
Distribution Made To Limited Partner [Line Items]
Distributed earnings		$ 79,733	$ 24,619
Distributions in excess of earnings and undistributed (loss) earnings	$ (90,015)	(95,776)	10,535
Net (loss) income attributable to limited partner units	$ (90,015)	$ (16,043)	$ 35,154
Weighted-average units to calculate basic EPU	65,829	65,098	64,790
Weighted-average units to calculate diluted EPU	65,829	65,098	64,790
Basic net (loss) income per unit	$ (1.37)	$ (0.25)	$ 0.54
Diluted net (loss) income per unit	$ (1.37)	$ (0.25)	$ 0.54
Subordinated Units
Distribution Made To Limited Partner [Line Items]
Distributed earnings		$ 72,100	$ 24,601
Distributions in excess of earnings and undistributed (loss) earnings	$ (88,774)	(95,534)	10,437
Net (loss) income attributable to limited partner units	$ (88,774)	$ (23,434)	$ 35,038
Weighted-average units to calculate basic EPU	64,955	64,934	64,739
Weighted-average units to calculate diluted EPU	64,955	64,934	64,739
Basic net (loss) income per unit	$ (1.37)	$ (0.36)	$ 0.54
Diluted net (loss) income per unit	$ (1.37)	$ (0.36)	$ 0.54

Earnings per Limited Partner103

Earnings per Limited Partner Unit - Summary of Partnership's Calculation of Net (Loss) Income per Common and Subordinated Unit (Parenthetical) (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Phantom Share Units (PSUs)
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share, amount	0.3	1.7	0.6

Risk Concentrations - Additiona

Risk Concentrations - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Murray Energy And Affiliated Entities
Concentration Risk [Line Items]
Accounts receivables, related parties	$ 18.6
Financing receivables, related parties	70.1
Customer Concentration Risk
Concentration Risk [Line Items]
Aggregate outstanding trade receivable balance	$ 14
Geographic Concentration Risk | All Countries | Sales Revenue, Net
Concentration Risk [Line Items]
Export sales as a percentage of total sales	17.00%	24.00%	30.00%
Geographic Concentration Risk | Europe/UK | Sales Revenue, Net
Concentration Risk [Line Items]
Export sales as a percentage of total sales	16.00%	22.00%	26.00%

Schedules of Risk Concentration

Schedules of Risk Concentrations (Details) - Sales Revenue, Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Customer A
Concentration Risk [Line Items]
Percentage of total coal sales	30.00%	22.00%	16.00%
Customer B
Concentration Risk [Line Items]
Percentage of total coal sales	10.00%	12.00%	12.00%
Customer C
Concentration Risk [Line Items]
Percentage of total coal sales	13.00%	11.00%
Customer D
Concentration Risk [Line Items]
Percentage of total coal sales			11.00%

Schedules of Risk Concentrat106

Schedules of Risk Concentrations (Details) (Parenthetical)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Customer Concentration Risk | Sales Revenue, Net | Maximum
Concentration Risk [Line Items]
Percentage of total coal sales	10.00%	10.00%	10.00%

Contingencies - Additional Info

Contingencies - Additional Information (Details) - USD ($)	1 Months Ended		12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 29, 2016	Jan. 31, 2016
Loss Contingencies [Line Items]
Minimum deficiency payment not made	$ 46,000,000		$ 46,000,000
Accrued litigation expense	4,800,000		4,800,000	$ 2,347,000
Cost of coal produced (excluding depreciation, depletion and amortization)			423,995,000	509,170,000	$ 449,905,000
Other operating (income) expense			22,161,000	$ 13,424,000	$ 2,837,000
Estimated insurance recoveries	0		0
Outstanding performance bonds	83,400,000		83,400,000
Cash collateral of surety bond	2,600,000		2,600,000
Foresight Reserves, LP
Loss Contingencies [Line Items]
Guarantee on surety bond						$ 50,500,000
Macoupin
Loss Contingencies [Line Items]
Possible loss contingencies							$ 3,300,000
Hillsboro Energy, LLC
Loss Contingencies [Line Items]
Cost of coal produced (excluding depreciation, depletion and amortization)			10,500,000
Other operating (income) expense			20,000,000
Employee Termination
Loss Contingencies [Line Items]
Loss contingency, amount		$ 600,000
Surety Bond
Loss Contingencies [Line Items]
Cash collateral of surety bond						$ 2,500,000
U.S. Equal Employment Opportunity Commission | Settled Litigation
Loss Contingencies [Line Items]
Litigation aggregate settlement amount	4,300,000
Insurance covered	3,800,000		$ 3,800,000
Railcar Lessors | Settled Litigation
Loss Contingencies [Line Items]
Compensatory damages sought	$ 3,700,000

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, cost recognized	$ 3	$ 3.3	$ 3.1
Award Modification
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, employer matching contribution, percent of employees' gross pay	100.00%
Defined contribution plan, maximum annual contributions per employee, percent	3.00%
3-5% of compensation
Defined Contribution Plan Disclosure [Line Items]
Defined contribution plan, employer matching contribution, percent of employees' gross pay	50.00%
Defined contribution plan, maximum annual contributions per employee, percent	2.00%

Selected Quarterly Financial109

Selected Quarterly Financial Information - Summary of the Unaudited Quarterly Results (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 252,922	$ 230,825	$ 226,000	$ 166,085	$ 241,650	$ 253,066	$ 251,222	$ 238,915	$ 875,832	$ 984,853	$ 1,109,404
Operating income (loss)	(22,475)	31,414	12,585	1,205	(29,659)	38,079	4,079	70,058	22,729	82,557	259,485
Net income (loss)	(85,012)	(24,331)	(27,670)	(41,607)	(64,309)	8,188	(25,280)	42,717	(178,620)	(38,684)	141,476
Net income (loss) attributable to limited partner units	$ (85,012)	$ (24,287)	$ (27,786)	$ (41,704)	$ (64,427)	$ 8,070	$ (25,403)	$ 42,283	$ (178,789)	$ (39,454)	$ 137,567
Basic and diluted income (loss) per limited partner unit	$ (0.65)	$ (0.19)	$ (0.21)	$ (0.32)	$ (0.49)	$ 0.06	$ (0.20)	$ 0.33

Selected Quarterly Financial110

Selected Quarterly Financial Information - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Line Items]
Debt restructuring costs		$ 6,100	$ 5,900	$ 9,700					$ 21,821	$ 3,930
Loss on early extinguishment of debt		13,200							13,203		$ 4,979
Long-lived asset impairments	$ 74,600				$ 12,600				74,575	12,592	$ 34,700
Loss of change in fair value of warrants	18,600								17,124
Transition and reorganization costs					4,100	$ 5,000	$ 12,300		6,889	21,433
Prepaid royalty reserve	34,000				46,300				$ 34,000	46,300
Murray Energy Corporation
Quarterly Financial Information Disclosure [Line Items]
Other operating income, net								$ 13,500
Hillsboro Energy, LLC
Quarterly Financial Information Disclosure [Line Items]
Insurance recovery recorded in cost of coal produced (excluding depreciation, depletion and amortization)		$ 10,500
Other operating income, net	$ 20,000
Prepaid royalty reserve					11,600					$ 11,600
Write-off of deferred costs					$ 1,000

Valuation and Qualifying Acc111

Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Prepaid Royalty Recoupment Reserve
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	$ 46,306	$ 34,700
Charged to Costs and Expenses	74,575	11,606	$ 34,700
Written-off / Other	(12,341)
Balance at End of Period	108,540	46,306	$ 34,700
Reserve for Materials and Supplies
Valuation And Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	458
Charged to Costs and Expenses	516	458
Written-off / Other	(254)
Balance at End of Period	$ 720	$ 458