Foresight Energy (FELPQ) 10-Q 14 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Aug. 11, 2017
Document And Entity Information [Line Items]
Entity Registrant Name	Foresight Energy LP
Entity Central Index Key	1,540,729
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2,017
Trading Symbol	FELP
Document Fiscal Period Focus	Q2
Common Units
Document And Entity Information [Line Items]
Entity Units Outstanding		77,435,175
Subordinated Units
Document And Entity Information [Line Items]
Entity Units Outstanding		64,954,691

Unaudited Condensed Consolidate

Unaudited Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 7,208
Accounts receivable	33,374
Due from affiliates	22,631
Financing receivables - affiliate	3,019
Inventories, net	71,990
Prepaid royalties	1,977
Deferred longwall costs	4,087
Coal derivative assets	1,318
Other prepaid expenses and current assets	23,661
Contract-based intangibles	36,340
Total current assets	205,605
Property, plant, equipment and development, net	2,533,933
Due from affiliates	947
Financing receivables - affiliate	65,696
Prepaid royalties	417
Other assets	2,783
Contract-based intangibles	11,032
Total assets	2,820,413
Current liabilities:
Current portion of long-term debt and capital lease obligations	69,635
Current portion of sale-leaseback financing arrangements	1,573
Accrued interest	16,250
Accounts payable	72,370
Accrued expenses and other current liabilities	54,893
Asset retirement obligations	8,167
Due to affiliates	8,387
Contract-based intangibles	23,197
Total current liabilities	254,472
Long-term debt and capital lease obligations	1,286,382
Sale-leaseback financing arrangements	199,363
Asset retirement obligations	37,635
Other long-term liabilities	45,584
Contract-based intangibles	124,937
Total liabilities	1,948,373
Limited partners' capital (deficit):
Total partners' capital (deficit)	872,040
Total liabilities and partners' capital (deficit)	2,820,413
Predecessor
Current assets:
Cash and cash equivalents		$ 103,690
Accounts receivable		54,905
Due from affiliates		16,891
Financing receivables - affiliate		2,904
Inventories, net		43,052
Prepaid royalties		3,136
Deferred longwall costs		13,310
Coal derivative assets		7,650
Other prepaid expenses and current assets		21,443
Total current assets		266,981
Property, plant, equipment and development, net		1,318,937
Due from affiliates		1,843
Financing receivables - affiliate		67,235
Prepaid royalties		13,765
Other assets		20,250
Total assets		1,689,011
Current liabilities:
Current portion of long-term debt and capital lease obligations		368,993
Current portion of sale-leaseback financing arrangements		1,372
Accrued interest		29,760
Accounts payable		60,971
Accrued expenses and other current liabilities		43,592
Asset retirement obligations		7,273
Due to affiliates		20,904
Total current liabilities		532,865
Long-term debt and capital lease obligations		1,022,070
Sale-leaseback financing arrangements		190,497
Asset retirement obligations		37,644
Warrant liability		51,169
Other long-term liabilities		9,359
Total liabilities		1,843,604
Limited partners' capital (deficit):
Total partners' capital (deficit)		(154,593)
Total liabilities and partners' capital (deficit)		1,689,011
Common Units
Limited partners' capital (deficit):
Total partners' capital (deficit)	527,225
Common Units | Predecessor
Limited partners' capital (deficit):
Total partners' capital (deficit)		100,628
Subordinated Units
Limited partners' capital (deficit):
Total partners' capital (deficit)	$ 344,815
Subordinated Units | Predecessor
Limited partners' capital (deficit):
Total partners' capital (deficit)		$ (255,221)

Unaudited Condensed Consolidat3

Unaudited Condensed Consolidated Balance Sheets (Parenthetical) - shares shares in Thousands	Jun. 30, 2017	Dec. 31, 2016
Common Units
Capital units, Outstanding	77,235
Common Units | Predecessor
Capital units, Outstanding		66,105
Subordinated Units
Capital units, Outstanding	64,955
Subordinated Units | Predecessor
Capital units, Outstanding		64,955

Unaudited Condensed Consolidat4

Unaudited Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Jun. 30, 2016
Revenues
Coal sales	$ 204,516
Other revenues	2,577
Total revenues	207,093
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)	105,790
Transportation	28,258
Depreciation, depletion and amortization	49,537
Contract amortization	8,733
Accretion on asset retirement obligations	728
Selling, general and administrative	7,277
Loss on commodity derivative contracts	1,117
Other operating (income) expense, net	(13,490)
Operating income	19,143
Other expenses:
Interest expense, net	35,420
Loss on early extinguishment of debt		$ 95,500
Net loss	(16,277)
Net loss attributable to controlling interests	(16,277)
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units	(16,277)
Predecessor
Revenues
Coal sales		227,813	$ 224,093	$ 387,190
Other revenues		2,581	1,907	4,895
Total revenues		230,394	226,000	392,085
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)		117,762	112,070	201,246
Cost of coal purchased		7,973		551
Transportation		37,726	37,557	63,355
Depreciation, depletion and amortization		39,298	45,467	81,884
Accretion on asset retirement obligations		710	844	1,688
Selling, general and administrative		6,554	5,588	11,308
Transition and reorganization costs			950	6,889
Loss on commodity derivative contracts		1,492	10,760	11,283
Other operating (income) expense, net		451	179	91
Operating income		18,428	12,585	13,790
Other expenses:
Interest expense, net		43,380	34,335	67,330
Debt restructuring costs			5,920	15,630
Change in fair value of warrants		(9,278)
Loss on early extinguishment of debt		95,510		107
Net loss		(111,184)	(27,670)	(69,277)
Less: net income attributable to noncontrolling interests			116	214
Net loss attributable to controlling interests		(111,184)	(27,786)	(69,491)
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units		(111,184)	(27,786)	(69,491)
Common Units
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units	$ (8,790)
Net loss per limited partner unit - basic and diluted	$ (0.12)
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted	76,270
Common Units | Predecessor
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units		$ (56,259)	$ (13,995)	$ (34,886)
Net loss per limited partner unit - basic and diluted		$ (0.85)	$ (0.21)	$ (0.53)
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted		66,533	65,917	65,555
Subordinated Units
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units	$ (7,487)
Net loss per limited partner unit - basic and diluted	$ (0.12)
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted	64,955
Subordinated Units | Predecessor
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units		$ (54,925)	$ (13,791)	$ (34,605)
Net loss per limited partner unit - basic and diluted		$ (0.85)	$ (0.21)	$ (0.53)
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted		64,955	64,955	64,955

Unaudited Condensed Consolidat5

Unaudited Condensed Consolidated Statement of Partners' Capital - USD ($) $ in Thousands	Total	Common Units	Subordinated Units	Limited PartnersCommon Units	Limited PartnersSubordinated Units
Beginning Balance (Predecessor) at Dec. 31, 2016	$ (154,593)	$ 100,628	$ (255,221)	$ 100,628	$ (255,221)
Beginning Balance (in units) (Predecessor) at Dec. 31, 2016				66,104,673	64,954,691
Net loss | Predecessor	(111,184)			$ (56,259)	$ (54,925)
Issuance of common units to Murray Energy (affiliate) | Predecessor	60,586			$ 60,586
Issuance of common units to Murray Energy (affiliate) (in units) | Predecessor				9,628,108
Reclassification of warrants | Predecessor	41,888			$ 41,888
Equity-based compensation | Predecessor	318			$ 318
Issuance of equity-based awards | Predecessor				235
Purchase accounting adjustment | Predecessor	1,163,478			$ 449,308	714,170
Ending Balance (Predecessor) at Mar. 31, 2017	(162,985)			147,161	(310,146)
Ending Balance at Mar. 31, 2017	1,000,493			$ 596,469	$ 404,024
Ending Balance (in units) (Predecessor) at Mar. 31, 2017				75,733,016	64,954,691
Ending Balance (in units) at Mar. 31, 2017				75,733,016	64,954,691
Net loss	(16,277)			$ (8,790)	$ (7,487)
Conversion of warrants, net				1,389,524
Equity-based compensation	211			$ 211
Issuance of equity-based awards				112,726
Net settlement of withholding taxes on issued LTIP awards	(361)			$ (361)
Purchase accounting adjustment	(112,026)			(60,304)	(51,722)
Ending Balance at Jun. 30, 2017	$ 872,040	$ 527,225	$ 344,815	$ 527,225	$ 344,815
Ending Balance (in units) at Jun. 30, 2017				77,235,266	64,954,691

Unaudited Condensed Consolidat6

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016
Cash flows from operating activities
Net loss	$ (16,277)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	49,537
Amortization of debt discount and deferred issuance costs	628
Contract amortization	8,733
Equity-based compensation	211
Loss on commodity derivative contracts	1,117
Settlements of commodity derivative contracts	444
Debt extinguishment expense		$ 95,500
Other	5,867
Changes in operating assets and liabilities:
Accounts receivable	1,836
Due from/to affiliates, net	(4,204)
Inventories	(19,863)
Prepaid expenses and other current assets	(8,833)
Prepaid royalties	4,276
Commodity derivative assets and liabilities	(303)
Accounts payable	4,075
Accrued interest	11,801
Accrued expenses and other current liabilities	423
Other	(965)
Net cash provided by operating activities	38,503
Cash flows from investing activities
Investment in property, plant, equipment and development	(21,732)
Return of investment on financing arrangements with Murray Energy	719
Net cash used in investing activities	(21,013)
Cash flows from financing activities
Net change in borrowings under A/R securitization program	(100)
Payments on other long-term debt and capital lease obligations	(12,287)
Other	(2,130)
Net cash used in financing activities	(14,517)
Net increase (decrease) in cash and cash equivalents	2,973
Cash and cash equivalents, beginning of period	4,235
Cash and cash equivalents, end of period	7,208	4,235
Supplemental disclosures of non-cash financing activities:
Short-term insurance financing and vendor financing	2,188
Predecessor
Cash flows from operating activities
Net loss		(111,184)	$ (69,277)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		39,298	81,884
Amortization of debt discount and deferred issuance costs		6,365	3,447
Equity-based compensation		318	4,427
Loss on commodity derivative contracts		1,492	11,283
Settlements of commodity derivative contracts		3,724	9,921
Realized gains on coal derivatives included in investing activities		(3,520)
Transition and reorganization expenses paid by Foresight Reserves			2,333
Change in fair value of warrants		(9,278)
Debt extinguishment expense		95,510	107
Other		1,321	2,394
Changes in operating assets and liabilities:
Accounts receivable		19,695	(3,849)
Due from/to affiliates, net		(13,157)	13,783
Inventories		(917)	(1,296)
Prepaid expenses and other current assets		(2,375)	(5,690)
Prepaid royalties		(241)	2,314
Commodity derivative assets and liabilities		(532)	2,089
Accounts payable		7,324	(8,703)
Accrued interest		(9,803)	22,870
Accrued expenses and other current liabilities		(3,430)	5,135
Other		1,782	440
Net cash provided by operating activities		22,392	73,612
Cash flows from investing activities
Investment in property, plant, equipment and development		(19,908)	(13,293)
Return of investment on financing arrangements with Murray Energy		705	1,319
Settlement of certain coal derivatives		3,520
Proceeds from sale of property, plant and equipment		1,898	83
Net cash used in investing activities		(13,785)	(11,891)
Cash flows from financing activities
Net change in borrowings under revolving credit facility		(352,500)	(10,100)
Net change in borrowings under A/R securitization program		7,000
Proceeds from other long-term debt		1,234,438
Payments on other long-term debt and capital lease obligations		(970,721)	(22,726)
Proceeds from issuance of common units to Murray Energy		60,586
Debt extinguishment costs		(57,645)
Debt issuance costs paid		(27,328)
Other		(1,892)	(1,258)
Net cash used in financing activities		(108,062)	(34,084)
Net increase (decrease) in cash and cash equivalents		(99,455)	27,637
Cash and cash equivalents, beginning of period	$ 4,235	103,690	17,538
Cash and cash equivalents, end of period		4,235	45,175
Supplemental disclosures of non-cash financing activities:
Non-cash capital contribution from Foresight Reserves LP			1,046
Short-term insurance financing and vendor financing			$ 603
Reclassification of warrant liability to partners' capital		$ 41,888

Organization, Nature of Busines

Organization, Nature of Business and Basis of Presentation	6 Months Ended
	Jun. 30, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization, Nature of Business and Basis of Presentation	1. Organization, Nature of Business 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. Because this transaction was between entities under common control, the contributed assets and liabilities of FELLC were recorded in the combined consolidated financial statements of FELP at FELLC’s historical cost. FELP has been managed by Foresight Energy GP LLC (“FEGP”) subsequent to the IPO. On April 16, 2015, Murray Energy Corporation (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% voting interest in FEGP and all of the outstanding subordinated units of FELP, representing a 50% ownership of the Partnership’s limited partner units outstanding at that time. On March 28, 2017, following the completion of a debt refinancing (see Note 8), Murray Energy exercised its option (the “FEGP Option”) to acquire an additional 46% voting interest in FEGP from Foresight Reserves and Michael J. Beyer (“Beyer”) pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and Beyer, as amended, thereby increasing Murray Energy’s voting interest in FEGP to 80%. The aggregate exercise price of the FEGP Option was $15 million. Murray Energy’s acquisition of the incremental ownership in FEGP resulted in its obtaining control of FELP. Per ASC”) 805-50-25-4, Murray Energy, as the acquirer of FELP through FEGP, has the option to apply pushdown accounting in the separate financial statements of the acquiree. Murray Energy elected to adopt pushdown accounting in our stand alone financial statements and therefore we have reflected the required purchase accounting adjustments in our consolidated financial statements (see Note 3). Also, due to the application of "pushdown" accounting, our condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. The periods prior to the acquisition date are identified as “Predecessor” and the period after the acquisition date is identified as “Successor”. For accounting purposes, management has designated the acquisition date as March 31, 2017 (the “Acquisition Date”), as the operating results and change in financial position for the intervening period was not material. As used hereafter in this report, the terms “Foresight Energy LP,” “FELP,” the “Partnership,” “we,” “us” or like terms, refer to the consolidated results of Foresight Energy LP and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated. 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. In April 2016, we temporarily sealed the entire mine to reduce the oxygen flow paths into the mine. In May 2017, we breached the seal and mine rescue teams are currently evaluating and monitoring the mine. 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 United States, as well as overseas markets. The accompanying condensed consolidated financial statements contain all significant adjustments (consisting of normal recurring accruals) that, in the opinion of management, are necessary to present fairly, the Partnership’s condensed consolidated financial position, results of operations and cash flows for all periods presented. In preparing the condensed consolidated financial statements, management used estimates and assumptions that may affect reported amounts and disclosures. To the extent there are material differences between the estimates and actual results, the impact to the Partnership’s financial condition or results of operations could be material. The unaudited condensed consolidated financial statements do not include footnotes and certain financial information as required annually under U.S. generally accepted accounting principles (“U.S. GAAP”) and, therefore, should be read in conjunction with the annual audited consolidated financial statements for the year ended December 31, 2016 included in our Annual Report on Form 10-K filed with the SEC on March 1, 2017. The results of operations for interim periods are not necessarily indicative of results that can be expected for any future period, including the year ending December 31, 2017. Intercompany transactions are eliminated in consolidation.

New Accounting Standards

New Accounting Standards	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
New Accounting Standards	2. New Accounting Standards In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation, In July 2015, the FASB issued ASU 2015-11, Inventory: Simplifying the Measurement of Inventory In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers , We are in the process of reviewing the various terms and clauses within our coal sales contracts and

Pushdown Accounting

Pushdown Accounting	6 Months Ended
	Jun. 30, 2017
Pushdown Accounting [Abstract]
Pushdown Accounting	3. Pushdown Accounting Pursuant to the acquisition by Murray Energy of the controlling interest in FEGP, management, with the assistance of a third-party valuation firm, has preliminarily estimated the fair value of FELP’s assets and liabilities as of the Acquisition Date. Given that the valuation being performed by the third-party valuation firm is not yet complete, the value of certain assets and liabilities are preliminary in nature and will be adjusted as additional analysis is performed and as additional information is obtained about the facts and circumstances that existed at the acquisition date. As a result, material adjustments to this allocation may occur as the valuation and the related "push down" accounting is finalized (such finalization to be completed within one year of the Acquisition Date, per the terms of ASC 805-50-25-4). Adjustments to the fair value of FELP’s asset and liabilities as of the Acquisition Date will be recorded during the period in which the adjustment is determined, including the effect on earnings of any amounts we would have recorded in previous periods if the accounting had been completed at the Acquisition Date (i.e. the historical reported financial statements will not be retrospectively adjusted). There was no impact to the condensed consolidated statement of operations during the period from April 1, 2017 to June 30, 2017 from changes to the estimated fair value of FELP’s assets and liabilities during the period from April 1, 2017 to June 30, 2017 that would have been recognized in previous periods if the adjustments to provisional amounts had been recognized as of the Acquisition Date. The preliminary fair value of our mineral rights, which are controlled through private coal leases, were established utilizing discounted cash flow (“DCF”) models. The DCF models were based on assumptions market participants would use in the pricing of these assets as well as projections of revenues and expenditures that would be incurred to mine or maintain these coal reserves through the life of mine. Our DCF models assume that the combustion event at our Hillsboro mine will subside and that production will resume at this mine. The tax-effected discount rates utilized in the DCF models ranged from 11.5% to 15.5% and the future cash flows were based on our forecast models, which included a variety of estimates and assumptions, such as pricing and demand for coal and expected future capital expenditures. Coal pricing was based principally on third-party forward pricing curves, adjusted for the quality and expected sales point of our coal. The preliminary fair value of plant and equipment was established with the assistance of a third-party valuation firm utilizing both market and cost approaches. The market approach was used to estimate the value of assets where detailed product specification data and maintenance history for the asset was available and an active market was identified for comparable property. The cost approach was utilized where there were limitations in the secondary equipment market. Under the cost approach, an estimate of the replacement cost of the asset was made adjusting for depreciation due to physical deterioration and also contemplated functional and economic obsolescence, where appropriate. Useful lives were assigned to all assets based on remaining future economic benefit of each asset. The carrying values of certain of FELP's assets and liabilities in this preliminary estimate were assumed to approximate their fair values. The preliminary net purchase accounting adjustments to record the assets and liabilities of FELP to fair value as of the Acquisition Date resulted in a $1.1 billion net increase to net assets, and was comprised of the following preliminary adjustments from carrying value as of the Acquisition Date (in thousands): Working capital and certain other long-term asset accounts (1) $ (48,503 ) Mineral rights, land and land rights (2) 1,533,171 Plant, equipment and development (2) (261,739 ) Contract-based intangibles, net (92,029 ) Deferred debt issuance costs (33,879 ) Sales-leaseback financing arrangements (9,267 ) Long-term liabilities, net (1) (36,302 ) Pushdown accounting adjustment $ 1,051,452 (1) – Accrued expenses and other current liabilities and other long-term liabilities include liabilities of $16.9 million and $38.9 million, respectively, for certain royalty and transportation executory contracts under which we have contractual future minimum required payments but we do not expect to receive any future economic benefits. (2) – The development costs of the mine were reduced to zero as part of the fair value adjustment and the corresponding value of mineral rights assets were increased to reflect the future cash flows that the developed mines are expected to generate. As a result, the value of the plant, equipment and development asset category decreased significantly and the value of the mineral rights category increased significantly. The following table presents each major class of intangible assets preliminarily identified as of the Acquisition Date (in thousands): Favorable sales contracts, net $ 20,770 Unfavorable royalty agreements (112,799 ) Total contract-based intangibles, net $ (92,029 ) The fair values of favorable sales contracts, net and unfavorable royalty agreements were determined using a DCF model based on the difference between estimated market rates and actual contract rates for each of the respective contracts. The favorable and unfavorable sales contract assets and liabilities will be amortized into contract amortization in the consolidated statement of operations on a per ton basis as the coal is sold throughout the term of each individual sales contract. The unfavorable royalty agreement liabilities will be amortized into contract amortization in the consolidated statement of operations over a weighted average period of 17.2 years.

Commodity Derivative Contracts

Commodity Derivative Contracts	6 Months Ended
	Jun. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts	4. 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 fixed price coal supply sales agreements and coal derivative swap contracts. As of June 30, 2017 and December 31, 2016, we had outstanding coal derivative swap contracts to fix the selling price on 0.1 million tons and 0.5 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 through 2017. The coal derivative 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 condensed consolidated balance sheets (see Note 11). 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. We received $3.5 million in proceeds during the predecessor period from January 1, 2017 to March 31, 2017 from the settlement of derivatives that were reclassified from an operating cash flow activity to an investing activity in the condensed consolidated statement 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	6 Months Ended
	Jun. 30, 2017
Receivables [Abstract]
Accounts Receivable	5. Accounts Receivable Accounts receivable consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Trade accounts receivable $ 25,968 $ 42,862 Other receivables 7,406 12,043 Total accounts receivable $ 33,374 $ 54,905

Inventories

Inventories	6 Months Ended
	Jun. 30, 2017
Inventory Disclosure [Abstract]
Inventories	6. Inventories Inventories consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Parts and supplies $ 17,872 $ 18,712 Raw coal 8,191 4,907 Clean coal 45,927 19,433 Total inventories $ 71,990 $ 43,052

Property, Plant, Equipment and

Property, Plant, Equipment and Development, Net	6 Months Ended
	Jun. 30, 2017
Property Plant And Equipment [Abstract]
Property, Plant, Equipment and Development, Net	7. Property, Plant, Equipment and Development, Net Property, plant, equipment and development, net consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Mineral rights, land and land rights $ 1,630,038 $ 99,909 Plant, equipment and development 960,580 2,318,697 Total property, plant, equipment and development 2,590,618 2,418,606 Less: accumulated depreciation, depletion and amortization (56,685 ) (1,099,669 ) Property, plant, equipment and development, net $ 2,533,933 $ 1,318,937 In conjunction with pushdown accounting, property, plant, equipment and development was measured at fair value as of the Acquisition Date, which also impacted how value was assigned between the categories within property, plant, equipment and development (see Note 3).

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Lease Obligations	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt and Capital Lease Obligations	8. Long-Term Debt and Capital Lease Obligations Long-term debt and capital lease obligations consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Prior Second Lien Notes $ — $ 349,100 2017 Exchangeable PIK Notes — 299,859 Prior Revolving Credit Facility ($450.0 million capacity) — 352,500 Prior Term Loan due 2020 — 295,667 2023 Second Lien Notes 425,000 — New Term Loan due 2022 822,938 — Revolving Credit Facility ($170.0 million capacity) — — Trade A/R Securitization 21,100 14,200 5.78% longwall financing arrangement 33,615 39,217 5.555% longwall financing arrangement 36,094 41,250 Capital lease obligations 32,177 41,457 Subtotal - Total long-term debt and capital lease obligations principal outstanding 1,370,924 1,433,250 Unamortized deferred financing costs and debt discounts (14,907 ) (42,187 ) Total long-term debt and capital lease obligations 1,356,017 1,391,063 Less: current portion (69,635 ) (368,993 ) Non-current portion of long-term debt and capital lease obligations $ 1,286,382 $ 1,022,070 On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to FELP in exchange for 9.6 million common units of FELP. The cash was utilized to redeem, pursuant to an equity claw redemption provision, $54.5 million of the then outstanding Second Lien Senior Secured Notes due 2021 (the “Prior Second Lien Notes”) at a redemption price equal to 110% of the principal thereof, plus accrued and unpaid interest. On March 28, 2017 (the “Closing Date”), FELP, together with its wholly-owned subsidiaries Foresight Energy LLC (the “Borrower” or “FELLC”) and Foresight Energy Finance Corporation (the “Co-Issuer” and together with FELLC, the “Issuers”) and certain of the Issuers’ subsidiaries, completed a series of transactions to refinance certain previously outstanding indebtedness (the “Refinancing Transactions”). The new debt issued was as follows: • the Issuers issued $425.0 million aggregate principal amount of Second Lien Senior Secured Notes due 2023 (the “2023 Second Lien Notes”) and • the Borrower entered into a new credit agreement (the “New Credit Agreement”) providing for new senior secured first-priority credit facilities (the “New Credit Facilities”) consisting of a new senior secured first-priority $825.0 million term loan with a five-year maturity (the “New Term Loan”) and a new senior secured first-priority $170.0 million revolving credit facility with a maturity of four years, including both a letter of credit sub-facility and a swing-line loan sub-facility (the “Revolving Credit Facility”). We incurred third-party professional fees totaling $27.3 million related to the new indebtedness. The Partnership retired the following indebtedness in the Refinancing Transactions: • the remaining Prior Second Lien Notes at a redemption price equal to the principal amount thereof plus the applicable premium as of, and accrued and unpaid interest; • the Second Lien Senior Secured Exchangeable PIK Notes due 2017 (the “2017 Exchangeable PIK Notes”) at a redemption price equal to the principal amount thereof, plus accrued and unpaid interest; and • the Partnership’s outstanding credit facilities (the “Prior Credit Facilities”), including the revolving credit facility (the “Prior Revolving Credit Facility”) and the term loan (the “Prior Term Loan”), including, in each case, accrued and unpaid interest. As a result of the Restructuring Transactions, a loss on the early extinguishment of debt of $95.5 million was recognized during the period from January 1, 2017 to March 31, 2017 for the incurrence of $57.6 million in make-whole/equity-claw premiums and other cash costs to retire the Prior Second Lien Notes early and the write-off of $37.9 million of unamortized debt discounts and debt issuance costs related to the retired indebtedness. Description of the New Credit Facilities On the Closing Date, the Borrower entered into a New Credit Agreement providing for new senior secured first-priority credit facilities consisting of a new senior secured first-priority $825.0 million term loan with a maturity of five years and a new senior secured first-priority $170.0 million revolving credit facility with a maturity of four years, including both a letter of credit sub-facility and a swing-line loan sub-facility. The New Term Loan was issued at an initial discount of $12.4 million, which is being amortized using the effective interest method over the term of the loan. Amounts outstanding under the New Credit Facilities bear interest as follows: • in the case of the New Term Loan, at the Borrower’s option, at (a) LIBOR (subject to a LIBOR floor of 1.00%) plus 5.75% per annum; or (b) a base rate plus 4.75% per annum; and • in the case of borrowings under the Revolving Credit Facility, at the Borrower’s option, at (a) LIBOR (subject to a floor of zero) plus an applicable margin ranging from 5.25% to 5.50% per annum or (b) a base rate plus an applicable margin ranging from 4.25% to 4.50% per annum, in each case, such applicable margins to be determined based on our net first lien secured leverage ratio. In addition to paying interest on the outstanding principal under the New Credit Facilities, we are required to pay a quarterly commitment fee with respect to the unused portions of our Revolving Credit Facility and customary letter of credit fees. The New Credit Facilities require scheduled quarterly amortization payments on the New Term Loan in an aggregate annual amount equal to 1.0% of the original principal amount of the New Term Loan, with the balance to be paid at maturity. The New Credit Facilities also require us to prepay outstanding borrowings, subject to certain exceptions, with: • 75% (which will be reduced to 50%, 25% and 0% based on satisfaction of specified net secured leverage ratio tests) of our annual excess cash flow, as defined under the New Credit Facilities; • 100% of the net cash proceeds of non-ordinary course asset sales and other dispositions of property, in each case subject to certain exceptions and customary reinvestment rights; • 100% of the net cash proceeds of insurance (other than insurance proceeds relating to the Deer Run mine), in each case subject to certain exceptions and customary reinvestment rights; and • 100% of the net cash proceeds of any issuance or incurrence of debt, other than proceeds from debt permitted under the New Credit Facilities. We may voluntarily repay outstanding loans under the New Credit Facilities at any time, without prepayment premium or penalty, except in connection with a repricing transaction in respect of the New Term Loan, in each case subject to customary “breakage” costs with respect to Eurodollar Rate loans. All obligations under the New Credit Facilities are guaranteed by FELP on a limited recourse basis (where recourse is limited to its pledge of stock of the Borrower) and are or will be unconditionally guaranteed, jointly and severally, on a senior secured first-priority basis by each of the Borrower’s existing and future direct and indirect, wholly-owned domestic restricted subsidiaries (which do not currently include Hillsboro Energy LLC), subject to certain exceptions. The New Credit Facilities require that we comply on a quarterly basis with a maximum net first lien secured leverage ratio of 3.75:1.00, stepping down by 0.25x in each of the first quarters of 2019 and 2021, which financial covenant is solely for the benefit of the lenders under the Revolving Credit Facility. The New Credit Facilities also contain certain customary affirmative covenants and events of default, including relating to a change of control. As of June 30, 2017, we had no borrowings outstanding under our Revolving Credit Facility, and available borrowing capacity under the Revolving Credit Facility, net of outstanding letters of credit of $11.5 million, was $158.5 million. Description of the 2023 Second Lien Notes On the Closing Date, the Issuers issued $425.0 million aggregate principal amount of 2023 Second Lien Notes pursuant to an indenture (the “Indenture”), dated as of the Closing Date, by and among the Issuers, the guarantors party thereto and the trustee. The 2023 Second Lien Notes have a maturity date of April 1, 2023 and bear interest at a rate of 11.50% per annum, payable in cash semi-annually on April 1 and October 1 (commencing on October 1, 2017). Prior to April 1, 2020, the Issuers may redeem the 2023 Second Lien Notes in whole or in part at a price equal to 100% of the aggregate principal amount thereof plus accrued and unpaid interest, if any, plus the applicable “make-whole” premium. In addition, prior to April 1, 2020, the Issuers may redeem up to 35% of the aggregate principal amount of the 2023 Second Lien Notes at a price equal to 111.50% of the aggregate principal amount of the 2023 Second Lien Notes redeemed with the proceeds from a qualified equity offering, subject to at least 50% of the aggregate principal amount of the 2023 Second Lien Notes remaining outstanding after giving effect to any such redemption. On or after April 1, 2020, the Issuers may redeem the Notes at a price equal to: (i) 105.750% of the aggregate principal amount of the 2023 Second Lien Notes redeemed prior to April 1, 2021; (ii) 102.875% of the aggregate principal amount of the 2023 Second Lien Notes redeemed on or after April 1, 2021 but prior to April 1, 2022; and (iii) 100.000% of the aggregate principal amount of the 2023 Second Lien Notes redeemed thereafter.

Related-Party Transactions

Related-Party Transactions	6 Months Ended
	Jun. 30, 2017
Related Party Transactions [Abstract]
Related-Party Transactions	9. Related-Party Transactions Overview Affiliated entities of FELP principally include: (a) Murray Energy, owner of a 80% interest in our general partner (effective March 28, 2017) and owner of all of the outstanding subordinated limited partner units, (b) Entities owned and controlled by Chris Cline, the former majority owner and former chairman of our general partner and (c) through May 9, 2017, Natural Resource Partners LP (“NRP”) and its affiliates, for which Chris Cline directly and indirectly beneficially owned a 31% and 4% interest in the general and limited partner interests of NRP, respectively. On May 9, 2017, the affiliate owned by Chris Cline sold its holdings in NRP’s general partner. As a result, NRP and its affiliates were not treated as related parties after May 9, 2017. We routinely engage in transactions in the normal course of business with Murray Energy and its subsidiaries, NRP and its subsidiaries and Foresight Reserves and its affiliates. These transactions include, among others, production royalties, transportation services, administrative arrangements, coal handling and storage services, supply agreements, service agreements, land leases and sale-leaseback financing arrangements. We also acquire mining equipment from subsidiaries of Murray Energy. Murray Investments In April 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 nearly 50% of the outstanding limited partner units in FELP, including all of the outstanding subordinated units. On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to us in exchange for 9,628,108 common units of FELP. On March 28, 2017, following completion of the Refinancing Transactions, Murray Energy exercised its FEGP Option to acquire an additional 46% voting interest in FEGP from Foresight Reserves and Beyer pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Reserves and Beyer, as amended, thereby increasing Murray Energy’s voting interest in the General Partner to 80%. The aggregate exercise price of the FEGP Option was $15 million. FEGP has continued to govern the Partnership subsequent to this transaction. Murray Energy is also a holder of 17,556 of FELP’s outstanding warrants as of June 30, 2017. Following the exercise of the FEGP Option, pursuant to the operating agreement of the General Partner, all members of the board of directors of the General Partner (the “Board”), other than Paul Vining, are deemed appointed by Murray Energy and can be removed and replaced by Murray Energy at its sole discretion. Murray Energy is entitled to appoint a majority of the Board. On March 28, 2017, Chris Cline resigned from the Board and from his role as Principal Strategy Advisor. In connection with the departure of Mr. Cline, Robert D. Moore now serves as Chairman of the Board and Mr. Robert Edward Murray became a member of the Board. Mr. Murray currently serves as the Executive Vice President of Marketing and Sales at Murray Energy. These changes came by way of the amended general partner operating agreement that went into effect upon the exercise of the FEGP Option. Murray Energy Management Services Agreement In April 2015, a management services agreement (“MSA”) was executed between FEGP and Murray American Coal, Inc. (the ”Manager”), a wholly-owned subsidiary of Murray Energy, pursuant to which the Manager provided 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 adjustments. To the extent that FELP or FEGP directly incurs costs for any services covered under the MSA, then the Manager’s quarterly fee is reduced accordingly. Also, to the extent that 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. Upon the exercise of the FEGP Option, the General Partner entered into an amended and restated MSA pursuant to which the quarterly fee for the Manager to provide certain management and administration services to FELP was increased to $5.0 million ($20.0 million on an annual basis) and is subject to future contractual escalations and 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 three months ended June 30, 2017 and 2016 was $3.7 million and $2.5 million, respectively, and was $2.5 million, $3.7 million and $4.6 million for the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to June 30, 2017, and for the six months ended June 30, 2016, respectively. Murray Energy Transport Lease and Overriding Royalty Agreements For the three months ended June 30, 2017 and 2016, we recorded other revenues of $1.8 million and $1.2 million, respectively, under the transport lease (the “Transport Lease”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, and for the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to June 30, 2017, and the six months ended June 30, 2016, we recorded other revenues of $1.6 million, $1.8 million and $3.0 million, respectively. The total remaining minimum payments under the Transport Lease was $88.3 million at June 30, 2017, with unearned income equal to $31.2 million. As of June 30, 2017, the outstanding Transport Lease financing receivable was $57.1 million, of which $2.8 million was classified as current in the condensed consolidated balance sheet. For the three months ended June 30, 2017 and 2016, we recorded other revenues of $0.6 million and $0.5 million, respectively, under the overriding royalty agreement (the “ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company, and for the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to June 30, 2017, and for the six months ended June 30, 2016, we recorded other revenues of $0.8 million, $0.6 million and $1.2 million, respectively. The total remaining minimum payments under the ORRA was $31.1 million at June 30, 2017, with unearned income equal to $19.5 million. As of June 30, 2017, the outstanding ORRA financing receivable was $11.6 million, of which $0.2 million was classified as current in the condensed consolidated balance sheet. Other Murray Energy Transactions During the three months ended June 30, 2017 and 2016, we purchased $3.3 million and $1.3 million, respectively, in equipment, supplies and rebuild services from affiliates of Murray Energy, and for the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to June 30, 2017, and for the six months ended June 30, 2016, we purchased $2.1 million, $3.3 million and $1.7 million, respectively. During the three months ended June 30, 2017 and 2016, we provided $0.1 million and $0.3 million, respectively, in equipment, supplies and rebuild services to affiliates of Murray Energy. We provided equipment, supplies and rebuild services to affiliates of Murray Energy of $0.1 million, $0.1 million and $0.5 million for the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to June 30, 2017, and for the six months ended June 30, 2016, respectively. From time to time, we purchase and sell coal to Murray Energy and its affiliates to, among other things, meet 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 ; and management of Javelin, as our primary outlet for export sales. F During the three months ended June 30, 2017 and 2016, we also paid Javelin $0.4 million and $0 million, respectively, in sales commissions. For the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to June 30, 2017, and for the six months ended June 30, 2016, we paid Javelin commissions of $0.7 million, $0.4 million and $0 million, respectively. During the three months ended June 30, 2017 and 2016, we earned $0.2 million and $0.3 million, respectively, in other revenues for Murray Energy’s usage of our Sitran terminal, and for the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to June 30, 2017, and for the six months ended June 30, 2016, Sitran earned usage fees from Murray Energy of $0.2 million, $0.2 million and $0.8 million, respectively. Murray Energy transports coal under our transportation agreement with a third-party rail company resulting in usage fees owed to the third-party rail company. These usage fees are billed to Murray Energy, resulting in no impact to our condensed consolidated statements of operations. The usage of the railway line with this third-party rail company by Murray Energy counts toward the minimum annual throughput volume requirement with the third-party rail company, thereby reducing the Partnership’s exposure to certain contractual liquidated damage charges. From time to time, we also reimburse Murray Energy for costs paid by them on our behalf, including certain insurance premiums. Reserves Investor Group In connection with the August 2016 debt restructuring transactions, the Reserves Investor Group (as defined below) acquired $179.9 million of 2017 Exchangeable PIK Notes and $15.2 million of the Prior Second Lien Notes. The Reserves Investor Group includes Christopher Cline, the four trusts established for the benefit of Mr. Cline’s children (the “Cline Trust”), 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. As part of the Refinancing Transactions, the Reserves Investor Group’s outstanding principal and accrued and unpaid interest was repaid consistent with the unaffiliated owners of those debt facilities. The Cline Trust acquired $20.0 million of 2023 Second Lien Notes and $10.0 million of the New Term Loan on consistent terms as the unaffiliated owners of these notes Mineral Reserve Leases Our mines have a series of mineral reserve leases with Colt, LLC 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. We also lease mineral reserves under lease agreements with subsidiaries of NRP, including WPP LLC (“WPP”), HOD LLC (“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 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 April 2017, Williamson entered into the eighth amendment to the coal mining lease agreement with WPP which primarily served to, for the remainder of 2017 only, (a) include an overriding royalty payment provision equal to the greater of 5% of the gross selling price of the coal, as defined in the agreement, or $1.56 per ton, and (b) increase the quarterly minimum deficiency payment from $2.0 million to $2.1 million. 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 combustion event, which has required the stoppage of mining operations since March 2015. As a result of the force majeure event, we have not made $61.0 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 12). Sale-Leaseback Financing Arrangements In 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP and leased them back. The gross proceeds from this transaction were $143.5 million. As Macoupin has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. The Macoupin financing arrangement has been adjusted to fair value as part of pushdown accounting which resulted in an adjusted carrying value of $133.2 million as of June 30, 2017 and an effective interest rate of 14.1%. In 2012, Sugar Camp sold certain rail facility assets to HOD and leased them back. The gross proceeds from this transaction were $50.0 million. As Sugar Camp has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. The Sugar Camp financing arrangement has been adjusted to fair value as part of pushdown accounting which resulted in an adjusted carrying value of $67.8 million as of June 30, 2017 and an effective interest rate of 8.2%. Limited Partnership Agreement The general partner 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. Murray Energy and Foresight Reserves have the right to appoint 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. The following table summarizes certain affiliate amounts included in our condensed consolidated balance sheets: (Successor) (Predecessor) Affiliated Company Balance Sheet Location June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Murray Energy and affiliated entities (1) Due from affiliates - current $ 22,631 $ 16,784 NRP and affiliated entities Due from affiliates - current n/a (4) 107 Total $ 22,631 $ 16,891 Murray Energy and affiliated entities Financing receivables - affiliate - current $ 3,019 $ 2,904 Total $ 3,019 $ 2,904 Murray Energy and affiliated entities Due from affiliates - noncurrent $ 947 $ 1,843 Total $ 947 $ 1,843 Murray Energy and affiliated entities Financing receivables - affiliate - noncurrent $ 65,696 $ 67,235 Total $ 65,696 $ 67,235 Foresight Reserves and affiliated entities (2) Prepaid royalties - current and noncurrent $ 1,977 $ 7,599 NRP and affiliated entities (2) Prepaid royalties - current and noncurrent n/a (4) 1,246 Total $ 1,977 $ 8,845 NRP and affiliated entities Sales-leaseback financing arrangements - current and noncurrent n/a (4) $ 191,869 NRP and affiliated entities Accrued interest n/a (4) $ 2,930 Murray Energy and affiliated entities (1) Due to affiliates - current $ 8,000 $ 17,021 Foresight Reserves and affiliated entities (3) Due to affiliates - current 387 1,373 NRP and affiliated entities Due to affiliates - current n/a (4) 2,510 Total $ 8,387 $ 20,904 (1) – Includes amounts due to/from from Javelin, a joint venture partially owned by Murray Energy. (2) – Prepaid royalties with Foresight Reserves and affiliated entities and NRP and affiliated entities is presented net of a reserve of $74,575 and $33,965, respectively, as of December 31, 2016. (3) – As of December 31, 2016, includes amounts due to/from a joint venture partially owned by an affiliate of The Cline Group. On March 31, 2017, The Cline Group sold its interest in the joint venture to the unaffiliated member therefore this joint venture will not be an affiliated party prospectively. (4) – As a result of Chris Cline’s affiliate selling its interest in NRP’s general partner on May 8, 2017, NRP is no longer considered to be an affiliate of FELP. A summary of certain expenditures and expenses (revenues) incurred with affiliated entities is as follows for the three months ended June 30, 2017 and 2016, the period from January 1, 2017 to March 31, 2017, the period from April 1, 2017 to June 30, 2017 and the six months ended June 30, 2016 (in thousands): (Successor) (Predecessor) (Successor) (Predecessor) (Predecessor) Three Months Ended June 30, 2017 Three Months Ended June 30, 2016 Period from April 1, 2017 to June 30, 2017 Period from January 1, 2017 to March 31, 2017 Six Months Ended June 30, 2016 Coal sales – Murray Energy and affiliated entities (including Javelin) (1) $ (40,310 ) $ — $ (40,310 ) $ (60,749 ) $ 30 Overriding royalty and lease revenues – Murray Energy and affiliated entities (2) $ (2,412 ) $ (1,645 ) $ (2,412 ) $ (2,355 ) $ (4,115 ) Terminal revenues - Murray Energy and affiliated entities (2) $ (166 ) $ (262 ) $ (166 ) $ (226 ) $ (780 ) Royalty expense – (3) $ 710 $ 4,442 $ 710 $ 3,669 $ 7,286 Royalty expense – Foresight Reserves and affiliated entities (3) $ 6,735 $ 3,710 $ 6,735 $ 1,521 $ 7,157 Loadout services – NRP and affiliated entities (3) $ 746 $ 1,937 $ 746 $ 2,134 $ 3,660 Purchased goods and services – Murray Energy and affiliated entities (4) $ 3,274 $ 1,308 $ 3,274 $ 2,061 $ 1,700 Purchased coal - Murray Energy and affiliated entities (5) $ — $ — $ — $ 7,973 $ 551 Sales commissions - Murray Energy and affiliated entities (including Javelin) (6) $ 367 $ — $ 367 $ 692 $ — Management services, net – Murray Energy and affiliated entities (6) $ 3,713 $ 2,491 $ 3,713 $ 2,547 $ 4,570 Sales-leaseback interest expense - NRP and affiliated entities (7) $ 2,012 $ 6,540 $ 2,012 $ 6,244 $ 12,403 Principal location in the condensed 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 and development, net, as applicable (5) – Cost of coal purchased (6) – Selling, general and administrative (7) – Interest expense, net For the three months ended June 30, 2017, transactions with NRP and affiliated are only included in the table above through April 30, 2017 as a result of NRP no longer being an affiliate subsequent to Chris Cline’s affiliate selling its interest in NRP’s general partner on May 8, 2017. We also purchased $3.0 million in mining supplies from an affiliated joint venture under a supply agreement during the period from January 1, 2017 to March 31, 2017 and $1.0 million and $3.2 million during the three and six months ended June 30, 2016, respectively. This joint venture was no longer an affiliate subsequent to March 31, 2017.

Earnings per Limited Partner Un

Earnings per Limited Partner Unit	6 Months Ended
	Jun. 30, 2017
Earnings Per Share [Abstract]
Earnings per Limited Partner Unit	10. Earnings per Limited Partner Unit Limited partners’ interest in net income (loss) attributable to the Partnership and basic and diluted earnings per unit reflect net income (loss) attributable to the Partnership. We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in ASC 260, Earnings Per Share The Partnership’s net income (loss) is allocated to the limited partners, including the holders of the subordinated units, in accordance with the partnership agreement on 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 holders of our incentive distribution rights (“IDR”) have the right to receive increasing percentages of quarterly distributions from operating surplus after certain distribution levels defined in the partnership agreement have been achieved. The general partner has no obligation to make distributions; therefore, undistributed earnings of the Partnership are not allocated to the IDR holder. 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 per common and subordinated unit for the three month periods indicated: (Successor) (Predecessor) Three Months Ended June 30, Three Months Ended June 30, 2017 2016 Common Units Subordinated Units Total Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Net loss available to limited partner units $ (8,790 ) $ (7,487 ) $ (16,277 ) $ (13,995 ) $ (13,791 ) $ (27,786 ) Denominator: Weighted-average units to calculate basic EPU 76,270 64,955 141,225 65,917 64,955 130,872 Less: effect of dilutive securities (1) — — — — — — Weighted-average units to calculate diluted EPU 76,270 64,955 141,225 65,917 64,955 130,872 Basic net loss per unit $ (0.12 ) $ (0.12 ) $ (0.12 ) $ (0.21 ) $ (0.21 ) $ (0.21 ) Diluted net loss per unit $ (0.12 ) $ (0.12 ) $ (0.12 ) $ (0.21 ) $ (0.21 ) $ (0.21 ) (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 three months ended June 30, 2017 and 2016, approximately 0.3 million and 0.2 million phantom units, respectively, were anti-dilutive, and therefore excluded from the diluted EPU calculation. Diluted EPU also is not impacted during the current period by the 384,124 Warrants outstanding as of June 30, 2017, which are convertible into common units at an exchange rate of approximately 12.8 common units of FELP at an initial exercise price of $0.8928 per common unit, in each case subject to adjustment (see Note 11). The following table illustrates the Partnership’s calculation of net loss per common and subordinated unit for the period from January 1, 2017 to March 31, 2017, from the period from April 1, 2017 to June 30, 2017 and for the six months ended June 30, 2016: (Predecessor) (Successor) Period from January 1, 2017 to March 31, 2017 Period from April 1, 2017 to June 30, 2017 Common Units Subordinated Units Total Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Net loss available to limited partner units $ (56,259 ) $ (54,925 ) $ (111,184 ) $ (8,790 ) $ (7,487 ) $ (16,277 ) Denominator: Weighted-average units to calculate basic EPU 66,533 64,955 131,488 76,270 64,955 141,225 Less: effect of dilutive securities (1) — — — — — — Weighted-average units to calculate diluted EPU 66,533 64,955 131,488 76,270 64,955 141,225 Basic net loss per unit $ (0.85 ) $ (0.85 ) $ (0.85 ) $ (0.12 ) $ (0.12 ) $ (0.12 ) Diluted net loss per unit $ (0.85 ) $ (0.85 ) $ (0.85 ) $ (0.12 ) $ (0.12 ) $ (0.12 ) (Predecessor) Six Months Ended June 30, 2016 Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Net loss available to limited partner units $ (34,886 ) $ (34,605 ) $ (69,491 ) Denominator: Weighted-average units to calculate basic EPU 65,555 64,955 130,510 Less: effect of dilutive securities (1) — — — Weighted-average units to calculate diluted EPU 65,555 64,955 130,510 Basic net loss per unit $ (0.53 ) $ (0.53 ) $ (0.53 ) Diluted net loss per unit $ (0.53 ) $ (0.53 ) $ (0.53 ) (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 period from January 1, 2017 to March 31, 2017 and for the period from April 1, 2017 to June 30, 2017, approximately 0.3 million phantom units were anti-dilutive and therefore excluded from the diluted EPU calculation. For the six months ended June 30, 2016, approximately 0.2 million phantom units were anti-dilutive and therefore excluded from the diluted EPU calculation. Diluted EPU also is not impacted during the current year period by the 384,124 Warrants outstanding as of June 30, 2017, which are convertible into common units at an exchange rate of approximately 12.8 common units of FELP at an initial exercise price of $0.8928 per common unit, in each case subject to adjustment (see Note 11).

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	11. Fair Value of Financial Instruments The table below sets forth, by level, the Partnership’s net financial assets and liabilities for which fair value is measured on a recurring basis: (Successor) Fair Value at June 30, 2017 Total Level 1 Level 2 Level 3 (In Thousands) Coal derivative contracts $ 1,318 $ — $ 1,318 $ — Total $ 1,318 $ — $ 1,318 $ — (Predecessor) 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 ) The Partnership’s commodity derivative contracts are valued based on direct broker quotes and corroborated with market pricing data. 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 condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016, are as follows: (Successor) Fair Value at June 30, 2017 Current – Long-Term – Coal Derivative Assets Accrued Expenses Other Long-Term Liabilities (In Thousands) Coal derivative contracts $ 1,318 $ — $ — $ — Total $ 1,318 $ — $ — $ — (Predecessor) 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 ) During the periods presented in these interim condensed consolidated financial statements, there were no assets or liabilities that were transferred between Level 1 and Level 2. 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): (Predecessor) Warrant Liability (In Thousands) Balance at January 1, 2017 $ 51,169 Purchases, issuances and settlements — Recorded fair value losses Included in earnings - gain (9,281) Reclassification of fair value to partners’ capital (41,888) Balance at March 31, 2017 $ — In August 2016, FELP issued 516,875 warrants (the “Warrants”) to the unaffiliated owners of the Prior 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 of the 2017 Exchangeable PIK Notes (“the 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. On the Closing Date, as a result of the Refinancing Transactions, the Warrants have become exercisable by the holders thereof at an exchange rate of approximately 12.8 common units of FELP at an initial exercise price of $0.8928 per common unit, in each case subject to adjustment. Upon their issuance, the Warrants were recorded as a liability at fair value and remeasured to fair value at each balance sheet date. The resulting non-cash gain or loss on remeasurements was recorded as a non-operating loss in our consolidated statements of operations. The fair value of the Warrants was calculated using the Black-Scholes pricing model 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 2.39% were used as assumptions in the Black-Scholes pricing model. Upon the Note Redemption on the Closing Date, the establishment of a fixed exchange rate for the conversion of the Warrants to a number of common units resulted in the warrant liability being reclassified to partners’ capital, and therefore, were not remeasured at fair value after the Closing Date. As of June 30, 2017, there are 384,124 Warrants outstanding and exercisable into common units of FELP. Long-Term Debt The fair value of long-term debt as of June 30, 2017 and December 31, 2016 was $1,278.1 million and $1,378.6 million, respectively. The fair value of long-term debt was calculated based on the credit-adjusted borrowing rate for similar debt instruments with comparable terms.

Contingencies

Contingencies	6 Months Ended
	Jun. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
Contingencies	12. Contingencies 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 June 30, 2017, we have not made $61.0 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 (collectively, the “Foresight 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. 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 June 30, 2017, we had no accruals for 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. In May 2017, we received an additional $12.8 million payment from the insurance companies which was recorded to other operating income (expense) in the condensed consolidated statement of operations. We continue to pursue additional remedies under our insurance policies; 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 $84.5 million as of June 30, 2017 to secure reclamation and other performance commitments, which are partially secured by $4.5 million of our outstanding letters of credit.

Subsequent Event

Subsequent Event	6 Months Ended
	Jun. 30, 2017
Subsequent Events [Abstract]
Subsequent Event	13. Subsequent Event On August 11, 2017, we announced a cash distribution of $0.0647 per unit payable to common unitholders. The distribution is payable on August 31, 2017, for common unitholders of record on August 21, 2017.

New Accounting Standards (Polic

New Accounting Standards (Policies)	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
New Accounting Standards	In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation, In July 2015, the FASB issued ASU 2015-11, Inventory: Simplifying the Measurement of Inventory In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers , We are in the process of reviewing the various terms and clauses within our coal sales contracts and

Pushdown Accounting (Tables)

Pushdown Accounting (Tables)	6 Months Ended
	Jun. 30, 2017
Pushdown Accounting [Abstract]
Summary of Net Preliminary Purchase Accounting Adjustments from Carrying Value	The preliminary net purchase accounting adjustments to record the assets and liabilities of FELP to fair value as of the Acquisition Date resulted in a $1.1 billion net increase to net assets, and was comprised of the following preliminary adjustments from carrying value as of the Acquisition Date (in thousands): Working capital and certain other long-term asset accounts (1) $ (48,503 ) Mineral rights, land and land rights (2) 1,533,171 Plant, equipment and development (2) (261,739 ) Contract-based intangibles, net (92,029 ) Deferred debt issuance costs (33,879 ) Sales-leaseback financing arrangements (9,267 ) Long-term liabilities, net (1) (36,302 ) Pushdown accounting adjustment $ 1,051,452 (1) – Accrued expenses and other current liabilities and other long-term liabilities include liabilities of $16.9 million and $38.9 million, respectively, for certain royalty and transportation executory contracts under which we have contractual future minimum required payments but we do not expect to receive any future economic benefits. (2) – The development costs of the mine were reduced to zero as part of the fair value adjustment and the corresponding value of mineral rights assets were increased to reflect the future cash flows that the developed mines are expected to generate. As a result, the value of the plant, equipment and development asset category decreased significantly and the value of the mineral rights category increased significantly.
Summary of Each Major Class of Intangible Assets Preliminarily Identified	The following table presents each major class of intangible assets preliminarily identified as of the Acquisition Date (in thousands): Favorable sales contracts, net $ 20,770 Unfavorable royalty agreements (112,799 ) Total contract-based intangibles, net $ (92,029 )

Accounts Receivable (Tables)

Accounts Receivable (Tables)	6 Months Ended
	Jun. 30, 2017
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Trade accounts receivable $ 25,968 $ 42,862 Other receivables 7,406 12,043 Total accounts receivable $ 33,374 $ 54,905

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2017
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Parts and supplies $ 17,872 $ 18,712 Raw coal 8,191 4,907 Clean coal 45,927 19,433 Total inventories $ 71,990 $ 43,052

Property, Plant, Equipment an24

Property, Plant, Equipment and Development, Net (Tables)	6 Months Ended
	Jun. 30, 2017
Property Plant And Equipment [Abstract]
Schedule of Property, Plant, Equipment and Development, Net	Property, plant, equipment and development, net consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Mineral rights, land and land rights $ 1,630,038 $ 99,909 Plant, equipment and development 960,580 2,318,697 Total property, plant, equipment and development 2,590,618 2,418,606 Less: accumulated depreciation, depletion and amortization (56,685 ) (1,099,669 ) Property, plant, equipment and development, net $ 2,533,933 $ 1,318,937 In conjunction with pushdown accounting, property, plant, equipment and development was measured at fair value as of the Acquisition Date, which also impacted how value was assigned between the categories within property, plant, equipment and development (see Note 3).

Long-Term Debt and Capital Le25

Long-Term Debt and Capital Lease Obligations (Tables)	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Schedule of Long-Term Debt and Capital Lease Obligations	Long-term debt and capital lease obligations consist of the following: (Successor) (Predecessor) June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Prior Second Lien Notes $ — $ 349,100 2017 Exchangeable PIK Notes — 299,859 Prior Revolving Credit Facility ($450.0 million capacity) — 352,500 Prior Term Loan due 2020 — 295,667 2023 Second Lien Notes 425,000 — New Term Loan due 2022 822,938 — Revolving Credit Facility ($170.0 million capacity) — — Trade A/R Securitization 21,100 14,200 5.78% longwall financing arrangement 33,615 39,217 5.555% longwall financing arrangement 36,094 41,250 Capital lease obligations 32,177 41,457 Subtotal - Total long-term debt and capital lease obligations principal outstanding 1,370,924 1,433,250 Unamortized deferred financing costs and debt discounts (14,907 ) (42,187 ) Total long-term debt and capital lease obligations 1,356,017 1,391,063 Less: current portion (69,635 ) (368,993 ) Non-current portion of long-term debt and capital lease obligations $ 1,286,382 $ 1,022,070

Related-Party Transactions (Tab

Related-Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2017
Related Party Transactions [Abstract]
Summary of Certain Affiliate Amounts Included in Condensed Consolidated Balance Sheets	The following table summarizes certain affiliate amounts included in our condensed consolidated balance sheets: (Successor) (Predecessor) Affiliated Company Balance Sheet Location June 30, 2017 December 31, 2016 (In Thousands) (In Thousands) Murray Energy and affiliated entities (1) Due from affiliates - current $ 22,631 $ 16,784 NRP and affiliated entities Due from affiliates - current n/a (4) 107 Total $ 22,631 $ 16,891 Murray Energy and affiliated entities Financing receivables - affiliate - current $ 3,019 $ 2,904 Total $ 3,019 $ 2,904 Murray Energy and affiliated entities Due from affiliates - noncurrent $ 947 $ 1,843 Total $ 947 $ 1,843 Murray Energy and affiliated entities Financing receivables - affiliate - noncurrent $ 65,696 $ 67,235 Total $ 65,696 $ 67,235 Foresight Reserves and affiliated entities (2) Prepaid royalties - current and noncurrent $ 1,977 $ 7,599 NRP and affiliated entities (2) Prepaid royalties - current and noncurrent n/a (4) 1,246 Total $ 1,977 $ 8,845 NRP and affiliated entities Sales-leaseback financing arrangements - current and noncurrent n/a (4) $ 191,869 NRP and affiliated entities Accrued interest n/a (4) $ 2,930 Murray Energy and affiliated entities (1) Due to affiliates - current $ 8,000 $ 17,021 Foresight Reserves and affiliated entities (3) Due to affiliates - current 387 1,373 NRP and affiliated entities Due to affiliates - current n/a (4) 2,510 Total $ 8,387 $ 20,904 (1) – Includes amounts due to/from from Javelin, a joint venture partially owned by Murray Energy. (2) – Prepaid royalties with Foresight Reserves and affiliated entities and NRP and affiliated entities is presented net of a reserve of $74,575 and $33,965, respectively, as of December 31, 2016. (3) – As of December 31, 2016, includes amounts due to/from a joint venture partially owned by an affiliate of The Cline Group. On March 31, 2017, The Cline Group sold its interest in the joint venture to the unaffiliated member therefore this joint venture will not be an affiliated party prospectively. (4) – As a result of Chris Cline’s affiliate selling its interest in NRP’s general partner on May 8, 2017, NRP is no longer considered to be an affiliate of FELP.
Summary of Certain Expenditures and Expenses (Revenues) Incurred With Affiliated Entities	A summary of certain expenditures and expenses (revenues) incurred with affiliated entities is as follows for the three months ended June 30, 2017 and 2016, the period from January 1, 2017 to March 31, 2017, the period from April 1, 2017 to June 30, 2017 and the six months ended June 30, 2016 (in thousands): (Successor) (Predecessor) (Successor) (Predecessor) (Predecessor) Three Months Ended June 30, 2017 Three Months Ended June 30, 2016 Period from April 1, 2017 to June 30, 2017 Period from January 1, 2017 to March 31, 2017 Six Months Ended June 30, 2016 Coal sales – Murray Energy and affiliated entities (including Javelin) (1) $ (40,310 ) $ — $ (40,310 ) $ (60,749 ) $ 30 Overriding royalty and lease revenues – Murray Energy and affiliated entities (2) $ (2,412 ) $ (1,645 ) $ (2,412 ) $ (2,355 ) $ (4,115 ) Terminal revenues - Murray Energy and affiliated entities (2) $ (166 ) $ (262 ) $ (166 ) $ (226 ) $ (780 ) Royalty expense – (3) $ 710 $ 4,442 $ 710 $ 3,669 $ 7,286 Royalty expense – Foresight Reserves and affiliated entities (3) $ 6,735 $ 3,710 $ 6,735 $ 1,521 $ 7,157 Loadout services – NRP and affiliated entities (3) $ 746 $ 1,937 $ 746 $ 2,134 $ 3,660 Purchased goods and services – Murray Energy and affiliated entities (4) $ 3,274 $ 1,308 $ 3,274 $ 2,061 $ 1,700 Purchased coal - Murray Energy and affiliated entities (5) $ — $ — $ — $ 7,973 $ 551 Sales commissions - Murray Energy and affiliated entities (including Javelin) (6) $ 367 $ — $ 367 $ 692 $ — Management services, net – Murray Energy and affiliated entities (6) $ 3,713 $ 2,491 $ 3,713 $ 2,547 $ 4,570 Sales-leaseback interest expense - NRP and affiliated entities (7) $ 2,012 $ 6,540 $ 2,012 $ 6,244 $ 12,403 Principal location in the condensed 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 and development, net, as applicable (5) – Cost of coal purchased (6) – Selling, general and administrative (7) – Interest expense, net

Earnings per Limited Partner 27

Earnings per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 2017
Earnings Per Share [Abstract]
Summary of Partnership's Calculation of Net Loss per Common and Subordinated Unit	The following table illustrates the Partnership’s calculation of net loss per common and subordinated unit for the three month periods indicated: (Successor) (Predecessor) Three Months Ended June 30, Three Months Ended June 30, 2017 2016 Common Units Subordinated Units Total Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Net loss available to limited partner units $ (8,790 ) $ (7,487 ) $ (16,277 ) $ (13,995 ) $ (13,791 ) $ (27,786 ) Denominator: Weighted-average units to calculate basic EPU 76,270 64,955 141,225 65,917 64,955 130,872 Less: effect of dilutive securities (1) — — — — — — Weighted-average units to calculate diluted EPU 76,270 64,955 141,225 65,917 64,955 130,872 Basic net loss per unit $ (0.12 ) $ (0.12 ) $ (0.12 ) $ (0.21 ) $ (0.21 ) $ (0.21 ) Diluted net loss per unit $ (0.12 ) $ (0.12 ) $ (0.12 ) $ (0.21 ) $ (0.21 ) $ (0.21 ) (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 three months ended June 30, 2017 and 2016, approximately 0.3 million and 0.2 million phantom units, respectively, were anti-dilutive, and therefore excluded from the diluted EPU calculation. Diluted EPU also is not impacted during the current period by the 384,124 Warrants outstanding as of June 30, 2017, which are convertible into common units at an exchange rate of approximately 12.8 common units of FELP at an initial exercise price of $0.8928 per common unit, in each case subject to adjustment (see Note 11). The following table illustrates the Partnership’s calculation of net loss per common and subordinated unit for the period from January 1, 2017 to March 31, 2017, from the period from April 1, 2017 to June 30, 2017 and for the six months ended June 30, 2016: (Predecessor) (Successor) Period from January 1, 2017 to March 31, 2017 Period from April 1, 2017 to June 30, 2017 Common Units Subordinated Units Total Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Net loss available to limited partner units $ (56,259 ) $ (54,925 ) $ (111,184 ) $ (8,790 ) $ (7,487 ) $ (16,277 ) Denominator: Weighted-average units to calculate basic EPU 66,533 64,955 131,488 76,270 64,955 141,225 Less: effect of dilutive securities (1) — — — — — — Weighted-average units to calculate diluted EPU 66,533 64,955 131,488 76,270 64,955 141,225 Basic net loss per unit $ (0.85 ) $ (0.85 ) $ (0.85 ) $ (0.12 ) $ (0.12 ) $ (0.12 ) Diluted net loss per unit $ (0.85 ) $ (0.85 ) $ (0.85 ) $ (0.12 ) $ (0.12 ) $ (0.12 ) (Predecessor) Six Months Ended June 30, 2016 Common Units Subordinated Units Total (In Thousands, Except Per Unit Data) Numerator: Net loss available to limited partner units $ (34,886 ) $ (34,605 ) $ (69,491 ) Denominator: Weighted-average units to calculate basic EPU 65,555 64,955 130,510 Less: effect of dilutive securities (1) — — — Weighted-average units to calculate diluted EPU 65,555 64,955 130,510 Basic net loss per unit $ (0.53 ) $ (0.53 ) $ (0.53 ) Diluted net loss per unit $ (0.53 ) $ (0.53 ) $ (0.53 ) (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 period from January 1, 2017 to March 31, 2017 and for the period from April 1, 2017 to June 30, 2017, approximately 0.3 million phantom units were anti-dilutive and therefore excluded from the diluted EPU calculation. For the six months ended June 30, 2016, approximately 0.2 million phantom units were anti-dilutive and therefore excluded from the diluted EPU calculation. Diluted EPU also is not impacted during the current year period by the 384,124 Warrants outstanding as of June 30, 2017, which are convertible into common units at an exchange rate of approximately 12.8 common units of FELP at an initial exercise price of $0.8928 per common unit, in each case subject to adjustment (see Note 11).

Fair Value of Financial Instr28

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value of Net Financial Assets and Liabilities Measured on Recurring Basis	The table below sets forth, by level, the Partnership’s net financial assets and liabilities for which fair value is measured on a recurring basis: (Successor) Fair Value at June 30, 2017 Total Level 1 Level 2 Level 3 (In Thousands) Coal derivative contracts $ 1,318 $ — $ 1,318 $ — Total $ 1,318 $ — $ 1,318 $ — (Predecessor) 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 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 condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016, are as follows: (Successor) Fair Value at June 30, 2017 Current – Long-Term – Coal Derivative Assets Accrued Expenses Other Long-Term Liabilities (In Thousands) Coal derivative contracts $ 1,318 $ — $ — $ — Total $ 1,318 $ — $ — $ — (Predecessor) 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 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): (Predecessor) Warrant Liability (In Thousands) Balance at January 1, 2017 $ 51,169 Purchases, issuances and settlements — Recorded fair value losses Included in earnings - gain (9,281) Reclassification of fair value to partners’ capital (41,888) Balance at March 31, 2017 $ —

Organization, Nature of Busin29

Organization, Nature of Business and Basis of Presentation - Additional Information (Details) $ in Millions	Mar. 28, 2017USD ($)	Jun. 23, 2014	Jun. 30, 2017segmentMiningComplex	Apr. 30, 2015	Apr. 16, 2015
Schedule Of Organization Nature Of Business 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 Nature Of Business And Basis Of Presentation [Line Items]
Percentage of outstanding limited partner units issued				50.00%	50.00%
Foresight Energy GP Limited Liability Company | Murray Energy Transaction
Schedule Of Organization Nature Of Business And Basis Of Presentation [Line Items]
Percentage of voting interests acquired	80.00%			34.00%	34.00%
Additional voting interests acquired through exercise of option, percentage	46.00%
Aggregate exercise price of option | $	$ 15
Foresight Energy LLC | Foresight Reserves, LP
Schedule Of Organization Nature Of Business And Basis Of Presentation [Line Items]
Ownership percentage prior		99.333%
Foresight Energy LLC | Member of Management
Schedule Of Organization Nature Of Business And Basis Of Presentation [Line Items]
Ownership percentage prior		0.667%

Pushdown Accounting - Additiona

Pushdown Accounting - Additional Information (Details) $ in Thousands	Mar. 31, 2017USD ($)
Preliminary Purchase Accounting Adjustments [Line Items]
Purchase accounting adjustments, net increase to net assets	$ 1,051,452
Unfavorable royalty agreement liabilities, weighted average amortization period	17 years 2 months 12 days
Maximum
Preliminary Purchase Accounting Adjustments [Line Items]
Preliminary allocation and related push down accounting finalization period, from the acquisition date	1 year
Discount rates	15.50%
Minimum
Preliminary Purchase Accounting Adjustments [Line Items]
Discount rates	11.50%

Pushdown Accounting - Summary o

Pushdown Accounting - Summary of Net Preliminary Purchase Accounting Adjustments from Carrying Value (Details) $ in Thousands	Mar. 31, 2017USD ($)
Preliminary Purchase Accounting Adjustments [Line Items]
Working capital and certain other long-term asset accounts	$ (48,503)	[1]
Contract-based intangibles, net	(92,029)
Deferred debt issuance costs	(33,879)
Sales-leaseback financing arrangements	(9,267)
Long-term liabilities, net	(36,302)	[1]
Pushdown accounting adjustment	1,051,452
Mineral Rights, Land and Land Rights
Preliminary Purchase Accounting Adjustments [Line Items]
Property, plant, equipment and development	1,533,171	[2]
Plant, Equipment and Development
Preliminary Purchase Accounting Adjustments [Line Items]
Property, plant, equipment and development	$ (261,739)	[2]
[1]	Accrued expenses and other current liabilities and other long-term liabilities include liabilities of $16.9 million and $38.9 million, respectively, for certain royalty and transportation executory contracts under which we have contractual future minimum required payments but we do not expect to receive any future economic benefits.
[2]	The development costs of the mine were reduced to zero as part of the fair value adjustment and the corresponding value of mineral rights assets were increased to reflect the future cash flows that the developed mines are expected to generate. As a result, the value of the plant, equipment and development asset category decreased significantly and the value of the mineral rights category increased significantly.

Pushdown Accounting - Summary32

Pushdown Accounting - Summary of Net Preliminary Purchase Accounting Adjustments from Carrying Value (Parenthetical) (Details) $ in Thousands	Mar. 31, 2017USD ($)
Royalty and Transportation Executory Contracts
Preliminary Purchase Accounting Adjustments [Line Items]
Accrued expenses and other current liabilities	$ 16,900
Other long-term liabilities	38,900
Mine Development
Preliminary Purchase Accounting Adjustments [Line Items]
Development costs of mine	$ 0

Pushdown Accounting - Summary33

Pushdown Accounting - Summary of Each Major Class of Intangible Assets Preliminarily Identified (Details) $ in Thousands	Mar. 31, 2017USD ($)
Finite Lived Intangible Assets [Line Items]
Contract-based intangibles, net	$ (92,029)
Favorable Sales Contracts, Net
Finite Lived Intangible Assets [Line Items]
Contract-based intangibles, net	20,770
Unfavorable Royalty Agreements
Finite Lived Intangible Assets [Line Items]
Contract-based intangibles, net	$ (112,799)

Commodity Derivative Contracts

Commodity Derivative Contracts - Additional Information (Details) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2017USD ($)	Jun. 30, 2017T	Dec. 31, 2016T
Predecessor
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Settlement of certain commodity derivative contracts | $	$ 3,520
Swap Agreements | Coal Derivative Contract
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount, Mass | T		100,000	500,000

Accounts Receivable - Schedule

Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Accounts Notes And Loans Receivable [Line Items]
Trade accounts receivable	$ 25,968
Other receivables	7,406
Total accounts receivable	$ 33,374
Predecessor
Accounts Notes And Loans Receivable [Line Items]
Trade accounts receivable		$ 42,862
Other receivables		12,043
Total accounts receivable		$ 54,905

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Inventory [Line Items]
Parts and supplies	$ 17,872
Total inventories	71,990
Predecessor
Inventory [Line Items]
Parts and supplies		$ 18,712
Total inventories		43,052
Raw coal
Inventory [Line Items]
Coal	8,191
Raw coal | Predecessor
Inventory [Line Items]
Coal		4,907
Clean coal
Inventory [Line Items]
Coal	$ 45,927
Clean coal | Predecessor
Inventory [Line Items]
Coal		$ 19,433

Property, Plant, Equipment an37

Property, Plant, Equipment and Development, Net (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Mineral rights, land and land rights	$ 1,630,038
Plant, equipment and development	960,580
Total property, plant, equipment and development	2,590,618
Less: accumulated depreciation, depletion and amortization	(56,685)
Property, plant, equipment and development, net	$ 2,533,933
Predecessor
Property Plant And Equipment [Line Items]
Mineral rights, land and land rights		$ 99,909
Plant, equipment and development		2,318,697
Total property, plant, equipment and development		2,418,606
Less: accumulated depreciation, depletion and amortization		(1,099,669)
Property, plant, equipment and development, net		$ 1,318,937

Long-Term Debt and Capital Le38

Long-Term Debt and Capital Lease Obligations (Details) - USD ($)	Jun. 30, 2017	Mar. 28, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 1,370,924,000
Capital lease obligations	32,177,000
Unamortized deferred financing costs and debt discounts	(14,907,000)
Total long-term debt and capital lease obligations	1,356,017,000
Less: current portion	(69,635,000)
Long-term debt and capital lease obligations	1,286,382,000
2023 Second Lien Notes
Debt Instrument [Line Items]
Long-term debt	425,000,000
New Term Loan due 2022
Debt Instrument [Line Items]
Long-term debt	822,938,000	$ 825,000,000
Trade A/R Securitization
Debt Instrument [Line Items]
Long-term debt	21,100,000
5.78% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt	33,615,000
5.555% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt	36,094,000
Predecessor
Debt Instrument [Line Items]
Long-term debt			$ 1,433,250,000
Capital lease obligations			41,457,000
Unamortized deferred financing costs and debt discounts			(42,187,000)
Total long-term debt and capital lease obligations			1,391,063,000
Less: current portion			(368,993,000)
Long-term debt and capital lease obligations			1,022,070,000
Predecessor | Prior Second Lien Notes
Debt Instrument [Line Items]
Long-term debt			349,100,000
Predecessor | 2017 Exchangeable PIK Notes
Debt Instrument [Line Items]
Long-term debt			299,859,000
Predecessor | Prior Term Loan due 2020
Debt Instrument [Line Items]
Long-term debt			295,667,000
Predecessor | Trade A/R Securitization
Debt Instrument [Line Items]
Long-term debt			14,200,000
Predecessor | 5.78% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt			39,217,000
Predecessor | 5.555% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt			41,250,000
Prior Revolving Credit Facility ($450.0 Million capacity) | Predecessor
Debt Instrument [Line Items]
Revolving Credit Facility			$ 352,500,000
Revolving Credit Facility ($170.0 Million capacity)
Debt Instrument [Line Items]
Revolving Credit Facility	$ 0

Long-Term Debt and Capital Le39

Long-Term Debt and Capital Lease Obligations (Parenthetical) (Details) - USD ($)	Mar. 28, 2017	Jun. 30, 2017	Dec. 31, 2016
2017 Exchangeable PIK Notes
Debt Instrument [Line Items]
Debt instrument maturity year			2,017
Prior Term Loan due 2020
Debt Instrument [Line Items]
Debt instrument maturity year			2,020
New Term Loan due 2022
Debt Instrument [Line Items]
Debt instrument maturity year		2,022
2023 Second Lien Notes
Debt Instrument [Line Items]
Debt instrument maturity year	2,023	2,023
Debt instrument interest percentage	11.50%
5.78% longwall financing arrangement
Debt Instrument [Line Items]
Debt instrument interest percentage		5.78%	5.78%
5.555% longwall financing arrangement
Debt Instrument [Line Items]
Debt instrument interest percentage		5.555%	5.555%
Prior Revolving Credit Facility ($450.0 Million capacity)
Debt Instrument [Line Items]
Maximum borrowings capacity under credit facility			$ 450,000,000
Revolving Credit Facility ($170.0 Million capacity)
Debt Instrument [Line Items]
Maximum borrowings capacity under credit facility	$ 170,000,000	$ 170,000,000

Long-Term Debt and Capital Le40

Long-Term Debt and Capital Lease Obligations - Murray Investment - Additional Information (Details) shares in Millions, $ in Millions	Mar. 27, 2017USD ($)shares
Debt Instrument [Line Items]
Proceeds from common unit issuance to Murray Energy (affiliate)	$ 60.6
Issuance of common units (in units) | shares	9.6
2021 Second Lien Notes
Debt Instrument [Line Items]
Amount of debt redeemed	$ 54.5
Debt instrument maturity year	2,021
Debt instrument redemption percentage	110.00%

Long-Term Debt and Capital Le41

Long-Term Debt and Capital Lease Obligations - Refinancing Transactions - New Debt Issued - Additional Information (Details) - USD ($)	Mar. 28, 2017	Jun. 30, 2017	Jun. 30, 2017
Debt Instrument [Line Items]
Long-term debt		$ 1,370,924,000	$ 1,370,924,000
Deferred third party professional fees		27,300,000
2023 Second Lien Notes
Debt Instrument [Line Items]
Debt instrument aggregate principal amount	$ 425,000,000
Debt instrument maturity year	2,023		2,023
Long-term debt		425,000,000	$ 425,000,000
New Term Loan due 2022
Debt Instrument [Line Items]
Debt instrument maturity year			2,022
Long-term debt	$ 825,000,000	822,938,000	$ 822,938,000
Debt Instrument maturity period	5 years
Revolving Credit Facility ($170.0 Million capacity)
Debt Instrument [Line Items]
Debt Instrument maturity period	4 years
Maximum borrowings capacity under credit facility	$ 170,000,000	$ 170,000,000	$ 170,000,000
Credit facility maturity period	4 years

Long-Term Debt and Capital Le42

Long-Term Debt and Capital Lease Obligations - Refinancing Transactions - Retired Indebtedness - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2017	Mar. 31, 2017
Debt Instrument [Line Items]
Debt instrument, redemption, description	 the remaining Prior Second Lien Notes at a redemption price equal to the principal amount thereof plus the applicable premium as of, and accrued and unpaid interest;  the Second Lien Senior Secured Exchangeable PIK Notes due 2017 (the “2017 Exchangeable PIK Notes”) at a redemption price equal to the principal amount thereof, plus accrued and unpaid interest; and  the Partnership’s outstanding credit facilities (the “Prior Credit Facilities”), including the revolving credit facility (the “Prior Revolving Credit Facility”) and the term loan (the “Prior Term Loan”), including, in each case, accrued and unpaid interest.
Loss on early extinguishment of debt		$ 95.5
Prior Second Lien Notes
Debt Instrument [Line Items]
Make-whole/equity-claw premiums and other cash costs to early retire notes		57.6
Write-off of unamortized debt discounts and debt issuance costs		$ 37.9

Long-Term Debt and Capital Le43

Long-Term Debt and Capital Lease Obligations - New Credit Facilities - Additional Information (Details) - USD ($)	Mar. 28, 2017	Mar. 31, 2021	Mar. 31, 2019	Jun. 30, 2017	Jun. 30, 2017
Debt Instrument [Line Items]
Long-term debt				$ 1,370,924,000	$ 1,370,924,000
New Credit Facilities
Debt Instrument [Line Items]
Percentage of amortization on original principal amount					1.00%
Percentage of prepayment of outstanding borrowings based on annual excess cash flow					75.00%
Reduction in percentage of prepayment of outstanding borrowings based on annual excess cash flow upon satisfaction of specified net secured leverage ratio test					50.00%
Reduction in percentage of prepayment of outstanding borrowings based on annual excess cash flow upon satisfaction of specified net secured leverage ratio tests two					25.00%
Reduction of prepayment of outstanding borrowings based on annual excess cash flow upon satisfaction of specified net secured leverage ratio tests three					0.00%
Percentage of prepayment of outstanding borrowings based on net cash proceeds of non-ordinary course asset sales and other dispositions of property					100.00%
Percentage of prepayment of outstanding borrowings based on net cash proceeds of insurance (other than insurance proceeds relating to the Deer Run mine)					100.00%
Percentage of prepayment of outstanding borrowings based on net cash proceeds of any issuance or incurrence of debt, other than proceeds from debt permitted under the New Credit Facilities					100.00%
Maximum required first lien secured leverage ratio				375.00%
New Credit Facilities | Scenario, Forecast
Debt Instrument [Line Items]
Step down percentage upon achievement of first lien secured leverage ratio		25.00%	25.00%
New Term Loan due 2022
Debt Instrument [Line Items]
Long-term debt	$ 825,000,000			$ 822,938,000	$ 822,938,000
Debt Instrument maturity period	5 years
Unamortized debt discount cost	$ 12,400,000
New Term Loan due 2022 | New Credit Facilities | Minimum
Debt Instrument [Line Items]
Debt instrument, LIBOR floor rate	1.00%
New Term Loan due 2022 | New Credit Facilities | LIBOR
Debt Instrument [Line Items]
Interest rate on borrowings under new credit facility	5.75%
New Term Loan due 2022 | New Credit Facilities | Base Rate
Debt Instrument [Line Items]
Interest rate on borrowings under new credit facility	4.75%
Revolving Credit Facility ($170.0 Million capacity)
Debt Instrument [Line Items]
Debt Instrument maturity period	4 years
Maximum borrowings capacity under credit facility	$ 170,000,000			170,000,000	170,000,000
Additional borrowing capacity				0	0
Outstanding letters of credit				11,500,000	11,500,000
Available borrowing capacity				$ 158,500,000	$ 158,500,000
Revolving Credit Facility | New Credit Facilities | Minimum
Debt Instrument [Line Items]
Debt instrument, LIBOR floor rate	0.00%
Revolving Credit Facility | New Credit Facilities | LIBOR | Minimum
Debt Instrument [Line Items]
Interest rate on borrowings under new credit facility	5.25%
Revolving Credit Facility | New Credit Facilities | LIBOR | Maximum
Debt Instrument [Line Items]
Interest rate on borrowings under new credit facility	5.50%
Revolving Credit Facility | New Credit Facilities | Base Rate | Minimum
Debt Instrument [Line Items]
Interest rate on borrowings under new credit facility	4.25%
Revolving Credit Facility | New Credit Facilities | Base Rate | Maximum
Debt Instrument [Line Items]
Interest rate on borrowings under new credit facility	4.50%

Long-Term Debt and Capital Le44

Long-Term Debt and Capital Lease Obligations - Second Lien Notes - Additional Information (Details) - USD ($)	Apr. 01, 2022	Mar. 28, 2017	Jun. 30, 2017	Jun. 30, 2017	Mar. 31, 2022	Mar. 31, 2021
Debt Instrument [Line Items]
Debt instrument redemption description			 the remaining Prior Second Lien Notes at a redemption price equal to the principal amount thereof plus the applicable premium as of, and accrued and unpaid interest;  the Second Lien Senior Secured Exchangeable PIK Notes due 2017 (the “2017 Exchangeable PIK Notes”) at a redemption price equal to the principal amount thereof, plus accrued and unpaid interest; and  the Partnership’s outstanding credit facilities (the “Prior Credit Facilities”), including the revolving credit facility (the “Prior Revolving Credit Facility”) and the term loan (the “Prior Term Loan”), including, in each case, accrued and unpaid interest.
2023 Second Lien Notes
Debt Instrument [Line Items]
Debt Instrument, face amount		$ 425,000,000
Debt instrument maturity date		Apr. 1, 2023
Debt instrument interest percentage		11.50%
Debt instrument interest payable description		The 2023 Second Lien Notes have a maturity date of April 1, 2023 and bear interest at a rate of 11.50% per annum, payable in cash semi-annually on April 1 and October 1 (commencing on October 1, 2017).
Debt instrument frequency of periodic interest payment		semi-annually
Debt instrument date of first interest payment		Oct. 1, 2017
Unamortized debt discount cost		$ 3,200,000
Debt instrument redemption period end date				Apr. 1, 2020
Debt instrument redemption description				Prior to April 1, 2020, the Issuers may redeem the 2023 Second Lien Notes in whole or in part at a price equal to 100% of the aggregate principal amount thereof plus accrued and unpaid interest, if any, plus the applicable “make-whole” premium.
Debt instrument redemption percentage of principal amount thereof plus accrued interest and unpaid interest, if any, plus the applicable make-whole premium				100.00%
Percentage of aggregate principal amount to be redeemed				35.00%
Percentage of remaining outstanding aggregate principal amount after redemption				50.00%
2023 Second Lien Notes | Equity Offering
Debt Instrument [Line Items]
Debt instrument redemption percentage of principal amount thereof plus accrued interest and unpaid interest, if any, plus the applicable make-whole premium				111.50%
2023 Second Lien Notes | Scenario, Forecast
Debt Instrument [Line Items]
Debt instrument redemption percentage of principal amount thereof plus accrued interest and unpaid interest, if any, plus the applicable make-whole premium	100.00%				102.875%	105.75%

Related-Party Transactions - Ad

Related-Party Transactions - Additional Information (Details)	Mar. 28, 2017USD ($)	Mar. 27, 2017USD ($)shares	Apr. 30, 2017USD ($)$ / T	Apr. 30, 2015USD ($)	Jun. 30, 2017USD ($)shares	Jun. 30, 2017USD ($)shares		Mar. 31, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)TrustRenewal$ / Tshares	Jun. 30, 2016USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2009USD ($)	Jul. 31, 2015USD ($)	Apr. 16, 2015
Related Party Transaction [Line Items]
Proceeds from common unit issuance to Murray Energy (affiliate)		$ 60,600,000
Issuance of common units (in units) | shares		9,600,000
Class of Warrant or Right, Outstanding | shares					384,124	384,124				384,124
Financing receivables - affiliates					$ 3,019,000	$ 3,019,000				$ 3,019,000
Coal sales						204,516,000
Long-term debt					1,370,924,000	1,370,924,000				1,370,924,000
Minimum deficiency payment not made					61,000,000	61,000,000				$ 61,000,000
Williamson Energy LLC
Related Party Transaction [Line Items]
Lease payment per ton | $ / T			1.56
Lessee agreement, conditions										(a) include an overriding royalty payment provision equal to the greater of 5% of the gross selling price of the coal, as defined in the agreement, or $1.56 per ton, and (b) increase the quarterly minimum deficiency payment from $2.0 million to $2.1 million.
Minimum deficiency payment not made			$ 2,000,000
Increased minimum deficiency payment			$ 2,100,000
Minimum | Williamson Energy LLC
Related Party Transaction [Line Items]
Percentage of gross price			5.00%
2023 Second Lien Notes
Related Party Transaction [Line Items]
Long-term debt					425,000,000	425,000,000				$ 425,000,000
New Term Loan due 2022
Related Party Transaction [Line Items]
Long-term debt	$ 825,000,000				822,938,000	822,938,000				822,938,000
Transport and Overriding Royalty Agreements
Related Party Transaction [Line Items]
Other revenues						1,800,000		$ 1,600,000	$ 1,200,000		$ 3,000,000
Total remaining minimum payments of transportation lease					88,300,000	88,300,000				88,300,000
Unearned income from financing leasing services						31,200,000
Outstanding financing receivable					57,100,000	57,100,000				57,100,000
Financing receivables - affiliates					2,800,000	2,800,000				2,800,000
ORRA
Related Party Transaction [Line Items]
Other revenues						600,000		800,000	500,000		1,200,000
Outstanding financing receivable					11,600,000	11,600,000				11,600,000
Financing receivables - affiliates					200,000	200,000				200,000
Remaining minimum payments under agreement					31,100,000	31,100,000				31,100,000
Unearned income under agreement					$ 19,500,000	$ 19,500,000				$ 19,500,000
Reserves Investor Group
Related Party Transaction [Line Items]
Number of trusts established | Trust										4
Percentage of voting interests					0.66%	0.66%				0.66%
Percentage of economic interests					0.225%	0.225%				0.225%
Reserves Investor Group | 2017 Exchangeable PIK Notes
Related Party Transaction [Line Items]
Long-term debt					$ 179,900,000	$ 179,900,000				$ 179,900,000
Reserves Investor Group | Prior Second Lien Notes
Related Party Transaction [Line Items]
Long-term debt					$ 15,200,000	15,200,000				$ 15,200,000
Murray Energy Transaction
Related Party Transaction [Line Items]
Proceeds from sale of voting interest				$ 1,370,000,000
Percentage of outstanding limited partner units issued				50.00%											50.00%
Proceeds from common unit issuance to Murray Energy (affiliate)		$ 60,600,000
Natural Resource Partners LP (“NRP”)
Related Party Transaction [Line Items]
General partner ownership interest					31.00%
Limited partners ownership interest					4.00%
Murray Energy And Affiliated Entities
Related Party Transaction [Line Items]
General partner ownership interest	80.00%
Subordinated limited partner ownership interest, description										owner of all of the outstanding subordinated limited partner units
Other revenues						200,000		200,000	300,000		800,000
Purchase of equipment, supplies and rebuild services						3,274,000	[1]	2,100,000	1,300,000		1,700,000
Cost of coal purchased						0		8,000,000	0		600,000
Coal sales						$ 40,300,000		60,700,000	0		0
Foresight Energy GP Limited Liability Company | Murray Energy Transaction
Related Party Transaction [Line Items]
Additional voting interests acquired through exercise of option, percentage	46.00%
Percentage of voting interests acquired	80.00%			34.00%											34.00%
Aggregate exercise price of option	$ 15,000,000
Foresight Energy Limited Liability IDRS | Murray Energy Transaction
Related Party Transaction [Line Items]
Issuance of common units (in units) | shares		9,628,108
Percentage of voting interests acquired				77.50%
Class of Warrant or Right, Outstanding | shares					17,556	17,556				17,556
Manager
Related Party Transaction [Line Items]
Management and administration services, quarterly payment				$ 3,500,000						$ 5,000,000
Management and administration services, annual payment				$ 14,000,000						$ 20,000,000
Manager | Murray Energy Management Services Agreement
Related Party Transaction [Line Items]
Management and administration expenses, net						$ 3,700,000		2,500,000	2,500,000		4,600,000
Manager
Related Party Transaction [Line Items]
Purchase of equipment, supplies and rebuild services						100,000		100,000	300,000		500,000
Javelin
Related Party Transaction [Line Items]
Sales commissions paid						$ 400,000		700,000	0		0
Cline Trust Company LLC | Reserves Investor Group
Related Party Transaction [Line Items]
Class of Warrant or Right, Outstanding | shares					17,556	17,556				17,556
Cline Trust Company LLC | Reserves Investor Group | 2023 Second Lien Notes
Related Party Transaction [Line Items]
Long-term debt					$ 20,000,000	$ 20,000,000				$ 20,000,000
Cline Trust Company LLC | Reserves Investor Group | New Term Loan due 2022
Related Party Transaction [Line Items]
Long-term debt					10,000,000	10,000,000				$ 10,000,000
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%
NRP and Affiliated Entities
Related Party Transaction [Line Items]
Minimum deficiency payment not made														$ 61,000,000
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%
Macoupin
Related Party Transaction [Line Items]
Sale-leaseback transaction, description										In 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP and leased them back. The gross proceeds from this transaction were $143.5 million.
Proceeds from sale-leaseback financing arrangement													$ 143,500,000
Sale-leaseback adjusted carrying value of financing arrangement					133,200,000	133,200,000				$ 133,200,000
Sale-leaseback transaction, imputed interest rate										14.10%
Sugar Camp
Related Party Transaction [Line Items]
Sale-leaseback transaction, description										In 2012, Sugar Camp sold certain rail facility assets to HOD and leased them back. The gross proceeds from this transaction were $50.0 million.
Proceeds from sale-leaseback financing arrangement												$ 50,000,000
Sale-leaseback adjusted carrying value of financing arrangement					$ 67,800,000	$ 67,800,000				$ 67,800,000
Sale-leaseback transaction, imputed interest rate										8.20%
Affiliated Joint Venture
Related Party Transaction [Line Items]
Purchase of mining supplies from affiliates								$ 3,000,000	$ 1,000,000		$ 3,200,000
[1]	Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment and development, net, as applicable

Related-Party Transactions - Su

Related-Party Transactions - Summary of Certain Affiliate Amounts Included in Condensed Consolidated Balance Sheets (Details) - USD ($) $ in Thousands		Jun. 30, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Due from affiliates - current		$ 22,631
Financing receivables - affiliate - current		3,019
Due from affiliates - noncurrent		947
Financing receivables - affiliate - noncurrent		65,696
Prepaid royalties - current and noncurrent		1,977
Accrued interest		16,250
Due to affiliates - current		8,387
Predecessor
Related Party Transaction [Line Items]
Due from affiliates - current			$ 16,891
Financing receivables - affiliate - current			2,904
Due from affiliates - noncurrent			1,843
Financing receivables - affiliate - noncurrent			67,235
Prepaid royalties - current and noncurrent			8,845
Accrued interest			29,760
Due to affiliates - current			20,904
Murray Energy And Affiliated Entities | Affiliates
Related Party Transaction [Line Items]
Due from affiliates - current	[1]	22,631
Financing receivables - affiliate - current		3,019
Due from affiliates - noncurrent		947
Financing receivables - affiliate - noncurrent		65,696
Due to affiliates - current	[1]	8,000
Murray Energy And Affiliated Entities | Predecessor | Affiliates
Related Party Transaction [Line Items]
Due from affiliates - current	[1]		16,784
Financing receivables - affiliate - current			2,904
Due from affiliates - noncurrent			1,843
Financing receivables - affiliate - noncurrent			67,235
Due to affiliates - current	[1]		17,021
NRP and Affiliated Entities | Predecessor | Affiliates
Related Party Transaction [Line Items]
Due from affiliates - current			107
Prepaid royalties - current and noncurrent	[2]		1,246
Sales-leaseback financing arrangements - current and noncurrent			191,869
Accrued interest			2,930
Due to affiliates - current			2,510
Foresight Reserves and Affiliated Entities | Affiliates
Related Party Transaction [Line Items]
Prepaid royalties - current and noncurrent	[2]	1,977
Due to affiliates - current	[3]	$ 387
Foresight Reserves and Affiliated Entities | Predecessor | Affiliates
Related Party Transaction [Line Items]
Prepaid royalties - current and noncurrent	[2]		7,599
Due to affiliates - current	[3]		$ 1,373
[1]	Includes amounts due to/from from Javelin, a joint venture partially owned by Murray Energy.
[2]	Prepaid royalties with Foresight Reserves and affiliated entities and NRP and affiliated entities is presented net of a reserve of $74,575 and $33,965, respectively, as of December 31, 2016.
[3]	As of December 31, 2016, includes amounts due to/from a joint venture partially owned by an affiliate of The Cline Group. On March 31, 2017, The Cline Group sold its interest in the joint venture to the unaffiliated member therefore this joint venture will not be an affiliated party prospectively.

Related-Party Transactions - 47

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

Related-Party Transactions - 48

Related-Party Transactions - Summary of Certain Expenditures and Expenses (Revenues) Incurred With Affiliated Entities (Details) - USD ($)		3 Months Ended				6 Months Ended
		Jun. 30, 2017		Mar. 31, 2017	Jun. 30, 2016	Jun. 30, 2016
Predecessor
Related Party Transaction [Line Items]
Purchased coal				$ 7,973,000		$ 551,000
Murray Energy and Affiliated Entities (Including Javelin)
Related Party Transaction [Line Items]
Coal sales	[1]	$ (40,310,000)
Sales commissions	[2]	367,000
Murray Energy and Affiliated Entities (Including Javelin) | Predecessor
Related Party Transaction [Line Items]
Coal sales	[1]			(60,749,000)		30,000
Sales commissions	[2]			692,000
Murray Energy And Affiliated Entities
Related Party Transaction [Line Items]
Overriding royalty and lease revenues	[3]	(2,412,000)
Terminal revenues	[3]	(166,000)
Purchase of equipment, supplies and rebuild services		3,274,000	[4]	2,100,000	$ 1,300,000	1,700,000
Purchased coal		0		8,000,000	0	600,000
Management services, net	[2]	3,713,000
Murray Energy And Affiliated Entities | Predecessor
Related Party Transaction [Line Items]
Overriding royalty and lease revenues	[3]			(2,355,000)	(1,645,000)	(4,115,000)
Terminal revenues	[3]			(226,000)	(262,000)	(780,000)
Purchase of equipment, supplies and rebuild services	[4]			2,061,000	1,308,000	1,700,000
Purchased coal	[5]			7,973,000		551,000
Management services, net	[2]			2,547,000	2,491,000	4,570,000
NRP and Affiliated Entities
Related Party Transaction [Line Items]
Royalty expense	[6]	710,000
Loadout services	[6]	746,000
Sales-leaseback interest expense	[7]	2,012,000
NRP and Affiliated Entities | Predecessor
Related Party Transaction [Line Items]
Royalty expense	[6]			3,669,000	4,442,000	7,286,000
Loadout services	[6]			2,134,000	1,937,000	3,660,000
Sales-leaseback interest expense	[7]			6,244,000	6,540,000	12,403,000
Foresight Reserves and Affiliated Entities
Related Party Transaction [Line Items]
Royalty expense	[6]	$ 6,735,000
Foresight Reserves and Affiliated Entities | Predecessor
Related Party Transaction [Line Items]
Royalty expense	[6]			$ 1,521,000	$ 3,710,000	$ 7,157,000
[1]	Coal sales
[2]	Selling, general and administrative
[3]	Other revenues
[4]	Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment and development, net, as applicable
[5]	Cost of coal purchased
[6]	Cost of coal produced (excluding depreciation, depletion and amortization)
[7]	Interest expense, net

Earnings per Limited Partner 49

Earnings per Limited Partner Unit - Summary of Partnership's Calculation of Net Loss per Common and Subordinated Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Jun. 30, 2016
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units	$ (16,277)
Weighted-average units to calculate basic EPU	141,225
Weighted-average units to calculate diluted EPU	141,225
Basic net loss per unit	$ (0.12)
Diluted net loss per unit	$ (0.12)
Common Units
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units	$ (8,790)
Weighted-average units to calculate basic EPU	76,270
Weighted-average units to calculate diluted EPU	76,270
Basic net loss per unit	$ (0.12)
Diluted net loss per unit	$ (0.12)
Subordinated Units
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units	$ (7,487)
Weighted-average units to calculate basic EPU	64,955
Weighted-average units to calculate diluted EPU	64,955
Basic net loss per unit	$ (0.12)
Diluted net loss per unit	$ (0.12)
Predecessor
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units		$ (111,184)	$ (27,786)	$ (69,491)
Weighted-average units to calculate basic EPU		131,488	130,872	130,510
Weighted-average units to calculate diluted EPU		131,488	130,872	130,510
Basic net loss per unit		$ (0.85)	$ (0.21)	$ (0.53)
Diluted net loss per unit		$ (0.85)	$ (0.21)	$ (0.53)
Predecessor | Common Units
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units		$ (56,259)	$ (13,995)	$ (34,886)
Weighted-average units to calculate basic EPU		66,533	65,917	65,555
Weighted-average units to calculate diluted EPU		66,533	65,917	65,555
Basic net loss per unit		$ (0.85)	$ (0.21)	$ (0.53)
Diluted net loss per unit		$ (0.85)	$ (0.21)	$ (0.53)
Predecessor | Subordinated Units
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units		$ (54,925)	$ (13,791)	$ (34,605)
Weighted-average units to calculate basic EPU		64,955	64,955	64,955
Weighted-average units to calculate diluted EPU		64,955	64,955	64,955
Basic net loss per unit		$ (0.85)	$ (0.21)	$ (0.53)
Diluted net loss per unit		$ (0.85)	$ (0.21)	$ (0.53)

Earnings per Limited Partner 50

Earnings per Limited Partner Unit - Summary of Partnership's Calculation of Net Loss per Common and Subordinated Unit (Parenthetical) (Details) - $ / shares	3 Months Ended			6 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Jun. 30, 2016	Mar. 28, 2017	Aug. 31, 2016
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Class of Warrant or Right, Outstanding	384,124
Warrant exchange rate for common units	12,800				12,800
Exercise price of the warrants	$ 0.8928					$ 0.8928
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	300,000
Phantom Share Units (PSUs) | Predecessor
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share, amount		300,000	200,000	200,000

Fair Value of Financial Instr51

Fair Value of Financial Instruments - Fair Value of Net Financial Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Predecessor
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	$ 1,318
Total	1,318
Fair Value, Measurements, Recurring | Predecessor
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Coal derivative contracts		7,315
Warrant liability		(51,169)
Total		(43,854)
Fair Value, Measurements, Recurring | Fair Value, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Coal derivative contracts	1,318
Total	$ 1,318
Fair Value, Measurements, Recurring | Fair Value, Level 2 | Predecessor
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Coal derivative contracts		7,315
Total		7,315
Fair Value, Measurements, Recurring | Fair Value, Level 3 | Predecessor
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Warrant liability		(51,169)
Total		$ (51,169)

Fair Value of Financial Instr52

Fair Value of Financial Instruments - Fair Value of Gross Financial Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets	$ 1,318
Predecessor
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets		$ 7,650
Other Long-Term Liabilities		(51,169)
Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets	1,318
Fair Value, Measurements, Recurring | Predecessor
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets		7,650
Accrued Expenses		(335)
Other Long-Term Liabilities		(51,169)
Fair Value, Measurements, Recurring | Predecessor | Warrant Liability
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other Long-Term Liabilities		(51,169)
Coal Derivative Contract | Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets	$ 1,318
Coal Derivative Contract | Fair Value, Measurements, Recurring | Predecessor
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current – Coal Derivative Assets		7,650
Accrued Expenses		$ (335)

Fair Value Measures and Disclos

Fair Value Measures and Disclosures - Additional Information (Details) - USD ($)	1 Months Ended	6 Months Ended
	Aug. 31, 2016	Jun. 30, 2017	Mar. 28, 2017	Dec. 31, 2016
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Assets or liabilities transferred between level 1 and level 2		$ 0		$ 0
Exercise price of the warrants	$ 0.8928	$ 0.8928
Warrant exchange rate for common units		12,800	12,800
Warrants outstanding		384,124
Fair value of Long-Term Debt		$ 1,278,100,000		$ 1,378,600,000
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		2.39%
Unaffiliated Owners
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Warrants issued	516,875
2017 Exchangeable PIK Notes
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of warrants to purchase of common units	4.50%

Fair Value of Financial Instr54

Fair Value of Financial Instruments - Fair Value Liabilities Measured on Recurring Basis with Unobservable Input Reconciliation (Details) - Warrant Liability - Predecessor $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Balance at January 1, 2017	$ 51,169
Recorded fair value losses
Included in earnings - gain	(9,281)
Reclassification of fair value to partners’ capital	$ (41,888)

Contingencies - Additional Info

Contingencies - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	May 31, 2017	Jun. 30, 2017	Dec. 31, 2016	Jan. 31, 2016
Loss Contingencies [Line Items]
Minimum deficiency payment not made		$ 61,000,000
Accrued litigation expense		0
Cost of coal produced (excluding depreciation, depletion and amortization)		105,790,000
Other operating (income) expense		13,490,000
Estimated insurance recoveries		0
Outstanding performance bonds		84,500,000
Surety Bond
Loss Contingencies [Line Items]
Outstanding letters of credit		$ 4,500,000
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	$ 12,800,000		$ 20,000,000

Subsequent Event - Additional I

Subsequent Event - Additional Information (Details) - Subsequent Event - Common Units	Aug. 11, 2017$ / shares
Subsequent Event [Line Items]
Cash distribution, announcement date	Aug. 11, 2017
Cash distribution, announced per unit payable	$ 0.0647
Cash distribution, payable date	Aug. 31, 2017
Cash distribution, record date	Aug. 21, 2017