10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission File Number: 001-36503

Foresight Energy LP

(Exact Name of Registrant as Specified in its Charter)

Delaware	80-0778894
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
211 North Broadway, Suite 2600, Saint Louis, MO	63102
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (314) 932-6160

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes ☒    No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐Accelerated filer    ☒       Non-accelerated filer   ☐	Smaller reporting company  ☐
	(do not check if a smaller reporting company)	Emerging growth company  ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

As of May 1, 2018, the registrant had 79,826,538 common units and 64,954,691 subordinated units outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION

Item 1.Financial Statements
Unaudited Condensed Consolidated Balance Sheets	3
Unaudited Condensed Consolidated Statements of Operations	4
Unaudited Condensed Consolidated Statement of Partners’ Capital	5
Unaudited Condensed Consolidated Statements of Cash Flows	6
Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.Quantitative and Qualitative Disclosures About Market Risk	27
Item 4.Controls and Procedures	27
PART II
OTHER INFORMATION
Item 1.Legal Proceedings	28
Item 1A.Risk Factors	28
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3.Defaults Upon Senior Securities	28
Item 4.Mine Safety Disclosures	28
Item 5.Other Information	28
Item 6. Exhibits	29
Signatures	30

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PART I – FINANCIAL INFORMATION.

Item 1. Financial Statements.

Foresight Energy LP

Unaudited Condensed Consolidated Balance Sheets

(In Thousands)

	(Successor)		(Successor)
	March 31,		December 31,
	2018		2017
Assets
Current assets:
Cash and cash equivalents	$	18,553	$	2,179
Accounts receivable		28,611		35,158
Due from affiliates		26,315		37,685
Financing receivables - affiliate		3,200		3,138
Inventories, net		56,557		40,539
Prepaid royalties		1,579		4,000
Deferred longwall costs		19,135		9,520
Other prepaid expenses and current assets		8,579		10,844
Contract-based intangibles		6,145		11,268
Total current assets		168,674		154,331
Property, plant, equipment and development, net		2,340,623		2,378,605
Due from affiliates		—		947
Financing receivables - affiliate		63,257		64,097
Prepaid royalties, net		1,667		1,250
Other assets		4,432		5,358
Contract-based intangibles		1,721		2,052
Total assets	$	2,580,374	$	2,606,640
Liabilities and partners’ capital
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	99,623	$	109,532
Current portion of sale-leaseback financing arrangements		4,731		4,148
Accrued interest		26,725		13,410
Accounts payable		85,876		76,658
Accrued expenses and other current liabilities		62,684		62,442
Asset retirement obligations		4,416		4,416
Due to affiliates		12,399		13,324
Contract-based intangibles		24,006		28,688
Total current liabilities		320,460		312,618
Long-term debt and capital lease obligations		1,202,956		1,205,000
Sale-leaseback financing arrangements		195,621		196,496
Asset retirement obligations		40,011		39,655
Other long-term liabilities		28,901		32,330
Contract-based intangibles		142,522		144,715
Total liabilities		1,930,471		1,930,814
Limited partners' capital:
Common unitholders (79,827 and 77,644 units outstanding as of March 31, 2018 and December 31, 2017, respectively)		407,018		421,161
Subordinated unitholder (64,955 units outstanding as of March 31, 2018 and December 31, 2017)		242,885		254,665
Total partners' capital		649,903		675,826
Total liabilities and partners' capital	$	2,580,374	$	2,606,640

See accompanying notes.

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Foresight Energy LP

Unaudited Condensed Consolidated Statements of Operations

(In Thousands, Except per Unit Data)

	(Successor)			(Predecessor)
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Revenues
Coal sales	$	238,387		$	227,813
Other revenues		2,339			2,581
Total revenues		240,726			230,394
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)		120,570			117,762
Cost of coal purchased		1,751			7,973
Transportation		46,443			37,726
Depreciation, depletion and amortization		51,420			39,298
Contract amortization		(1,420	)		—
Accretion on asset retirement obligations		731			710
Selling, general and administrative		7,775			6,554
Loss on commodity derivative contracts		—			1,492
Other operating (income) expense, net		(648	)		451
Operating income		14,104			18,428
Other expenses:
Interest expense, net		35,673			43,380
Change in fair value of warrants		—			(9,278	)
Loss on early extinguishment of debt		—			95,510
Net loss	$	(21,569	)	$	(111,184	)
Net loss available to limited partner units - basic and diluted:
Common unitholders	$	(9,789	)	$	(56,259	)
Subordinated unitholder	$	(11,780	)	$	(54,925	)
Net loss per limited partner unit - basic and diluted:
Common unitholders	$	(0.12	)	$	(0.85	)
Subordinated unitholder	$	(0.18	)	$	(0.85	)
Weighted average limited partner units outstanding - basic and diluted:
Common units		78,846			66,533
Subordinated units		64,955			64,955
Distributions declared per limited partner unit	$	0.0565		$	—

See accompanying notes.

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Foresight Energy LP

Unaudited Condensed Consolidated Statement of Partners’ Capital

(In Thousands, Except Unit Data)

	Limited Partners
	Common			Number of		Subordinated			Number of		Total Partners'
	Unitholders			Common Units		Unitholder			Subordinated Units		Capital (Deficit)
Successor balance at January 1, 2018	$	421,161			77,644,489	$	254,665			64,954,691	$	675,826
Net loss attributable to successor		(9,789	)		—		(11,780	)		—		(21,569	)
Cash distributions		(4,510	)		—		—			—		(4,510	)
Conversion of warrants, net		—			2,135,493		—			—		—
Equity-based compensation		177			—		—			—		177
Issuance of equity-based awards		—			46,556		—			—		—
Distribution equivalent rights on LTIP awards		(21	)		—		—			—		(21	)
Successor balance at March 31, 2018	$	407,018			79,826,538	$	242,885			64,954,691	$	649,903

See accompanying notes.

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Foresight Energy LP

Unaudited Condensed Consolidated Statements of Cash Flows

(In Thousands)

	(Successor)			(Predecessor)
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Cash flows from operating activities
Net loss	$	(21,569	)	$	(111,184	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		51,420			39,298
Amortization of debt discount and deferred issuance costs		655			6,365
Contract amortization		(1,420	)		—
Equity-based compensation		177			318
Loss on commodity derivative contracts		—			1,492
Settlements of commodity derivative contracts		—			3,724
Realized gains on coal derivatives included in investing activities		—			(3,520	)
Change in fair value of warrants		—			(9,278	)
Debt extinguishment expense		—			95,510
Other		—			1,321
Changes in operating assets and liabilities:
Accounts receivable		6,547			19,695
Due from/to affiliates, net		11,392			(13,157	)
Inventories		(12,927	)		(917	)
Prepaid expenses and other assets		(6,424	)		(5,117	)
Prepaid royalties		2,004			(241	)
Commodity derivative assets and liabilities		—			(532	)
Accounts payable		9,218			7,324
Accrued interest		13,315			(9,803	)
Accrued expenses and other current liabilities		(1,466	)		(3,430	)
Other		784			1,782
Net cash provided by operating activities		51,706			19,650
Cash flows from investing activities
Investment in property, plant, equipment and development		(16,531	)		(19,908	)
Return of investment on financing arrangements with Murray Energy (affiliate)		778			705
Settlement of certain coal derivatives		—			3,520
Proceeds from sale of property, plant and equipment		—			1,898
Net cash used in investing activities		(15,753	)		(13,785	)
Cash flows from financing activities
Net change in borrowings under revolving credit facility		—			(352,500	)
Net change in borrowings under A/R securitization program		—			7,000
Proceeds from long-term debt and capital lease obligations		—			1,234,438
Payments on long-term debt and capital lease obligations		(12,608	)		(970,721	)
Payments on short-term debt		(2,147	)		—
Proceeds from issuance of common units to Murray Energy (affiliate)		—			60,586
Distributions paid		(4,510	)		—
Debt extinguishment costs		—			(57,645	)
Debt issuance costs paid		—			(27,328	)
Other		(314	)		(1,892	)
Net cash used in financing activities		(19,579	)		(108,062	)
Net increase (decrease) in cash, cash equivalents, and restricted cash		16,374			(102,197	)
Cash, cash equivalents, and restricted cash, beginning of period		2,179			116,921
Cash, cash equivalents, and restricted cash, end of period	$	18,553		$	14,724

See accompanying notes.

6

Foresight Energy LP

Notes to Unaudited Condensed Consolidated Financial Statements

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 and its affiliates (“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 (the “March 2017 Refinancing Transactions”), Murray Energy exercised its option (the “FEGP Option”) to acquire an additional 46% voting interest in FEGP from Foresight Reserves and a former member of management pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and a former member of management, 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 Accounting Standards Codification (“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 adjustment of our assets and liabilities to fair value required by pushdown accounting in our consolidated financial statements.

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 owns 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. On April 11, 2018, we announced that our Hillsboro operation will be permanently closed (see Note 13). 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, 2017 included in our Annual Report on Form 10-K filed with the SEC on March 7, 2018. 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, 2018. Intercompany transactions are eliminated in consolidation.

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2. New Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (“ASC 606”), that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. We adopted ASC 606 as of January 1, 2018 using the modified retrospective approach; therefore, the comparative information has not been adjusted and continues to be reported under previous revenue recognition guidance.  The adoption did not have a material effect on our financial position and results of operations as the timing of revenue recognition related to coal sales remains consistent between ASC 606 and previous revenue recognition guidance. Additionally, there was no cumulative adjustment to partners’ capital as of January 1, 2018. Refer to Note 3 for the additional financial statement disclosures required by ASC 606.

In November 2016, the FASB issued ASU 2016-18 which clarified the presentation requirements of restricted cash within the statement of cash flows. Under ASU 2016-18, the changes in restricted cash and restricted cash equivalents during the period should be included in the beginning and ending cash and cash equivalents balance reconciliation on the statement of cash flows. When cash, cash equivalents, restricted cash or restricted cash equivalents are presented in more than one line item within the statement of financial position, an entity shall calculate a total cash amount in a narrative or tabular format that agrees to the amount shown on the statement of cash flows. Details on the nature and amounts of restricted cash should also be disclosed. This standard is effective for fiscal years beginning after December 15, 2017, and is to be applied retrospectively. We adopted this update during the first quarter of 2018 and this new guidance to required adjustments to the presentation of our condensed consolidated statement of cash flows. Refer to Note 4 for the additional financial statement disclosures required by this update.

In February 2016, the FASB updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements and related disclosures. We disclosed our future minimum payments on our contractual royalty obligations and operating lease obligations in our Annual Report on Form 10-K filed with the SEC on March 7, 2018 and we will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under the new standard

3. Revenue from Contracts with Customers

Significant Accounting Policy

Revenue is measured based on consideration specified in a contract with a customer. The Partnership recognizes revenue when it satisfies a performance obligation by transferring control over goods and services to a customer.

Shipping and handling costs (e.g., the application of anti-freezing agents) are accounted for as fulfillment costs. The Partnership includes any fulfillment costs billed to customers in revenue, with the corresponding expenses included in cost of coal produced and transportation.

Nature of Goods and Services

The Partnership’s primary source of revenue is from the sale of coal to domestic and international customers through short-term and long-term coal sales contracts. Coal sales revenue includes the sale to customers of coal produced and, from time to time, the re-sale of coal purchased from third-parties or from one of our affiliates. Performance obligations, consisting of individual tons of coal, are satisfied at a point in time when control is transferred to a customer.  For domestic coal sales, this generally occurs when coal is loaded onto railcars at the mine or onto barges at terminals.  For coal sales to international markets, this generally occurs when coal is loaded onto an ocean vessel.  

The Partnership’s coal sales contracts typically range in length from one to three years, however some agreements have terms of as little as one month. Coal sales contracts generally provide for either a fixed base price or a base price determined by a market index. The base price is subject to quality and weight adjustments. Quality and weight adjustments are recorded as necessary based on coal sales contract specifications as a reduction or increase to coal sales revenue. The coal sales contracts also typically give the customer

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the option to vary volumes, subject to certain minimums. Coal sales are generally invoiced upon shipment and payment is due from customers within standard industry credit timeframes.  

Disaggregation of Revenue

The following table disaggregates revenue by domestic and international markets:

	(Successor)
	Three Months Ended March 31, 2018
	(In Thousands)
Coal sales - Domestic	$	142,715
Coal sales - International		95,672
Total coal sales	$	238,387

Contract Balances

The following table provides information about balances associated with contracts with customers:

	(Successor)
	March 31, 2018
	(In Thousands)
Receivables - Included in 'Accounts receivable'	$	25,179
Receivables - Included in 'Due from affiliates - current'		20,395
Total contract balances	$	45,574

Contract Costs

The Partnership applies the practical expedient in ASC 340-40-25-4, whereby the Partnership recognizes the incremental costs of obtaining contracts as an expense when incurred if the amortization period of the assets that the Partnership would have recognized is one year or less. These costs are included in selling, general and administrative expenses.

Other Revenues

Other revenues consist primarily of a transport lease and overriding royalty agreements with Murray Energy (see Note 9). These arrangements are accounted for under guidance contained in ASC 310 Receivables, ASC 360 Property, Plant, and Equipment, and ASC 840 Leases and therefore are outside the scope of ASC 606.

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4. Supplemental Cash Flow Information

The following is supplemental information to the condensed consolidated statement of cash flows (in thousands):

	(Successor)		(Predecessor)
	Three Months Ended March 31, 2018		Three Months Ended March 31, 2017
Supplemental disclosures of non-cash financing activities:
Reclassification of warrant liability to partners' capital	$	—	$	41,888

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the total of the same such amounts shown in the condensed consolidated statement of cash flows (in thousands):

	(Successor)		(Successor)		(Successor)		(Predecessor)
	March 31, 2018		December 31, 2017		March 31, 2017		December 31, 2016
Cash and cash equivalents	$	18,553	$	2,179	$	4,235	$	103,690
Restricted cash - Included in 'Other prepaid expenses and current assets'		—		—		10,489		10,731
Restricted cash - Included in 'Other assets'		—		—		—		2,500
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	18,553	$	2,179	$	14,724	$	116,921

Restricted cash included in other prepaid expenses and current assets were amounts that were required to be temporarily held in a restricted cash account for a short duration related to our trade accounts receivable securitization program. The accounts receivable securitization program terminated in December 2017.  

Restricted cash included in other assets was cash collateral used to secure a letter of credit for one of our surety bond providers. During the three months ended March 31, 2017, the restriction was released.

5. Accounts Receivable

Accounts receivable consist of the following:

	(Successor)		(Successor)
	March 31, 2018		December 31, 2017
	(In Thousands)
Trade accounts receivable	$	25,179	$	31,225
Other receivables		3,432		3,933
Total accounts receivable	$	28,611	$	35,158

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6. Inventories, Net

Inventories, net consist of the following:

	(Successor)		(Successor)
	March 31, 2018		December 31, 2017
	(In Thousands)
Parts and supplies	$	17,366	$	17,196
Raw coal		3,777		5,577
Clean coal		35,414		17,766
Total inventories	$	56,557	$	40,539

7. Property, Plant, Equipment and Development, Net

Property, plant, equipment and development, net consist of the following:

	(Successor)			(Successor)
	March 31, 2018			December 31, 2017
	(In Thousands)
Land, land rights and mineral rights	$	1,639,980		$	1,639,980
Machinery and equipment		545,570			580,649
Machinery and equipment under capital lease		127,064			127,064
Buildings and structures		221,625			221,625
Development costs		20,450			16,644
Other		3,449			3,449
Property, plant, equipment and development		2,558,138			2,589,411
Less: accumulated depreciation, depletion and amortization		(217,515	)		(210,806	)
Property, plant, equipment and development, net	$	2,340,623		$	2,378,605

8. Long-Term Debt and Capital Lease Obligations

Long-term debt and capital lease obligations consist of the following:

	(Successor)			(Successor)
	March 31, 2018			December 31, 2017
	(In Thousands)
Term Loan due 2022	$	816,750		$	818,813
Second Lien Notes due 2023		425,000			425,000
Revolving Credit Facility ($170.0 million capacity)		—			—
5.78% longwall financing arrangement		28,012			28,012
5.555% longwall financing arrangement		23,204			30,937
Capital lease obligations		22,566			25,378
Subtotal - Total long-term debt and capital lease obligations principal outstanding		1,315,532			1,328,140
Unamortized debt discounts		(12,953	)		(13,608	)
Total long-term debt and capital lease obligations		1,302,579			1,314,532
Less: current portion		(99,623	)		(109,532	)
Non-current portion of long-term debt and capital lease obligations	$	1,202,956		$	1,205,000

Term Loan due 2022

The Term Loan due 2022 bears interest at the borrower’s option of (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. The Term Loan due 2022 also requires us to prepay outstanding borrowings (the

11

“Excess Cash Flow Provisions”), subject to certain exceptions. The Excess Cash Flow Provisions are calculated annually and are payable 95 days after year-end.  We are required to prepay $53.8 million of outstanding borrowings under the Excess Cash Flow Provisions for the annual period ending December 31, 2017.  Accordingly, this amount has been included in the current portion of long-term debt and capital lease obligations on our condensed consolidated balance sheets as of March 31, 2018.

Second Lien Notes due 2023

The Second Lien Notes due 2023 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.

Revolving Credit Facility

The Revolving Credit Facility has a total borrowing capacity of $170.0 million and bears interest at the borrower’s option of (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. 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.

As of March 31, 2018, there were no outstanding borrowings under our Revolving Credit Facility and available borrowing capacity under the Revolving Credit Facility, net of outstanding letters of credit of $9.0 million, was $161.0 million.  

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 8, 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 8, 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 (“IDRs”) 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 March 2017 Refinancing Transactions, Murray Energy exercised its FEGP Option to acquire an additional 46% voting interest in FEGP from Foresight Reserves and a former member of management pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and a former member of management, as amended, thereby increasing Murray Energy’s voting interest in FEGP 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 was also a holder of 17,556 of FELP’s outstanding warrants. All outstanding warrants held by Murray Energy were exercised in 2017 and Murray Energy held no outstanding warrants as of March 31, 2018.

Following the exercise of the FEGP Option, certain changes to the operating agreement of FEGP went into effect, pursuant to which Murray Energy is entitled to appoint a majority of the board of directors of FEGP (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. All members of 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.

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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, FEGP 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 escalations and adjustments for direct costs incurred by FELP, the amount of net expense due to the Manager for the three months ended March 31, 2018 and 2017 was $4.0 million and $2.5 million, respectively.

Murray Energy Transport Lease and Overriding Royalty Agreements

For the three months ended March 31, 2018 and 2017, we recorded other revenues of $1.6 million and $1.6 million, respectively, under the transport lease (the “Transport Lease”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy.  The total remaining minimum payments under the Transport Lease were $83.1 million at March 31, 2018, with unearned income equal to $28.1 million. As of March 31, 2018, the outstanding Transport Lease financing receivable was $55.0 million, of which $3.0 million was classified as current in the condensed consolidated balance sheet.

For the three months ended March 31, 2018 and 2017, we recorded other revenues of $0.7 million and $0.8 million, respectively, under the overriding royalty agreement (the “ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company. The total remaining minimum payments under the ORRA were $29.6 million at March 31, 2018, with unearned income equal to $18.2 million. As of March 31, 2018, the outstanding ORRA financing receivable was $11.4 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 March 31, 2018 and 2017, we purchased $4.1 million and $2.1 million, respectively, in equipment, supplies and rebuild services from affiliates of Murray Energy.  During the three months ended March 31, 2018 and 2017, we provided $0.1 million and $0.1 million, respectively, in equipment, supplies and rebuild services to affiliates of Murray Energy.

From time to time, we purchase and sell coal to Murray Energy and its affiliates to, among other things, meet 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. During the three months ended March 31, 2018 and 2017, we purchased $1.8 million and $8.0 million, respectively of coal from Murray Energy and its affiliates and we sold $85.1 million and $60.7 million, respectively, of coal to Murray Energy and its affiliates, including Javelin.

During the three months ended March 31, 2018 and 2017, we paid Javelin $1.0 million and $0.5 million, respectively, in transportation costs related to certain export sales.

During the three months ended March 31, 2018 and 2017, we also paid Javelin $1.3 million and $0.7 million, respectively, in sales and marketing expenses.

During the three months ended March 31, 2018 and 2017, we earned less than $0.1 million and $0.2 million, respectively, in other revenues for Murray Energy’s usage of our Sitran terminal.

During the three months ended March 31, 2018, we utilized capacity on a Murray Energy transloading contract with a third party, thereby allowing Murray Energy to reduce its exposure to certain contractual liquidated damage charges.  To compensate the Partnership for the reduced contractual liquidated damage charges, Murray Energy reimbursed the Partnership $2.5 million of transportation expenses during the three months ended March 31, 2018.

During the three months ended March 31, 2018, Murray Energy utilized our capacity within our transportation agreement with a third party, thereby allowing us to reduce our exposure to certain contractual liquidated damage charges.  To compensate Murray Energy for our reduced contractual liquidated damage charges, we reimbursed Murray Energy $0.2 million of transportation expenses during the three months ended March 31, 2018.  

From time to time, we also reimburse Murray Energy for costs paid by them on our behalf, including certain insurance premiums.

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Reserves Investor Group

The Reserves Investor Group includes Christopher Cline, the Cline Resource and Development Company (“CRDC”), the four trusts established for the benefit of Mr. Cline’s children (the “Cline Trust”), and certain other limited liability companies owned or controlled by individuals with limited partner interests in Foresight Reserves through indirect ownership. Concurrent with and subsequent to the March 2017 Refinancing Transactions, CRDC and the Cline Trust acquired investments in our Term Loan due 2022 and our Second Lien Notes due 2023 on consistent terms as the unaffiliated owners of these notes.

As of March 31, 2018, CRDC owned $9.9 million and $5.0 million of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023, respectively.

As of March 31, 2018, the Cline Trust owned $9.9 million and $20.0 million of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023, respectively. The Cline Trust is also a holder of 17,556 of FELP’s outstanding warrants as of March 31, 2018.

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.

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.

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The following table summarizes certain affiliate amounts included in our condensed consolidated balance sheets:

		(Successor)		(Successor)
Affiliated Company	Balance Sheet Location	March 31, 2018		December 31, 2017
		(In Thousands)
Murray Energy and affiliated entities (1)	Due from affiliates - current	$	26,315	$	37,685
Total		$	26,315	$	37,685
Murray Energy and affiliated entities	Financing receivables - affiliate - current	$	3,200	$	3,138
Total		$	3,200	$	3,138
Murray Energy and affiliated entities	Due from affiliates - noncurrent	$	—	$	947
Total		$	—	$	947
Murray Energy and affiliated entities	Financing receivables - affiliate - noncurrent	$	63,257	$	64,097
Total		$	63,257	$	64,097
Foresight Reserves and affiliated entities	Prepaid royalties - current and noncurrent	$	1,579	$	4,000
Total		$	1,579	$	4,000
Murray Energy and affiliated entities (1)	Due to affiliates - current	$	11,384	$	11,591
Foresight Reserves and affiliated entities	Due to affiliates - current		1,015		1,733
Total		$	12,399	$	13,324

(1) – Includes amounts due to/from Javelin, a joint venture partially owned by Murray Energy.

A summary of certain expenditures and expenses (revenues) incurred with affiliated entities is as follows for the three months ended  March 31, 2018 and 2017 (in thousands):

	(Successor)			(Predecessor)
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Coal sales – Murray Energy and affiliated entities (including Javelin) (1)	$	(85,082	)	$	(60,749	)
Overriding royalty and lease revenues – Murray Energy and affiliated entities (2)	$	(2,296	)	$	(2,355	)
Terminal revenues - Murray Energy and affiliated entities (2)	$	(44	)	$	(226	)
Royalty expense – NRP and affiliated entities (3) — through April 30, 2017	n/a			$	3,669
Royalty expense – Foresight Reserves and affiliated entities (3)	$	5,387		$	1,521
Loadout services – NRP and affiliated entities (3) — through April 30, 2017	n/a			$	2,134
Transportation services - Murray Energy and affiliated entities (including Javelin) (4)	$	978		$	525
Purchased goods and services – Murray Energy and affiliated entities (5)	$	4,118		$	2,061
Purchased coal - Murray Energy and affiliated entities (6)	$	1,751		$	7,973
Land leases - Foresight Reserves and affiliated entities (3), (4)	$	60		$	57
Sales and marketing expenses - Murray Energy and affiliated entities (including Javelin)(7)	$	1,266		$	692
Management services, net  – Murray Energy and affiliated entities (7)	$	3,983		$	2,547
Sales-leaseback interest expense - NRP and affiliated entities (8) — through April 30, 2017	n/a			$	6,244

Principal location in the condensed consolidated financial statements:

(1) – Coal sales

(2) – Other revenues

(3) – Cost of coal produced (excluding depreciation, depletion and amortization)

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(4) – Transportation

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

(6) – Cost of coal purchased

(7) – Selling, general and administrative

(8) – Interest expense, net

Transactions with NRP and affiliated entities 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 9, 2017.

We also purchased $3.0 million in mining supplies from an affiliated joint venture under a supply agreement during the three months ended March 31, 2017. This joint venture was no longer an affiliate subsequent to March 31, 2017, due to The Cline Group disposing of its interest in the joint venture.

10. Earnings per Limited Partner Unit

We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in ASC 260, Earnings Per Share. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic EPU. In addition to the common and subordinated units, we have also identified the general partner interest and our incentive distribution rights (“IDR”) as participating securities. Under the two-class method, EPU is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The Partnership’s net 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 IDRs 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 IDRs. 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 March 31,									Three Months Ended March 31,
	2018									2017
	Common Units			Subordinated Units			Total			Common Units			Subordinated Units			Total
	(In Thousands, Except Per Unit Data)									(In Thousands, Except Per Unit Data)
Numerator:
Net loss available to limited partner units	$	(9,789	)	$	(11,780	)	$	(21,569	)	$	(56,259	)	$	(54,925	)	$	(111,184	)
Denominator:
Weighted-average units to calculate basic EPU		78,846			64,955			143,801			66,533			64,955			131,488
Less: effect of dilutive securities (1)		—			—			—			—			—			—
Weighted-average units to calculate diluted EPU		78,846			64,955			143,801			66,533			64,955			131,488
Basic net loss per unit	$	(0.12	)	$	(0.18	)	$	(0.15	)	$	(0.85	)	$	(0.85	)	$	(0.85	)
Diluted net loss per unit	$	(0.12	)	$	(0.18	)	$	(0.15	)	$	(0.85	)	$	(0.85	)	$	(0.85	)

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(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 March 31, 2018 and 2017, approximately 0.3 million and 0.4 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 142,530Warrants outstanding as of March 31, 2018, which are convertible into common units at an exchange rate of approximately 13.4 common units of FELP at an exercise price of $0.8531 per common unit, in each case subject to adjustment (see Note 11).

11. Fair Value of Financial Instruments

Warrants

In August 2016, FELP issued 516,825 warrants (the “Warrants”) to the unaffiliated owners of previously outstanding debt to purchase an amount of common units. 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.

As a result of a series of transactions related to the March 2017 Refinancing Transactions, 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 subsequent to the March 2017 Refinancing Transactions. As of March 31, 2018, there are 142,530 Warrants outstanding and exercisable into 13.4 common units of FELP at an exercise price of $0.8531 per common unit.

Long-Term Debt

The fair value of long-term debt as of March 31, 2018 and December 31, 2017 was $1,205.1 million and $1,178.1 million, respectively. The fair value of long-term debt was calculated based on (i) quoted prices in markets that are not active and (ii) the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms.  These are considered Level 2 and Level 3 fair value measurements, respectively.

12. Contingencies

In January 2016, WPP LLC (“WPP”), a subsidiary of NRP, a 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 LLC (“HOD”), a subsidiary of NRP filed a complaint in the Circuit Court of Macoupin County, Illinois. As of December 31, 2017, WPP claims it is owed $9.5 million. 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. Macoupin has filed a motion to dismiss the Complaint, which is pending.

In July 2015, we provided notice to WPP declaring a force majeure event at our Hillsboro mine due to a combustion event. As a result of the force majeure event, as of March 31, 2018, we have not made $83.5 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, and WPP has subsequently amended its Complaint. On October 6, 2017, the Circuit Court dismissed many of the claims in the Third Amended Complaint against Hillsboro and the Partnership and other of its subsidiaries. However, WPP was afforded a chance to replead some claims, and WPP’s claim for breach of the royalty agreement will proceed. 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 and interest of 1% per month. A bench trial to resolve the dispute over Hillsboro’s declaration of force majeure is currently set for October 22, 2018.

On April 11, 2018, Hillsboro filed appropriate pleadings to seek a declaratory judgment from the Circuit Court of Montgomery County, Illinois, that the royalty agreement has terminated by its own terms.  Under the royalty agreement, Hillsboro leased certain mineral rights from WPP for a term of 20 years (with the option to renew for additional five-year terms, with a maximum of six terms) or until the date on which all merchantable and mineable coal under the royalty agreement has been mined and removed.  Hillsboro maintains that all merchantable and mineable coal under the royalty agreement was mined and removed as of March 26, 2015, the date on which the last coal was mined and removed under the terms of the royalty agreement.  If the Court agrees that the royalty agreement is terminated, no payments are owed by Hillsboro under the royalty agreement after the date of termination.  Hillsboro’s declaratory judgment action is subject to litigation, the outcome of which remains uncertain.

We are also party to various other litigation matters, in most cases involving ordinary and routine claims incidental to our business.

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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.

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. From the date of the combustion event through December 31, 2017, we have recognized $46.9 million of insurance recoveries related to the recovery of mitigation costs and business interruption insurance proceeds.  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 $85.8 million as of March 31, 2018 to secure reclamation and other performance commitments, which are partially secured by $4.5 million of our outstanding letters of credit.

13. Subsequent Event

On April 11, 2018, we announced that our Hillsboro operation will be permanently closed and certain long-lived assets, including mineral reserves, buildings and structures, machinery and equipment, and other related assets are not expected to generate future positive cash flows. As such, we expect to record an aggregate impairment charge between $134 million and $172 million in the second quarter of 2018.  The impairment charge represents the estimated net book value of the certain long-lived assets and other related assets as of March 31, 2018.

On May 8, 2018, we announced a cash distribution of $0.0565 per unit payable to common unitholders.  The distribution is payable on May 31, 2018, for common unitholders of record on May 21, 2018.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

You should read the following discussion and analysis together with the financial statements and the notes thereto included elsewhere in this report. This discussion may contain statements about our business, operations and industry that constitute forward-looking statements. Forward-looking statements involve risks and uncertainties, such as statements regarding our plans, objectives, expectations and intentions. You can identify these forward-looking statements by the use of forward-looking words such as “outlook,” “intends,” “plans,” “estimates,” “believes,” “expects,” “potential,” “continues,” “may,” “will,” “should,” “seeks,” “approximately,” “predicts,” “anticipates,” “foresees,” or the negative version of these words or other comparable words and phrases. Any forward-looking statements contained in this report are based upon our historical performance and on our current plans, estimates and expectations as of the filing date of this report. Our future results and financial condition may differ materially from those we currently anticipate as a result of various factors. Among those factors that could cause actual results to differ materially are the following:

•   The market price for coal;

• The supply of, and demand for, domestic and foreign coal;

• The supply of, and demand for, electricity;

• Competition from other coal suppliers;

• The cost of using, and the availability of, other fuels, including the effects of technological developments;

• Advances in power technologies;

• The efficiency of our mines;

• The amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

• The pricing terms contained in our long-term contracts;

• Cancellation or renegotiation of contracts;

• Legislative, regulatory and judicial developments, including those related to the release of greenhouse gases;

• The strength of the U.S. dollar;

• Air emission, wastewater discharge and other environmental standards for coal-fired power plants or coal mines;

• Changes to free trade agreements, including the imposition of additional customs duties or tariffs;

• Delays in the receipt of, failure to receive, or revocation of, necessary government permits;

• Inclement or hazardous weather conditions and natural disasters;

• Availability and cost or interruption of fuel, equipment and other supplies;

• Transportation costs;

• Availability of transportation infrastructure, including flooding and railroad derailments;

• Technological developments, including those related to alternative energy sources;

• Cost and availability of our coal miners;

• Availability of skilled employees;  

• Work stoppages or other labor difficulties; and

• The receipt of insurance recoveries related to the Hillsboro combustion event.

The above factors should be read in conjunction with the risk factors included in our Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) on March 7, 2018.

Company Overview

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,” “we,” “us,” and “our”), Foresight Reserves and a member of FELLC’s management contributed their ownership interests in FELLC to FELP in exchange for common and subordinated units in FELP. 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 50% ownership of the Partnership’s limited partner units outstanding at that time. On March 28, 2017, Murray Energy acquired an additional 46% voting interest in FEGP, thereby increasing Murray Energy’s voting interest in the FEGP to 80%.

We control over 1.7 billion tons of coal reserves, almost all of which exist in three large, contiguous blocks of coal: two in central Illinois and one in southern Illinois. Since our inception, we have invested significantly in capital expenditures to develop what we believe are industry-leading, geologically similar, low-cost and highly productive mines and related infrastructure. We currently operate under one reportable segment with three operating underground mining complexes in the Illinois Basin. Williamson and Sugar Camp are longwall operations, and Macoupin is currently a continuous miner operation. The Williamson complex operates with one longwall system and Sugar Camp operates with two longwall mining systems.

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Mining operations at Hillsboro have been idle since March 2015 due to a combustion event. In May 2017, we breached the seal and mine rescue teams evaluated the mine. In December 2017, we submitted a re-entry plan to MSHA, which contained a plan for the permanent sealing of the current longwall district of Hillsboro.  In early 2018 the current longwall district was permanently sealed, resulting in certain longwall equipment and other related assets being permanently sealed within and unable to be recovered. As a result, a $42.7 million impairment loss was recognized during 2017. In April 2018, we announced the permanent closure of the Hillsboro complex in which we expect to record an aggregate impairment charge between $134 million and $172 million in the second quarter of 2018.

Our coal is sold to a diverse customer base, including electric utility and industrial companies in the eastern half of the United States as well as internationally (primarily into Europe). We generally sell a majority of our coal to customers at delivery points other than our mines, including, but not limited to, our river terminal on the Ohio River and ports near New Orleans.

Pushdown Accounting

Murray Energy, as the acquirer of FELP through our general partner, had the option to apply pushdown accounting to our stand alone financial statements and elected to do so, therefore, our consolidated financial statements were adjusted to reflect the preliminary purchase accounting adjustments. Due to the application of pushdown accounting, our condensed consolidated financial statements 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 is not material.

As it relates to the results of operations, references to "Successor" are in reference to reporting dates on or after April 1, 2017, and references to "Predecessor" are in reference to reporting dates prior to and including March 31, 2017. While the 2017 Successor period and the 2017 Predecessor period are distinct reporting periods, the effects of the change of control did not have a material impact on the comparability of our results of operations between the periods, unless otherwise noted related to the impact from pushdown accounting.  

Key Metrics

We assess the performance of our business using certain key metrics, which are described below and analyzed on a period-to -period basis. These key metrics include Adjusted EBITDA, production, tons sold, coal sales realization per ton sold, netback to mine realization per ton sold and cash cost per ton sold. Coal sales realization per ton sold is defined as coal sales divided by tons sold. Netback to mine realization per ton sold is defined as coal sales less transportation expense divided by tons sold. Cash cost per ton sold is defined as cost of coal produced (excluding depreciation, depletion and amortization) divided by produced tons sold.

Wedefine AdjustedEBITDAasnetincome(loss)attributableto controllinginterestsbeforeinterest,incometaxes,depreciation, depletion,amortizationandaccretion.AdjustedEBITDAisalsoadjustedforequity-basedcompensation,losses/gains on commodity derivative contracts, settlements of derivative contracts, contract amortization, changes in the fair value of the warrantsandmaterialnonrecurringorotheritems whichmaynotreflectthetrendoffutureresults. As it relates to derivatives, the Adjusted EBITDA calculation removes the total impact of derivative gains/losses on net income (loss) during the period and then adds/deducts to Adjusted EBITDA the aggregate settlements during the period.

Adjusted EBITDA is not a measure of performance defined in accordance with U.S. GAAP. However, management believes that Adjusted EBITDA is useful to investors in evaluating our performance because it is a commonly used financial analysis tool for measuring and comparing companies in our industry in areas of operating performance. Management believes that the disclosure of Adjusted EBITDA offers an additional view of our operations that, when coupled with our U.S. GAAP results and the reconciliation to U.S. GAAP results, provides a more complete understanding of our results of operations and the factors and trends affecting our business. Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income, cash flow from operations, or as a measure of profitability or liquidity under U.S. GAAP. The primary limitation associated with the use of Adjusted EBITDA as compared to U.S. GAAP results are (i) it may not be comparable to similarly titled measures used by other companies in our industry, and (ii) it excludes financial information that some consider important in evaluating our performance. We compensate for these limitations by providing a reconciliation of Adjusted EBITDA to U.S. GAAP results to enable users to perform their own analysis of our operating results.

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Results of Operations

Comparison of Three Months Ended March 31, 2018 (Successor) to Three Months Ended March 31, 2017 (Predecessor)

Coal Sales. The following table summarizes coal sales information during the three months ended March 31, 2018 and 2017 (in thousands, except per ton data).

	(Successor)		(Predecessor)
	Three Months Ended March 31, 2018		Three Months Ended March 31, 2017		Variance
Coal sales	$	238,387	$	227,813	$	10,574		4.6	%
Tons sold		5,240		5,283		(43	)	-0.8	%
Coal sales realization per ton sold(1)	$	45.49	$	43.12	$	2.37		5.5	%
Netback to mine realization per ton sold(2)	$	36.63	$	35.98	$	0.65		1.8	%
(1) - Coal sales realization per ton sold is defined as coal sales divided by tons sold.
(2) - Netback to mine realization per ton sold is defined as coal sales less transportation expense divided by tons sold.

The increase in coal sales revenue from the prior year period was due to slightly lower coal sales volumes offset by higher coal sales realization per ton sold.  Coal sales realization per ton sold for the three months ended March 31, 2018 was higher as compared to the prior year period due to a higher mix of export sales, which experienced more favorable API2 pricing during 2018.

Cost of Coal Produced (Excluding Depreciation, Depletion and Amortization). The following table summarizes cost of coal produced (excluding depreciation, depletion and amortization) information for the three months ended March 31, 2018 and 2017 (in thousands, except per ton data).

	(Successor)		(Predecessor)
	Three Months Ended March 31, 2018		Three Months Ended March 31, 2017		Variance
Cost of coal produced (excluding depreciation,   depletion and amortization)	$	120,570	$	117,762	$	2,808	2.4%
Produced tons sold		5,199		5,165		34	0.7%
Cash cost per ton sold(1)	$	23.19	$	22.80	$	0.39	1.7%
Tons produced		5,667		5,267		400	7.6%
(1) - Cash cost per ton sold is defined as cost of coal produced (excluding depreciation, depletion and amortization) divided by produced tons sold.

The increase in cost of coal produced (excluding depreciation, depletion and amortization) from the prior year period was due to a slight increase in produced tons sold as well as slightly higher royalty expense. The higher royalty expense is a function of which coal reserve lease we currently mine as well as higher coal sales realization per ton. As a result, the overall cash cost per ton sold increased as compared to the prior year period.

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Transportation.Our cost of transportation for the three months ended March 31, 2018 increased $8.7 million, or 23.1%, from the three months ended March 31, 2017 due to a higher percentage of our sales going to the export market during the current year period and the additional transportation and transloading costs associated therewith.

Contract Amortization.During the three months ended March 31, 2018, we recorded an amortization benefit of $1.4 million on the favorable/unfavorable sales and royalty contract assets and liabilities recorded as part of our pushdown accounting.

Depreciation, Depletion and Amortization.  The increase in depreciation, depletion and amortization expense for the three months ended March 31, 2018 compared to the three months ended March 31, 2017 was primarily the result of increased depreciation and depletion expense resulting from recording our assets at estimated fair value from the application of pushdown accounting.

Selling, General and Administrative.  The $1.2 million increase in selling, general and administrative expense for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 was primarily due to the increase in the management services agreement with Marry Energy upon the exercise of the FEGP Option in March 2017.

Loss on Commodity Derivative Contracts.  We recorded a loss on our commodity contracts of $1.5 million for the three months ended March 31, 2017.  We had no open commodity contracts during the three months ended March 31, 2018.

Interest Expense, Net.  Interest expense, net for the three months ended March 31, 2018 decreased $7.7 million as compared to the three months ended March 31, 2017 primarily due to lower effective interest rates on our existing debt and borrowings on our revolving credit facility compared to the interest rates on the indebtedness retired in the March 2017 Refinancing Transactions.

Change in Fair Value of Warrants. The warrants issued as part of our August 2016 debt restructuring (the “August 2016 Restructuring Transactions”) were required to be accounted for as a liability at fair value and revalued at each balance sheet date until the earlier of the exercise of the warrants, their expiration, or until any feature requiring liability treatments expires or is modified. During the three months ended March 31, 2017, a gain of $9.3 million was recorded to adjust the warrants to fair value, which was primarily driven by the increase in the price of our units subsequent to the closing date of the August 2016 Restructuring Transactions. Concurrent with the March 2017 Refinancing Transactions, the establishment of an exchange rate for the conversion of the warrants to a number of common units resulted in the warrants meeting the “indexed to its own stock exception” under ASC 815-40-15-7C; and therefore, the warrant liability was reclassified to partners’ capital and is be remeasured prospectively.

Loss on Extinguishment of Debt. The $95.5 million loss on the early extinguishment of debt recognized during the three months ended March 31, 2017 was due to the incurrence of $57.6 million in make-whole/equity-claw premiums and other costs to retire debt arising from the August 2016 Restructuring Transactions early and the write-off of $37.9 million of unamortized debt discounts and debt issuance costs from the retired debt.

Adjusted EBITDA. Adjusted EBITDA increased $1.0 million from the prior year period due primarily due to higher netback to mine realizations offset by slightly higher cash costs per ton sold and no settlements of commodity derivative contracts during 2018. The table below reconciles net loss to Adjusted EBITDA for the three months ended March 31, 2018 and 2017 (in thousands).

	(Successor)			(Predecessor)
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Net loss	$	(21,569	)	$	(111,184	)
Interest expense, net		35,673			43,380
Depreciation, depletion and amortization		51,420			39,298
Accretion on asset retirement obligations		731			710
Contract amortization		(1,420	)		—
Equity-based compensation		177			318
Loss on commodity derivative contracts		—			1,492
Settlements of commodity derivative contracts		—			3,724
Change in fair value of warrants		—			(9,278	)
Loss on early extinguishment of debt		—			95,510
Adjusted EBITDA	$	65,012		$	63,970

For a discussion on Adjusted EBITDA, please read Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Metrics.”

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Liquidity and Capital Resources

Our primary cash requirements include, but are not limited to, working capital needs, capital expenditures, and debt service costs (interest and principal). The consummation of the March 2017 Refinancing Transactions required us to use more than $100 million of cash; however, the refinancing substantially extended our debt maturities, provided us with operating liquidity through a $170.0 million revolving credit facility (the “Revolving Credit Facility”) and refinanced certain high effective interest rates. As of March 31, 2018, we had $18.6 million of cash on hand, no borrowings under our Revolving Credit Facility, and available borrowing capacity under the Revolving Credit Facility (net of outstanding letters of credit) of $161.0 million.

The Credit Facilities (defined below) resulting from the March 2017 Refinancing Transactions require us to utilize excess cash flows to prepay outstanding borrowings (the “Excess Cash Flow Provisions”), subject to certain exceptions, with:

•75% (which percentage 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 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 Credit Facilities.

We are required to prepay $53.8 million of outstanding borrowings pursuant to the Excess Cash Flow Provisions under the Credit Facilities for the annual period ending December 31, 2017.  The prepayment is payable 95 days after year-end.  Accordingly, this amount has been included in the current portion of long-term debt and capital lease obligations on our condensed consolidated balance sheets as of March 31, 2018.

Our operations are capital intensive, requiring investments to expand, maintain or enhance existing operations and to meet environmental and operational regulations. Our future capital spending will be determined by the board of directors of our general partner. Our capital requirements at this time consist of maintenance capital expenditures. Maintenance capital expenditures are cash expenditures made to maintain our then-current operating capacity or net income as they exist at such time as the capital expenditures are made. Our maintenance capital expenditures can be irregular, causing the amount spent to differ materially from period to period.

Expansion capital expenditures are cash expenditures made to increase, over the long-term, our operating capacity or net income as it exists at such time as the capital expenditures are made. Expansion capital expenditures have declined significantly since early-2015 and no significant expansion capital expenditure plans are currently planned. Future longwall development and the associated expansion capital expenditures will be dependent upon several factors, including permitting, demand, access to capital, equipment availability and the committed sales position at our existing mining operations.

Distributions

The restricted payment provisions in our Credit Facilities are not explicitly restrictive in terms of our ability to pay discretionary distributions. However, the Credit Facilities could require us to utilize a substantial amount of our annual excess cash flow to prepay outstanding borrowings based on satisfaction of specified net secured leverage ratios defined under the Credit Facilities. This excess cash flow provision is therefore currently restrictive to our ability to meaningfully resume distributions in the near term.

Changes in Cash Flows

The following is a summary of cash provided by or used in each of the indicated types of activities:

	(Successor) Three Months Ended March 31, 2018			(Predecessor) Three Months Ended March 31, 2017
	(In Thousands)			(In Thousands)
Net cash provided by operating activities	$	51,706		$	19,650
Net cash used in investing activities	$	(15,753	)	$	(13,785	)
Net cash used in financing activities	$	(19,579	)	$	(108,062	)

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For the three months ended March 31, 2018, net cash provided by operating activities was $51.7 million compared to $19.7million provided by operating activities for the three months ended March 31, 2017. Cash provided by operating activities for the current period, after adjusting for noncash items and the financing costs incurred related to the March 2017 Refinancing Transactions, is primarily a result of various working capital variances.  Significant working capital variances as compared to the prior period included:

• a $23.1 million favorable accrued interest variance as compared to the prior year driven by the timing of interest payments;

• a $24.5 million favorable due from/to affiliates, net variance which is a function of the timing of coal shipments with Murray Energy and its affiliates;

• a $12.0 million unfavorable inventory variance driven by coal inventory build from the beginning of the year;

• a $13.1 million unfavorable accounts receivable variance and a $1.8 million favorable accounts payable variance which is a function of the timing of cash receipts and vendor payments; and

• a $2.0 million favorable variance in accrued expenses and other current liabilities which is a function of the timing of cash receipts and vendor payments.

For the three months ended March 31, 2018, net cash used in investing activities was $15.8 million compared to $13.8 million used in investing activities for the three months ended March 31, 2017.  Cash used in investing activities in the current year period resulted primarily from capital expenditures of $16.5 million compared with $19.9 million during the prior year period.  Cash from investing activities during the prior year period also benefited from $3.5 million in cash proceeds from the early settlement of certain coal derivative contracts and $1.9 million from the sale of property and equipment.

For the three months ended March 31, 2018, net cash used in financing activities was $19.6 million compared to $108.1 million used in financing activities for the three months ended March 31, 2017. Cash used in financing activities in the current year period resulted primarily from $12.6 million in payments on long-term debt and capital lease obligations and $4.5 million in distributions paid to common unitholders.  In the prior year period, cash used in financing activities primarily related to the March 2017 Refinancing Transactions, in which we extinguished our prior debt and issued new debt.  We incurred $57.6 million in costs to extinguish the prior debt and $27.3 million of costs to issue the new debt.  Additionally, the prior year period included cash proceeds of $60.6 million from the issuance of common units to Murray Energy and its affiliates.  

Long-Term Debt and Sale-Leaseback Financing Arrangements

Summary of March 2017 Refinancing Transactions and Additional Murray Energy Investment

On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to FELP in exchange for 9,628,108 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 PIK 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 FELLC (the “Borrower”) and Foresight Energy Finance Corporation (the “Co-Issuer” and together with FELLC, the “Issuers” and certain of the Issuers’ subsidiaries, completed the March 2017 Refinancing Transactions, which were a series of transactions to refinance certain previously outstanding indebtedness. The debt issued was as follows:

• The Issuers issued $425 million aggregate principal amount of Second Lien Senior Secured Notes due 2023 (the “Second Lien Notes due 2023”) and

• The Borrower entered into a new credit agreement (the “New Credit Agreement”) providing for new senior secured first-priority credit facilities (the “Credit Facilities”) consisting of a new senior secured first-priority $825.0 million term loan with a five-year maturity (the “Term Loan due 2022”) and the Revolving Credit Facility, which is 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 Partnership retired the following indebtedness in the March 2017 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 “Exchangeable PIK Notes”) at a redemption price equal to the principal amount thereof, plus accrued and unpaid interest; and

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• 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.

Description of the Credit Facilities

The Term Loan due 2022 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 Credit Facilities bear interest as follows:

•in the case of the Term Loan due 2022, at the Borrower’s option, at (a) LIBOR (subject to a 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 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 Credit Facilities requires scheduled quarterly amortization payments on the Term Loan due 2022 in an aggregate annual amount equal to 1.0% of the original principal amount of the Term Loan due 2022, with the balance to be paid at maturity.

The Credit Facilities require us to prepay outstanding borrowings, subject to certain exceptions, as described under “Liquidity and Capital Resources” above. We may also voluntarily repay outstanding loans under the Credit Facilities at any time, without prepayment premium or penalty, except in connection with a repricing transaction in respect of the Term Loan due 2022, in each case subject to customary “breakage” costs with respect to Eurodollar Rate loans. All obligations under the 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 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 Credit Facilities also contain certain customary affirmative covenants and events of default, including relating to a change of control.

As of March 31, 2018, $816.8 million in principal was outstanding under the Term Loan due 2022 and there were no borrowings outstanding under the Revolving Credit Facility. We are required to prepay $53.8 million of outstanding borrowings pursuant to the Excess Cash Flow Provisions under the Credit Facilities for the annual period ending December 31, 2017.  The prepayment is payable 95 days after year-end.  Accordingly, this amount has been included in the current portion of long-term debt and capital lease obligations on our condensed consolidated balance sheets as of March 31, 2018.

Description of the Second Lien Notes due 2023

On the Closing Date, the Issuers issued $425 million aggregate principal amount of Second Lien Notes due 2023 (the “Notes”) pursuant to an indenture (the “Indenture”), by and among the Issuers, the guarantors party thereto and the trustee. The 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).The Notes were issued at an initial discount of $3.2 million, which is being amortized using the effective interest method over the term of the notes. The obligations under the Notes are unconditionally guaranteed, jointly and severally, on a senior secured second-priority basis by each of the Issuers’ wholly-owned domestic subsidiaries that guarantee the Credit Facilities (which do not include Hillsboro Energy LLC). The Indenture contains certain usual and customary negative covenants and events of default, including related to a change in control.

Prior to April 1, 2020, the Issuers may redeem the 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 Notes at a price equal to 111.50% of the aggregate principal amount of the Notes redeemed with the proceeds from a qualified equity offering, subject to at least 50% of the aggregate principal amount of the 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 Notes redeemed prior to April 1, 2021; (ii) 102.875% of the aggregate principal amount of the 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 Notes redeemed thereafter.

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Longwall Financing Arrangements and Capital Lease Obligations

In November 2014, we entered into a sale-leaseback financing arrangement with a financial institution under which we sold a set of longwall shields and related equipment for $55.9 million and leased the shields back under three individual leases. We account for these leases as capital lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases. Principal and interest payments are due monthly over the five-year terms of the leases. Aggregate termination payments of $2.8 million are due at the end of the lease terms. As of March 31, 2018, $22.6 million was outstanding under these capital lease obligations.

In May 2010, we entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement also provided for financing of loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall equipment. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually in March and September until maturity. Principal is due in semiannual payments through maturity. The maturity date of the 5.555% longwall financing arrangement is September 2019. In addition, on the Closing Date, certain covenants and definitions in the credit agreements and guaranty agreements were conformed to the covenants and definitions in the Credit Facilities. The outstanding balance as of March 31, 2018 was $23.2 million.

In January 2010, we entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement also provided for financing of the loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall equipment. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually in June and December until maturity. Principal is due in semiannual payments through maturity. The maturity date of the 5.78% longwall financing arrangement is June 2019. In addition, on the Closing Date, certain covenants and definitions in the credit agreements and guaranty agreements were conformed to the covenants and definitions in the Credit Facilities. The outstanding balance as of March 31, 2018 was $28.0 million.

Sale-Leaseback Financing Arrangements

In 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP LLC (“WPP”), a subsidiary of Natural Resource Partners LP (“NRP”), 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. The Macoupin financing arrangement had a carrying value of $133.2 million as of March 31, 2018 and an effective interest rate of 14.7%.

In 2012, Sugar Camp sold certain rail facility assets to HOD LLC (“HOD”), a subsidiary of NRP, 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. The Sugar Camp financing arrangement had a carrying value of $67.2 million as of March 31, 2018 and an effective interest rate of 8.4%.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements, including operating leases, coal reserve leases, take-or-pay transportation obligations, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. Liabilities related to these arrangements are generally not reflected in our consolidated balance sheets and, except for the coal reserve leases, take-or-pay transportation obligations and operating leases, we do not expect any material impact on our cash flows, results of operations or financial condition to result from these off-balance sheet arrangements.

From time to time, we use bank letters of credit to secure our obligations for certain contracts and other obligations. At March 31, 2018, we had $11.5 million of letters of credit outstanding, which includes $9.0 million in letters of credit secured by our Revolving Credit Facility.

Regulatory authorities require us to provide financial assurance to secure, in whole or in part, our future reclamation projects. We had outstanding surety bonds with third parties of $85.8 million as of March 31, 2018 to secure reclamation and other performance commitments, which are secured by $4.5 million of our outstanding letters of credit.

Related-Party Transactions

See “Item 1. Financial Statements – Note 9. Related-Party Transactions” of this Quarterly Report on Form 10-Q. See also Part III. “Item 13. Certain Relationships and Related Transactions” in the Annual Report on Form 10-K filed with the SEC on March 7, 2018.

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Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

See “Item 1. Financial Statements – Note 2. New Accounting Standards” of this Quarterly Report on Form 10-Q.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions in certain circumstances that affect amounts reported in the accompanying condensed consolidated financial statements and related footnotes. In preparing these financial statements, we have made our best estimates of certain amounts included in the financial statements. Application of these accounting policies and estimates, however, involves the exercise of judgment and use of assumptions as to future uncertainties, and as a result, actual results could differ from these estimates. In arriving at our critical accounting estimates, factors we consider include how accurate the estimates or assumptions have been in the past, how much the estimates or assumptions have changed and how reasonably likely such change may have a material impact. Our critical accounting policies and estimates are more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report on Form 10-K filed with the SEC on March 7, 2018.  Other than as indicated in this Quarterly Report on Form 10-Q related to the adoption of the new revenue standard, there have been no significant changes to our prior critical accounting policies and estimates subsequent to December 31, 2017, or new accounting pronouncements impacting our results.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks include commodity price risk and interest rate risk, which are disclosed below.

Commodity Price Risk

We have commodity price risk as a result of changes in the market value of our coal. We try to minimize this risk by entering into fixed price coal supply agreements and, from time to time, commodity hedge agreements.

Interest Rate Risk

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At March 31, 2018, of our $1.3 billion in long-term debt and capital lease obligations outstanding, $816.8 million of outstanding borrowings have interest rates that fluctuate based on changes in market interest rates. A one percentage point increase in the interest rates related to our variable interest borrowings would result in an annualized increase in interest expense of approximately $8.2 million.

Item 4. Controls and Procedures.

We evaluated, under the supervision and with the participation of our management, including our chief executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2018. Based on that evaluation, our management, including our chief executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective in ensuring that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to our management to allow timely decisions regarding required disclosure. There were no changes in our internal control over financial reporting during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION.

Item 1. Legal Proceedings.

See Part I. “Item 1. Financial Statements –Note 12, Contingencies,” to the condensed consolidated financial statements included in this report relating to certain legal proceedings, which information is incorporated by reference herein. See also Part I. “Item 3. Legal Proceedings” in our Annual Report on Form 10-K filed with the SEC on March 7, 2018.

Item 1A. Risk Factors.

You should carefully consider the risk factors discussed under Part I. “Item 1A. Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 7, 2018, which risks could have a material adverse effect on our business, financial condition, or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may have a material adverse effect on our business, operations, financial condition or future results.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95.1 of this Form 10-Q.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Foresight Energy LP (f/k/a Foresight Energy Partners LP) (incorporated herein by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 filed on February 2, 2012 (SEC File No. 333-179304)).
3.2	First Amended and Restated Agreement of Limited Partnership of Foresight Energy LP (incorporated herein by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on June 23, 2014 (SEC File No. 001-36503)).
3.3	First Amendment to First Amended and Restated Agreement of Limited Partnership of Foresight Energy LP, dated as of August 30, 2016, entered into by Foresight Energy GP LLC (incorporated herein by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on September 6, 2016 (SEC File No. 001-36503)).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
32.1**	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2012.
32.2**	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2012.
95.1*	Mine Safety Disclosure Exhibit.
101*	Interactive Data File (Form 10-Q for the quarter ended March 31, 2018) filed in XBRL.  The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed”.
*	Filed herewith.
**	Furnished

29

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May 8, 2018.

Foresight Energy LP
By:	Foresight Energy GP LLC,
	its general partner
	/s/ Robert D. Moore
	Robert D. Moore
	President, Chairman of the Board and Chief Executive Officer
	/s/ Jeremy J. Harrison
	Jeremy J. Harrison
	Principal Financial Officer and Chief Accounting Officer

30

EX-31.1

Exhibit 31.1

Certification by Chief Executive Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Robert D. Moore certify that:

1.           I have reviewed this Quarterly Report on Form 10-Q of Foresight Energy LP;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a.            designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.            designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.            evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusion about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.            all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2018

/s/ Robert D. Moore

Robert D. Moore

President, Chairman of the Board and Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification by Chief Financial Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Jeremy J. Harrison certify that:

1.           I have reviewed this Quarterly Report on Form 10-Q of Foresight Energy LP;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a.            designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.            designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.            evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusion about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.            all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2018

/s/ Jeremy J. Harrison

Jeremy J. Harrison

Principal Financial Officer and

Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Foresight Energy LP (the “Partnership”) on Form 10-Q for the quarterly period ended March 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Moore, President, Chief Executive Officer and Chairman of the Board of Foresight Energy GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1)        The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)        The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

By:	/s/ Robert D. Moore
Robert D. Moore
President, Chief Executive Officer and Chairman of the Board
of Foresight Energy GP, LLC

Date:  May 8, 2018

This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Partnership for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section. This certification shall not be deemed incorporated by reference in any filing under the Securities Act or Exchange Act, except to the extent that the Partnership specifically incorporates it by reference. A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Foresight Energy LP (the “Partnership”) on Form 10-Q for the quarterly period ended March 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeremy J. Harrison, Principal Financial Officer and Chief Accounting Officer of Foresight Energy GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1)        The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)        The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

By:	/s/ Jeremy J. Harrison
Jeremy J. Harrison
Principal Financial Officer and Chief Accounting Officer
of Foresight Energy GP, LLC

Date:  May 8, 2018

This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Partnership for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section. This certification shall not be deemed incorporated by reference in any filing under the Securities Act or Exchange Act, except to the extent that the Partnership specifically incorporates it by reference. A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request. 

EX-95.1

Exhibit 95.1

MINE SAFETY DISCLOSURE

Our mine operations are subject to regulation by the Federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”).  MSHA inspects our mines on a regular basis and issues various citations and orders to our operators when its inspectors believe that a violation has occurred under the Mine Act.  We disclose information regarding certain citations and orders issued by MSHA and related assessments and legal actions with respect to our coal mining operations.  In evaluating the below information regarding mine safety and health, investors should take into account factors such as: (i) the number of citations and orders will vary depending on the size of a coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process are often reduced in severity and amount, and are sometimes dismissed or vacated.

Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires issuers to include in periodic reports filed with the Securities and Exchange Commission (“SEC”) certain information relating to citations and orders for violations of standards under the Mine Act.  The following tables disclose information required under the Dodd-Frank Act for the three month period ended March 31, 2018.

Mine Name / MSHA Identification Number	Section 104 S&S Citations Excluding 104(d) Citations /  Orders (#)(1)	Section 104(b) Orders (#)(2)	Section 104(d) Citations and Orders (#)(3)	Section 110(b)(2) Violations (#)(4)	Section 107(a) Orders (#)(5)	Total Dollar Value of MSHA Assessments Proposed in Thousands ($)(6)	Total Number of Mining Related Fatalities (#)(7)	Received Notice of Pattern of Violations Under Section 104(e) (yes/no) (8)	Legal Actions Pending as of Last Day of Period (#)(9)	Legal Actions Initiated During Period (#)(9)	Legal Actions Resolved During Period (#)(9)
Mach No. 1 / 1103141	17	0	1	0	0	$114.92	0	No	9	3	4
MC No. 1 / 1103189	24	0	1	0	0	$65.62	0	No	50	5	4
Deer Run / 1103182	0	0	0	0	0	$0.12	0	No	3	0	0
Shay No. 1 / 1100726	3	0	0	0	0	$13.64	0	No	9	3	2

(1) Mine Act Section 104 citations and orders for alleged violations of mandatory health or safety standards that could significantly and substantially contribute to a coal mine safety or health hazard.  Excludes 104(d) orders.

(2) Mine Act Section 104(b) orders are for alleged failures to totally abate a citation within the period of time specified in the citation.

(3) Mine Act Section 104(d) citations and orders are for an alleged unwarrantable failure to comply with mandatory health or safety standards.

(4) Total number of flagrant violations issued under Section 110(b)(2) of the Mine Act.

(5) Mine Act Section 107(a) orders are for alleged conditions or practices that could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated and result in orders of immediate withdrawal from the area of the mine affected by the condition.

(6) Total dollar value of MSHA assessments proposed during the three months ended March 31, 2018.  These figures do not necessarily relate to the citations or orders issued by MSHA during the current reporting period or to the pending cases reported herein.  Note that these figures represent assessments proposed by MSHA during the three months ended March 31, 2018, including those contested or appealed.

(7) Total number of mining related fatalities during the three months ended March 31, 2018.

(8) Mine Act Section 104(e) written notices are for an alleged pattern of violations of mandatory health or safety standards that could significantly and substantially contribute to a coal mine health or safety hazard.

(9) Any pending legal action before the Federal Mine Safety and Health Review Commission (the “Commission”) involving a coal mine owned and operated by us.  The number of legal actions pending as of March 31, 2018, that fall into each of the following categories is as follows:

Mine Name / MSHA Identification Number	Contests of Citations/ Orders referenced in Subpart B, 29CFR Part 2700	Contests of Proposed Penalties referenced in Subpart C, 29CFR Part 2700		Complaints for compensation referenced in Subpart D, 29CFR Part 2700	Complaints for discharge, discrimination, or interference referenced in Subpart E, 29CFR Part 2700	Applications for temporary relief referenced in Subpart F 29CFR Part 2700	Appeals of judges' decisions or orders to FMSHRC referenced in Subpart H 29CFR Part 2700
		Dockets	Citations and Orders
Mach No. 1 / 1103141	2	5	45	0	0	0	2
MC No. 1 / 1103189	32	16	110	0	1	0	1
Deer Run / 1103182	0	3	6	0	0	0	0
Shay No. 1 / 1100726	0	9	18	0	0	0	0

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 01, 2018
Document And Entity Information [Line Items]
Entity Registrant Name	Foresight Energy LP
Entity Central Index Key	0001540729
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Fiscal Year Focus	2018
Trading Symbol	FELP
Document Fiscal Period Focus	Q1
Common Units
Document And Entity Information [Line Items]
Entity Units Outstanding		79,826,538
Subordinated Units
Document And Entity Information [Line Items]
Entity Units Outstanding		64,954,691

XML

Unaudited Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 18,553	$ 2,179
Accounts receivable	28,611	35,158
Due from affiliates	26,315	37,685
Financing receivables - affiliate	3,200	3,138
Inventories, net	56,557	40,539
Prepaid royalties	1,579	4,000
Deferred longwall costs	19,135	9,520
Other prepaid expenses and current assets	8,579	10,844
Contract-based intangibles	6,145	11,268
Total current assets	168,674	154,331
Property, plant, equipment and development, net	2,340,623	2,378,605
Due from affiliates		947
Financing receivables - affiliate	63,257	64,097
Prepaid royalties, net	1,667	1,250
Other assets	4,432	5,358
Contract-based intangibles	1,721	2,052
Total assets	2,580,374	2,606,640
Current liabilities:
Current portion of long-term debt and capital lease obligations	99,623	109,532
Current portion of sale-leaseback financing arrangements	4,731	4,148
Accrued interest	26,725	13,410
Accounts payable	85,876	76,658
Accrued expenses and other current liabilities	62,684	62,442
Asset retirement obligations	4,416	4,416
Due to affiliates	12,399	13,324
Contract-based intangibles	24,006	28,688
Total current liabilities	320,460	312,618
Long-term debt and capital lease obligations	1,202,956	1,205,000
Sale-leaseback financing arrangements	195,621	196,496
Asset retirement obligations	40,011	39,655
Other long-term liabilities	28,901	32,330
Contract-based intangibles	142,522	144,715
Total liabilities	1,930,471	1,930,814
Limited partners' capital:
Total partners' capital	649,903	675,826
Total liabilities and partners' capital	2,580,374	2,606,640
Common Units
Limited partners' capital:
Total partners' capital	407,018	421,161
Subordinated Units
Limited partners' capital:
Total partners' capital	$ 242,885	$ 254,665

XML

Unaudited Condensed Consolidated Balance Sheets (Parenthetical) - shares shares in Thousands	Mar. 31, 2018	Dec. 31, 2017
Common Units
Capital units, Outstanding	79,827	77,644
Subordinated Units
Capital units, Outstanding	64,955	64,955

XML

Unaudited Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues
Coal sales	$ 238,387
Other revenues	2,339
Total revenues	240,726
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)	120,570
Cost of coal purchased	1,751
Transportation	46,443
Depreciation, depletion and amortization	51,420
Contract amortization	(1,420)
Accretion on asset retirement obligations	731
Selling, general and administrative	7,775
Other operating (income) expense, net	(648)
Operating income	14,104
Other expenses:
Interest expense, net	35,673
Net loss	(21,569)
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units	$ (21,569)
Weighted average limited partner units outstanding - basic and diluted:
Distributions declared per limited partner unit	$ 0.0565
Predecessor
Revenues
Coal sales		$ 227,813
Other revenues		2,581
Total revenues		230,394
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)		117,762
Cost of coal purchased		7,973
Transportation		37,726
Depreciation, depletion and amortization		39,298
Accretion on asset retirement obligations		710
Selling, general and administrative		6,554
Loss on commodity derivative contracts		1,492
Other operating (income) expense, net		451
Operating income		18,428
Other expenses:
Interest expense, net		43,380
Change in fair value of warrants		(9,278)
Loss on early extinguishment of debt		95,510
Net loss		(111,184)
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units		(111,184)
Common Units
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units	$ (9,789)
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	78,846
Common Units | Predecessor
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units		$ (56,259)
Net loss per limited partner unit - basic and diluted		$ (0.85)
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted		66,533
Subordinated Units
Net loss available to limited partner units - basic and diluted:
Net loss available to limited partner units	$ (11,780)
Net loss per limited partner unit - basic and diluted	$ (0.18)
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)
Net loss per limited partner unit - basic and diluted		$ (0.85)
Weighted average limited partner units outstanding - basic and diluted:
Weighted average limited partner units outstanding - basic and diluted		64,955

XML

Unaudited Condensed Consolidated Statement of Partners' Capital - 3 months ended Mar. 31, 2018 - USD ($) $ in Thousands	Total	Common Units	Subordinated Units	Limited Partners Common Units	Limited Partners Subordinated Units
Beginning Balance at Dec. 31, 2017	$ 675,826	$ 421,161	$ 254,665	$ 421,161	$ 254,665
Beginning Balance (in units) at Dec. 31, 2017				77,644,489	64,954,691
Net loss attributable to successor	(21,569)			$ (9,789)	$ (11,780)
Cash distributions	(4,510)			$ (4,510)
Conversion of warrants, net				2,135,493
Equity-based compensation	177			$ 177
Issuance of equity-based awards				46,556
Distribution equivalent rights on LTIP awards	(21)			$ (21)
Ending Balance at Mar. 31, 2018	$ 649,903	$ 407,018	$ 242,885	$ 407,018	$ 242,885
Ending Balance (in units) at Mar. 31, 2018				79,826,538	64,954,691

XML

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities
Net loss	$ (21,569)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	51,420
Amortization of debt discount and deferred issuance costs	655
Contract amortization	(1,420)
Equity-based compensation	177
Changes in operating assets and liabilities:
Accounts receivable	6,547
Due from/to affiliates, net	11,392
Inventories	(12,927)
Prepaid expenses and other assets	(6,424)
Prepaid royalties	2,004
Accounts payable	9,218
Accrued interest	13,315
Accrued expenses and other current liabilities	(1,466)
Other	784
Net cash provided by operating activities	51,706
Cash flows from investing activities
Investment in property, plant, equipment and development	(16,531)
Return of investment on financing arrangements with Murray Energy (affiliate)	778
Net cash used in investing activities	(15,753)
Cash flows from financing activities
Payments on long-term debt and capital lease obligations	(12,608)
Payments on short-term debt	(2,147)
Distributions paid	(4,510)
Other	(314)
Net cash used in financing activities	(19,579)
Net increase (decrease) in cash, cash equivalents, and restricted cash	16,374
Cash, cash equivalents, and restricted cash, beginning of period	2,179
Cash, cash equivalents, and restricted cash, end of period	$ 18,553	$ 14,724
Predecessor
Cash flows from operating activities
Net loss		(111,184)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		39,298
Amortization of debt discount and deferred issuance costs		6,365
Equity-based compensation		318
Loss on commodity derivative contracts		1,492
Settlements of commodity derivative contracts		3,724
Realized gains on coal derivatives included in investing activities		(3,520)
Change in fair value of warrants		(9,278)
Debt extinguishment expense		95,510
Other		1,321
Changes in operating assets and liabilities:
Accounts receivable		19,695
Due from/to affiliates, net		(13,157)
Inventories		(917)
Prepaid expenses and other assets		(5,117)
Prepaid royalties		(241)
Commodity derivative assets and liabilities		(532)
Accounts payable		7,324
Accrued interest		(9,803)
Accrued expenses and other current liabilities		(3,430)
Other		1,782
Net cash provided by operating activities		19,650
Cash flows from investing activities
Investment in property, plant, equipment and development		(19,908)
Return of investment on financing arrangements with Murray Energy (affiliate)		705
Settlement of certain coal derivatives		3,520
Proceeds from sale of property, plant and equipment		1,898
Net cash used in investing activities		(13,785)
Cash flows from financing activities
Net change in borrowings under revolving credit facility		(352,500)
Net change in borrowings under A/R securitization program		7,000
Proceeds from long-term debt and capital lease obligations		1,234,438
Payments on long-term debt and capital lease obligations		(970,721)
Proceeds from issuance of common units to Murray Energy (affiliate)		60,586
Debt extinguishment costs		(57,645)
Debt issuance costs paid		(27,328)
Other		(1,892)
Net cash used in financing activities		(108,062)
Net increase (decrease) in cash, cash equivalents, and restricted cash		(102,197)
Cash, cash equivalents, and restricted cash, beginning of period		116,921
Cash, cash equivalents, and restricted cash, end of period		$ 14,724

XML

Organization, Nature of Business and Basis of Presentation

3 Months Ended

Mar. 31, 2018

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 and its affiliates (“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 (the “March 2017 Refinancing Transactions”), Murray Energy exercised its option (the “FEGP Option”) to acquire an additional 46% voting interest in FEGP from Foresight Reserves and a former member of management pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and a former member of management, 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 Accounting Standards Codification (“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 adjustment of our assets and liabilities to fair value required by pushdown accounting in our consolidated financial statements.

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 owns 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. On April 11, 2018, we announced that our Hillsboro operation will be permanently closed (see Note 13). 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, 2017 included in our Annual Report on Form 10-K filed with the SEC on March 7, 2018. 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, 2018. Intercompany transactions are eliminated in consolidation.

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New Accounting Standards

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

New Accounting Standards

2. New Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (“ASC 606”), that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. We adopted ASC 606 as of January 1, 2018 using the modified retrospective approach; therefore, the comparative information has not been adjusted and continues to be reported under previous revenue recognition guidance.  The adoption did not have a material effect on our financial position and results of operations as the timing of revenue recognition related to coal sales remains consistent between ASC 606 and previous revenue recognition guidance. Additionally, there was no cumulative adjustment to partners’ capital as of January 1, 2018. Refer to Note 3 for the additional financial statement disclosures required by ASC 606.

In November 2016, the FASB issued ASU 2016-18 which clarified the presentation requirements of restricted cash within the statement of cash flows. Under ASU 2016-18, the changes in restricted cash and restricted cash equivalents during the period should be included in the beginning and ending cash and cash equivalents balance reconciliation on the statement of cash flows. When cash, cash equivalents, restricted cash or restricted cash equivalents are presented in more than one line item within the statement of financial position, an entity shall calculate a total cash amount in a narrative or tabular format that agrees to the amount shown on the statement of cash flows. Details on the nature and amounts of restricted cash should also be disclosed. This standard is effective for fiscal years beginning after December 15, 2017, and is to be applied retrospectively. We adopted this update during the first quarter of 2018 and this new guidance to required adjustments to the presentation of our condensed consolidated statement of cash flows. Refer to Note 4 for the additional financial statement disclosures required by this update.

In February 2016, the FASB updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements and related disclosures. We disclosed our future minimum payments on our contractual royalty obligations and operating lease obligations in our Annual Report on Form 10-K filed with the SEC on March 7, 2018 and we will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under the new standard

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Revenue from Contracts with Customers

3 Months Ended

Mar. 31, 2018

Revenue From Contract With Customer [Abstract]

Revenue from Contracts with Customers

3. Revenue from Contracts with Customers

Significant Accounting Policy

Revenue is measured based on consideration specified in a contract with a customer. The Partnership recognizes revenue when it satisfies a performance obligation by transferring control over goods and services to a customer.

Shipping and handling costs (e.g., the application of anti-freezing agents) are accounted for as fulfillment costs. The Partnership includes any fulfillment costs billed to customers in revenue, with the corresponding expenses included in cost of coal produced and transportation.

Nature of Goods and Services

The Partnership’s primary source of revenue is from the sale of coal to domestic and international customers through short-term and long-term coal sales contracts. Coal sales revenue includes the sale to customers of coal produced and, from time to time, the re-sale of coal purchased from third-parties or from one of our affiliates. Performance obligations, consisting of individual tons of coal, are satisfied at a point in time when control is transferred to a customer.  For domestic coal sales, this generally occurs when coal is loaded onto railcars at the mine or onto barges at terminals.  For coal sales to international markets, this generally occurs when coal is loaded onto an ocean vessel.  

The Partnership’s coal sales contracts typically range in length from one to three years, however some agreements have terms of as little as one month. Coal sales contracts generally provide for either a fixed base price or a base price determined by a market index. The base price is subject to quality and weight adjustments. Quality and weight adjustments are recorded as necessary based on coal sales contract specifications as a reduction or increase to coal sales revenue. The coal sales contracts also typically give the customer the option to vary volumes, subject to certain minimums. Coal sales are generally invoiced upon shipment and payment is due from customers within standard industry credit timeframes.  

Disaggregation of Revenue

The following table disaggregates revenue by domestic and international markets:

	(Successor)
	Three Months Ended March 31, 2018
	(In Thousands)
Coal sales - Domestic	$	142,715
Coal sales - International		95,672
Total coal sales	$	238,387

Contract Balances

The following table provides information about balances associated with contracts with customers:

	(Successor)
	March 31, 2018
	(In Thousands)
Receivables - Included in 'Accounts receivable'	$	25,179
Receivables - Included in 'Due from affiliates - current'		20,395
Total contract balances	$	45,574

Contract Costs

The Partnership applies the practical expedient in ASC 340-40-25-4, whereby the Partnership recognizes the incremental costs of obtaining contracts as an expense when incurred if the amortization period of the assets that the Partnership would have recognized is one year or less. These costs are included in selling, general and administrative expenses.

Other Revenues

Other revenues consist primarily of a transport lease and overriding royalty agreements with Murray Energy (see Note 9). These arrangements are accounted for under guidance contained in ASC 310 Receivables, ASC 360 Property, Plant, and Equipment, and ASC 840 Leases and therefore are outside the scope of ASC 606.

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

4. Supplemental Cash Flow Information

The following is supplemental information to the condensed consolidated statement of cash flows (in thousands):

	(Successor)		(Predecessor)
	Three Months Ended March 31, 2018		Three Months Ended March 31, 2017
Supplemental disclosures of non-cash financing activities:
Reclassification of warrant liability to partners' capital	$	—	$	41,888

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the total of the same such amounts shown in the condensed consolidated statement of cash flows (in thousands):

	(Successor)		(Successor)		(Successor)		(Predecessor)
	March 31, 2018		December 31, 2017		March 31, 2017		December 31, 2016
Cash and cash equivalents	$	18,553	$	2,179	$	4,235	$	103,690
Restricted cash - Included in 'Other prepaid expenses and current assets'		—		—		10,489		10,731
Restricted cash - Included in 'Other assets'		—		—		—		2,500
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	18,553	$	2,179	$	14,724	$	116,921

Restricted cash included in other prepaid expenses and current assets were amounts that were required to be temporarily held in a restricted cash account for a short duration related to our trade accounts receivable securitization program. The accounts receivable securitization program terminated in December 2017.  

Restricted cash included in other assets was cash collateral used to secure a letter of credit for one of our surety bond providers. During the three months ended March 31, 2017, the restriction was released.

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Accounts Receivable

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Accounts Receivable

5. Accounts Receivable

Accounts receivable consist of the following:

	(Successor)		(Successor)
	March 31, 2018		December 31, 2017
	(In Thousands)
Trade accounts receivable	$	25,179	$	31,225
Other receivables		3,432		3,933
Total accounts receivable	$	28,611	$	35,158

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Inventories, Net

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Inventories, Net

6. Inventories, Net

Inventories, net consist of the following:

	(Successor)		(Successor)
	March 31, 2018		December 31, 2017
	(In Thousands)
Parts and supplies	$	17,366	$	17,196
Raw coal		3,777		5,577
Clean coal		35,414		17,766
Total inventories	$	56,557	$	40,539

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Property, Plant, Equipment and Development, Net

3 Months Ended

Mar. 31, 2018

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)			(Successor)
	March 31, 2018			December 31, 2017
	(In Thousands)
Land, land rights and mineral rights	$	1,639,980		$	1,639,980
Machinery and equipment		545,570			580,649
Machinery and equipment under capital lease		127,064			127,064
Buildings and structures		221,625			221,625
Development costs		20,450			16,644
Other		3,449			3,449
Property, plant, equipment and development		2,558,138			2,589,411
Less: accumulated depreciation, depletion and amortization		(217,515	)		(210,806	)
Property, plant, equipment and development, net	$	2,340,623		$	2,378,605

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Long-Term Debt and Capital Lease Obligations

3 Months Ended

Mar. 31, 2018

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)			(Successor)
	March 31, 2018			December 31, 2017
	(In Thousands)
Term Loan due 2022	$	816,750		$	818,813
Second Lien Notes due 2023		425,000			425,000
Revolving Credit Facility ($170.0 million capacity)		—			—
5.78% longwall financing arrangement		28,012			28,012
5.555% longwall financing arrangement		23,204			30,937
Capital lease obligations		22,566			25,378
Subtotal - Total long-term debt and capital lease obligations principal outstanding		1,315,532			1,328,140
Unamortized debt discounts		(12,953	)		(13,608	)
Total long-term debt and capital lease obligations		1,302,579			1,314,532
Less: current portion		(99,623	)		(109,532	)
Non-current portion of long-term debt and capital lease obligations	$	1,202,956		$	1,205,000

Term Loan due 2022

The Term Loan due 2022 bears interest at the borrower’s option of (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. The Term Loan due 2022 also requires us to prepay outstanding borrowings (the “Excess Cash Flow Provisions”), subject to certain exceptions. The Excess Cash Flow Provisions are calculated annually and are payable 95 days after year-end.  We are required to prepay $53.8 million of outstanding borrowings under the Excess Cash Flow Provisions for the annual period ending December 31, 2017.  Accordingly, this amount has been included in the current portion of long-term debt and capital lease obligations on our condensed consolidated balance sheets as of March 31, 2018.

Second Lien Notes due 2023

The Second Lien Notes due 2023 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.

Revolving Credit Facility

The Revolving Credit Facility has a total borrowing capacity of $170.0 million and bears interest at the borrower’s option of (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. 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.

As of March 31, 2018, there were no outstanding borrowings under our Revolving Credit Facility and available borrowing capacity under the Revolving Credit Facility, net of outstanding letters of credit of $9.0 million, was $161.0 million.  

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Related-Party Transactions

3 Months Ended

Mar. 31, 2018

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 8, 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 8, 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 (“IDRs”) 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 March 2017 Refinancing Transactions, Murray Energy exercised its FEGP Option to acquire an additional 46% voting interest in FEGP from Foresight Reserves and a former member of management pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and a former member of management, as amended, thereby increasing Murray Energy’s voting interest in FEGP 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 was also a holder of 17,556 of FELP’s outstanding warrants. All outstanding warrants held by Murray Energy were exercised in 2017 and Murray Energy held no outstanding warrants as of March 31, 2018.

Following the exercise of the FEGP Option, certain changes to the operating agreement of FEGP went into effect, pursuant to which Murray Energy is entitled to appoint a majority of the board of directors of FEGP (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. All members of 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 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, FEGP 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 escalations and adjustments for direct costs incurred by FELP, the amount of net expense due to the Manager for the three months ended March 31, 2018 and 2017 was $4.0 million and $2.5 million, respectively.

Murray Energy Transport Lease and Overriding Royalty Agreements

For the three months ended March 31, 2018 and 2017, we recorded other revenues of $1.6 million and $1.6 million, respectively, under the transport lease (the “Transport Lease”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy.  The total remaining minimum payments under the Transport Lease were $83.1 million at March 31, 2018, with unearned income equal to $28.1 million. As of March 31, 2018, the outstanding Transport Lease financing receivable was $55.0 million, of which $3.0 million was classified as current in the condensed consolidated balance sheet.

For the three months ended March 31, 2018 and 2017, we recorded other revenues of $0.7 million and $0.8 million, respectively, under the overriding royalty agreement (the “ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company. The total remaining minimum payments under the ORRA were $29.6 million at March 31, 2018, with unearned income equal to $18.2 million. As of March 31, 2018, the outstanding ORRA financing receivable was $11.4 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 March 31, 2018 and 2017, we purchased $4.1 million and $2.1 million, respectively, in equipment, supplies and rebuild services from affiliates of Murray Energy.  During the three months ended March 31, 2018 and 2017, we provided $0.1 million and $0.1 million, respectively, in equipment, supplies and rebuild services to affiliates of Murray Energy.

From time to time, we purchase and sell coal to Murray Energy and its affiliates to, among other things, meet 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. During the three months ended March 31, 2018 and 2017, we purchased $1.8 million and $8.0 million, respectively of coal from Murray Energy and its affiliates and we sold $85.1 million and $60.7 million, respectively, of coal to Murray Energy and its affiliates, including Javelin.

During the three months ended March 31, 2018 and 2017, we paid Javelin $1.0 million and $0.5 million, respectively, in transportation costs related to certain export sales.

During the three months ended March 31, 2018 and 2017, we also paid Javelin $1.3 million and $0.7 million, respectively, in sales and marketing expenses.

During the three months ended March 31, 2018 and 2017, we earned less than $0.1 million and $0.2 million, respectively, in other revenues for Murray Energy’s usage of our Sitran terminal.

During the three months ended March 31, 2018, we utilized capacity on a Murray Energy transloading contract with a third party, thereby allowing Murray Energy to reduce its exposure to certain contractual liquidated damage charges.  To compensate the Partnership for the reduced contractual liquidated damage charges, Murray Energy reimbursed the Partnership $2.5 million of transportation expenses during the three months ended March 31, 2018.

During the three months ended March 31, 2018, Murray Energy utilized our capacity within our transportation agreement with a third party, thereby allowing us to reduce our exposure to certain contractual liquidated damage charges.  To compensate Murray Energy for our reduced contractual liquidated damage charges, we reimbursed Murray Energy $0.2 million of transportation expenses during the three months ended March 31, 2018.  

From time to time, we also reimburse Murray Energy for costs paid by them on our behalf, including certain insurance premiums.

Reserves Investor Group

The Reserves Investor Group includes Christopher Cline, the Cline Resource and Development Company (“CRDC”), the four trusts established for the benefit of Mr. Cline’s children (the “Cline Trust”), and certain other limited liability companies owned or controlled by individuals with limited partner interests in Foresight Reserves through indirect ownership. Concurrent with and subsequent to the March 2017 Refinancing Transactions, CRDC and the Cline Trust acquired investments in our Term Loan due 2022 and our Second Lien Notes due 2023 on consistent terms as the unaffiliated owners of these notes.

As of March 31, 2018, CRDC owned $9.9 million and $5.0 million of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023, respectively.

As of March 31, 2018, the Cline Trust owned $9.9 million and $20.0 million of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023, respectively. The Cline Trust is also a holder of 17,556 of FELP’s outstanding warrants as of March 31, 2018.

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.

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)		(Successor)
Affiliated Company	Balance Sheet Location	March 31, 2018		December 31, 2017
		(In Thousands)
Murray Energy and affiliated entities (1)	Due from affiliates - current	$	26,315	$	37,685
Total		$	26,315	$	37,685
Murray Energy and affiliated entities	Financing receivables - affiliate - current	$	3,200	$	3,138
Total		$	3,200	$	3,138
Murray Energy and affiliated entities	Due from affiliates - noncurrent	$	—	$	947
Total		$	—	$	947
Murray Energy and affiliated entities	Financing receivables - affiliate - noncurrent	$	63,257	$	64,097
Total		$	63,257	$	64,097
Foresight Reserves and affiliated entities	Prepaid royalties - current and noncurrent	$	1,579	$	4,000
Total		$	1,579	$	4,000
Murray Energy and affiliated entities (1)	Due to affiliates - current	$	11,384	$	11,591
Foresight Reserves and affiliated entities	Due to affiliates - current		1,015		1,733
Total		$	12,399	$	13,324

(1) – Includes amounts due to/from Javelin, a joint venture partially owned by Murray Energy.

A summary of certain expenditures and expenses (revenues) incurred with affiliated entities is as follows for the three months ended  March 31, 2018 and 2017 (in thousands):

	(Successor)			(Predecessor)
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Coal sales – Murray Energy and affiliated entities (including Javelin) (1)	$	(85,082	)	$	(60,749	)
Overriding royalty and lease revenues – Murray Energy and affiliated entities (2)	$	(2,296	)	$	(2,355	)
Terminal revenues - Murray Energy and affiliated entities (2)	$	(44	)	$	(226	)
Royalty expense – NRP and affiliated entities (3) — through April 30, 2017	n/a			$	3,669
Royalty expense – Foresight Reserves and affiliated entities (3)	$	5,387		$	1,521
Loadout services – NRP and affiliated entities (3) — through April 30, 2017	n/a			$	2,134
Transportation services - Murray Energy and affiliated entities (including Javelin) (4)	$	978		$	525
Purchased goods and services – Murray Energy and affiliated entities (5)	$	4,118		$	2,061
Purchased coal - Murray Energy and affiliated entities (6)	$	1,751		$	7,973
Land leases - Foresight Reserves and affiliated entities (3), (4)	$	60		$	57
Sales and marketing expenses - Murray Energy and affiliated entities (including Javelin)(7)	$	1,266		$	692
Management services, net  – Murray Energy and affiliated entities (7)	$	3,983		$	2,547
Sales-leaseback interest expense - NRP and affiliated entities (8) — through April 30, 2017	n/a			$	6,244

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) – Transportation

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

(6) – Cost of coal purchased

(7) – Selling, general and administrative

(8) – Interest expense, net

Transactions with NRP and affiliated entities 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 9, 2017.

We also purchased $3.0 million in mining supplies from an affiliated joint venture under a supply agreement during the three months ended March 31, 2017. This joint venture was no longer an affiliate subsequent to March 31, 2017, due to The Cline Group disposing of its interest in the joint venture.

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Earnings per Limited Partner Unit

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Earnings per Limited Partner Unit

10. Earnings per Limited Partner Unit

We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in ASC 260, Earnings Per Share. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic EPU. In addition to the common and subordinated units, we have also identified the general partner interest and our incentive distribution rights (“IDR”) as participating securities. Under the two-class method, EPU is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The Partnership’s net 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 IDRs 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 IDRs. 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 March 31,									Three Months Ended March 31,
	2018									2017
	Common Units			Subordinated Units			Total			Common Units			Subordinated Units			Total
	(In Thousands, Except Per Unit Data)									(In Thousands, Except Per Unit Data)
Numerator:
Net loss available to limited partner units	$	(9,789	)	$	(11,780	)	$	(21,569	)	$	(56,259	)	$	(54,925	)	$	(111,184	)
Denominator:
Weighted-average units to calculate basic EPU		78,846			64,955			143,801			66,533			64,955			131,488
Less: effect of dilutive securities (1)		—			—			—			—			—			—
Weighted-average units to calculate diluted EPU		78,846			64,955			143,801			66,533			64,955			131,488
Basic net loss per unit	$	(0.12	)	$	(0.18	)	$	(0.15	)	$	(0.85	)	$	(0.85	)	$	(0.85	)
Diluted net loss per unit	$	(0.12	)	$	(0.18	)	$	(0.15	)	$	(0.85	)	$	(0.85	)	$	(0.85	)

(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 March 31, 2018 and 2017, approximately 0.3 million and 0.4 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 142,530 Warrants outstanding as of March 31, 2018, which are convertible into common units at an exchange rate of approximately 13.4 common units of FELP at an exercise price of $0.8531 per common unit, in each case subject to adjustment (see Note 11).

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

11. Fair Value of Financial Instruments

Warrants

In August 2016, FELP issued 516,825 warrants (the “Warrants”) to the unaffiliated owners of previously outstanding debt to purchase an amount of common units. 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.

As a result of a series of transactions related to the March 2017 Refinancing Transactions, 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 subsequent to the March 2017 Refinancing Transactions. As of March 31, 2018, there are 142,530 Warrants outstanding and exercisable into 13.4 common units of FELP at an exercise price of $0.8531 per common unit.

Long-Term Debt

The fair value of long-term debt as of March 31, 2018 and December 31, 2017 was $1,205.1 million and $1,178.1 million, respectively. The fair value of long-term debt was calculated based on (i) quoted prices in markets that are not active and (ii) the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms.  These are considered Level 2 and Level 3 fair value measurements, respectively.

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Contingencies

3 Months Ended

Mar. 31, 2018

Commitments And Contingencies Disclosure [Abstract]

Contingencies

12. Contingencies

In January 2016, WPP LLC (“WPP”), a subsidiary of NRP, a 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 LLC (“HOD”), a subsidiary of NRP filed a complaint in the Circuit Court of Macoupin County, Illinois. As of December 31, 2017, WPP claims it is owed $9.5 million. 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. Macoupin has filed a motion to dismiss the Complaint, which is pending.

In July 2015, we provided notice to WPP declaring a force majeure event at our Hillsboro mine due to a combustion event. As a result of the force majeure event, as of March 31, 2018, we have not made $83.5 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, and WPP has subsequently amended its Complaint. On October 6, 2017, the Circuit Court dismissed many of the claims in the Third Amended Complaint against Hillsboro and the Partnership and other of its subsidiaries. However, WPP was afforded a chance to replead some claims, and WPP’s claim for breach of the royalty agreement will proceed. 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 and interest of 1% per month. A bench trial to resolve the dispute over Hillsboro’s declaration of force majeure is currently set for October 22, 2018.

On April 11, 2018, Hillsboro filed appropriate pleadings to seek a declaratory judgment from the Circuit Court of Montgomery County, Illinois, that the royalty agreement has terminated by its own terms.  Under the royalty agreement, Hillsboro leased certain mineral rights from WPP for a term of 20 years (with the option to renew for additional five-year terms, with a maximum of six terms) or until the date on which all merchantable and mineable coal under the royalty agreement has been mined and removed.  Hillsboro maintains that all merchantable and mineable coal under the royalty agreement was mined and removed as of March 26, 2015, the date on which the last coal was mined and removed under the terms of the royalty agreement.  If the Court agrees that the royalty agreement is terminated, no payments are owed by Hillsboro under the royalty agreement after the date of termination.  Hillsboro’s declaratory judgment action is subject to litigation, the outcome of which remains uncertain.

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.

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. From the date of the combustion event through December 31, 2017, we have recognized $46.9 million of insurance recoveries related to the recovery of mitigation costs and business interruption insurance proceeds.  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 $85.8 million as of March 31, 2018 to secure reclamation and other performance commitments, which are partially secured by $4.5 million of our outstanding letters of credit.

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Subsequent Event

3 Months Ended

Mar. 31, 2018

Subsequent Events [Abstract]

Subsequent Event

13. Subsequent Event

On April 11, 2018, we announced that our Hillsboro operation will be permanently closed and certain long-lived assets, including mineral reserves, buildings and structures, machinery and equipment, and other related assets are not expected to generate future positive cash flows. As such, we expect to record an aggregate impairment charge between $134 million and $172 million in the second quarter of 2018.  The impairment charge represents the estimated net book value of the certain long-lived assets and other related assets as of March 31, 2018.

On May 8, 2018, we announced a cash distribution of $0.0565 per unit payable to common unitholders.  The distribution is payable on May 31, 2018, for common unitholders of record on May 21, 2018.

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New Accounting Standards (Policies)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

New Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (“ASC 606”), that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. We adopted ASC 606 as of January 1, 2018 using the modified retrospective approach; therefore, the comparative information has not been adjusted and continues to be reported under previous revenue recognition guidance.  The adoption did not have a material effect on our financial position and results of operations as the timing of revenue recognition related to coal sales remains consistent between ASC 606 and previous revenue recognition guidance. Additionally, there was no cumulative adjustment to partners’ capital as of January 1, 2018. Refer to Note 3 for the additional financial statement disclosures required by ASC 606.

In November 2016, the FASB issued ASU 2016-18 which clarified the presentation requirements of restricted cash within the statement of cash flows. Under ASU 2016-18, the changes in restricted cash and restricted cash equivalents during the period should be included in the beginning and ending cash and cash equivalents balance reconciliation on the statement of cash flows. When cash, cash equivalents, restricted cash or restricted cash equivalents are presented in more than one line item within the statement of financial position, an entity shall calculate a total cash amount in a narrative or tabular format that agrees to the amount shown on the statement of cash flows. Details on the nature and amounts of restricted cash should also be disclosed. This standard is effective for fiscal years beginning after December 15, 2017, and is to be applied retrospectively. We adopted this update during the first quarter of 2018 and this new guidance to required adjustments to the presentation of our condensed consolidated statement of cash flows. Refer to Note 4 for the additional financial statement disclosures required by this update.

In February 2016, the FASB updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements and related disclosures. We disclosed our future minimum payments on our contractual royalty obligations and operating lease obligations in our Annual Report on Form 10-K filed with the SEC on March 7, 2018 and we will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under the new standard

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Revenue from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2018

Revenue From Contract With Customer [Abstract]

Schedule of Disaggregates Revenue by Domestic and International Markets

The following table disaggregates revenue by domestic and international markets:

	(Successor)
	Three Months Ended March 31, 2018
	(In Thousands)
Coal sales - Domestic	$	142,715
Coal sales - International		95,672
Total coal sales	$	238,387

Schedule of Information About Balances Associated with Contracts with Customers

The following table provides information about balances associated with contracts with customers:

	(Successor)
	March 31, 2018
	(In Thousands)
Receivables - Included in 'Accounts receivable'	$	25,179
Receivables - Included in 'Due from affiliates - current'		20,395
Total contract balances	$	45,574

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

The following is supplemental information to the condensed consolidated statement of cash flows (in thousands):

	(Successor)		(Predecessor)
	Three Months Ended March 31, 2018		Three Months Ended March 31, 2017
Supplemental disclosures of non-cash financing activities:
Reclassification of warrant liability to partners' capital	$	—	$	41,888

Reconciliation of Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the total of the same such amounts shown in the condensed consolidated statement of cash flows (in thousands):

	(Successor)		(Successor)		(Successor)		(Predecessor)
	March 31, 2018		December 31, 2017		March 31, 2017		December 31, 2016
Cash and cash equivalents	$	18,553	$	2,179	$	4,235	$	103,690
Restricted cash - Included in 'Other prepaid expenses and current assets'		—		—		10,489		10,731
Restricted cash - Included in 'Other assets'		—		—		—		2,500
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	18,553	$	2,179	$	14,724	$	116,921

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Accounts Receivable (Tables)

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Schedule of Accounts Receivable

Accounts receivable consist of the following:

	(Successor)		(Successor)
	March 31, 2018		December 31, 2017
	(In Thousands)
Trade accounts receivable	$	25,179	$	31,225
Other receivables		3,432		3,933
Total accounts receivable	$	28,611	$	35,158

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Inventories, Net (Tables)

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Schedule of Inventories, Net

Inventories, net consist of the following:

	(Successor)		(Successor)
	March 31, 2018		December 31, 2017
	(In Thousands)
Parts and supplies	$	17,366	$	17,196
Raw coal		3,777		5,577
Clean coal		35,414		17,766
Total inventories	$	56,557	$	40,539

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Property, Plant, Equipment and Development, Net (Tables)

3 Months Ended

Mar. 31, 2018

Property Plant And Equipment [Abstract]

Schedule of Property, Plant, Equipment and Development, Net

Property, plant, equipment and development, net consist of the following:

	(Successor)			(Successor)
	March 31, 2018			December 31, 2017
	(In Thousands)
Land, land rights and mineral rights	$	1,639,980		$	1,639,980
Machinery and equipment		545,570			580,649
Machinery and equipment under capital lease		127,064			127,064
Buildings and structures		221,625			221,625
Development costs		20,450			16,644
Other		3,449			3,449
Property, plant, equipment and development		2,558,138			2,589,411
Less: accumulated depreciation, depletion and amortization		(217,515	)		(210,806	)
Property, plant, equipment and development, net	$	2,340,623		$	2,378,605

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Long-Term Debt and Capital Lease Obligations (Tables)

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Schedule of Long-Term Debt and Capital Lease Obligations

Long-term debt and capital lease obligations consist of the following:

	(Successor)			(Successor)
	March 31, 2018			December 31, 2017
	(In Thousands)
Term Loan due 2022	$	816,750		$	818,813
Second Lien Notes due 2023		425,000			425,000
Revolving Credit Facility ($170.0 million capacity)		—			—
5.78% longwall financing arrangement		28,012			28,012
5.555% longwall financing arrangement		23,204			30,937
Capital lease obligations		22,566			25,378
Subtotal - Total long-term debt and capital lease obligations principal outstanding		1,315,532			1,328,140
Unamortized debt discounts		(12,953	)		(13,608	)
Total long-term debt and capital lease obligations		1,302,579			1,314,532
Less: current portion		(99,623	)		(109,532	)
Non-current portion of long-term debt and capital lease obligations	$	1,202,956		$	1,205,000

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Related-Party Transactions (Tables)

3 Months Ended

Mar. 31, 2018

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)		(Successor)
Affiliated Company	Balance Sheet Location	March 31, 2018		December 31, 2017
		(In Thousands)
Murray Energy and affiliated entities (1)	Due from affiliates - current	$	26,315	$	37,685
Total		$	26,315	$	37,685
Murray Energy and affiliated entities	Financing receivables - affiliate - current	$	3,200	$	3,138
Total		$	3,200	$	3,138
Murray Energy and affiliated entities	Due from affiliates - noncurrent	$	—	$	947
Total		$	—	$	947
Murray Energy and affiliated entities	Financing receivables - affiliate - noncurrent	$	63,257	$	64,097
Total		$	63,257	$	64,097
Foresight Reserves and affiliated entities	Prepaid royalties - current and noncurrent	$	1,579	$	4,000
Total		$	1,579	$	4,000
Murray Energy and affiliated entities (1)	Due to affiliates - current	$	11,384	$	11,591
Foresight Reserves and affiliated entities	Due to affiliates - current		1,015		1,733
Total		$	12,399	$	13,324

(1) – Includes amounts due to/from Javelin, a joint venture partially owned by Murray Energy.

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  March 31, 2018 and 2017 (in thousands):

	(Successor)			(Predecessor)
	Three Months Ended March 31, 2018			Three Months Ended March 31, 2017
Coal sales – Murray Energy and affiliated entities (including Javelin) (1)	$	(85,082	)	$	(60,749	)
Overriding royalty and lease revenues – Murray Energy and affiliated entities (2)	$	(2,296	)	$	(2,355	)
Terminal revenues - Murray Energy and affiliated entities (2)	$	(44	)	$	(226	)
Royalty expense – NRP and affiliated entities (3) — through April 30, 2017	n/a			$	3,669
Royalty expense – Foresight Reserves and affiliated entities (3)	$	5,387		$	1,521
Loadout services – NRP and affiliated entities (3) — through April 30, 2017	n/a			$	2,134
Transportation services - Murray Energy and affiliated entities (including Javelin) (4)	$	978		$	525
Purchased goods and services – Murray Energy and affiliated entities (5)	$	4,118		$	2,061
Purchased coal - Murray Energy and affiliated entities (6)	$	1,751		$	7,973
Land leases - Foresight Reserves and affiliated entities (3), (4)	$	60		$	57
Sales and marketing expenses - Murray Energy and affiliated entities (including Javelin)(7)	$	1,266		$	692
Management services, net  – Murray Energy and affiliated entities (7)	$	3,983		$	2,547
Sales-leaseback interest expense - NRP and affiliated entities (8) — through April 30, 2017	n/a			$	6,244

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) – Transportation

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

(6) – Cost of coal purchased

(7) – Selling, general and administrative

(8) – Interest expense, net

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Earnings per Limited Partner Unit (Tables)

3 Months Ended

Mar. 31, 2018

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 March 31,									Three Months Ended March 31,
	2018									2017
	Common Units			Subordinated Units			Total			Common Units			Subordinated Units			Total
	(In Thousands, Except Per Unit Data)									(In Thousands, Except Per Unit Data)
Numerator:
Net loss available to limited partner units	$	(9,789	)	$	(11,780	)	$	(21,569	)	$	(56,259	)	$	(54,925	)	$	(111,184	)
Denominator:
Weighted-average units to calculate basic EPU		78,846			64,955			143,801			66,533			64,955			131,488
Less: effect of dilutive securities (1)		—			—			—			—			—			—
Weighted-average units to calculate diluted EPU		78,846			64,955			143,801			66,533			64,955			131,488
Basic net loss per unit	$	(0.12	)	$	(0.18	)	$	(0.15	)	$	(0.85	)	$	(0.85	)	$	(0.85	)
Diluted net loss per unit	$	(0.12	)	$	(0.18	)	$	(0.15	)	$	(0.85	)	$	(0.85	)	$	(0.85	)

(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 March 31, 2018 and 2017, approximately 0.3 million and 0.4 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 142,530 Warrants outstanding as of March 31, 2018, which are convertible into common units at an exchange rate of approximately 13.4 common units of FELP at an exercise price of $0.8531 per common unit, in each case subject to adjustment (see Note 11).

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Organization, Nature of Business and Basis of Presentation - Additional Information (Details) $ in Millions			3 Months Ended
	Mar. 28, 2017 USD ($)	Jun. 23, 2014	Mar. 31, 2018 segment MiningComplex	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
Predecessor | 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%
Predecessor | 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
Predecessor | Foresight Energy LLC | Foresight Reserves, LP
Schedule Of Organization Nature Of Business And Basis Of Presentation [Line Items]
Ownership percentage prior		99.333%
Predecessor | Foresight Energy LLC | Member of Management
Schedule Of Organization Nature Of Business And Basis Of Presentation [Line Items]
Ownership percentage prior		0.667%

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New Accounting Standards - Additional Information (Details)	Jan. 01, 2018 USD ($)
ASU 2014-09
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Cumulative adjustment to partners’ capital	$ 0

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Revenue from Contracts with Customers - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018
Minimum
Disaggregation Of Revenue [Line Items]
Coal sales contract term	1 year
Maximum
Disaggregation Of Revenue [Line Items]
Coal sales contract term	3 years
Recognized amortization period of assets	1 year

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Revenue from Contracts with Customers - Schedule of Disaggregates Revenue by Domestic and International Markets (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($)
Disaggregation Of Revenue [Line Items]
Total coal sales	$ 238,387
Domestic
Disaggregation Of Revenue [Line Items]
Total coal sales	142,715
International
Disaggregation Of Revenue [Line Items]
Total coal sales	$ 95,672

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Revenue from Contracts with Customers - Schedule of Information About Balances Associated with Contracts with Customers (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Disaggregation Of Revenue [Line Items]
Receivables - Included in 'Accounts receivable'	$ 28,611	$ 35,158
Receivables - Included in 'Due from affiliates - current'	26,315	$ 37,685
Revenue from Contracts with Customers
Disaggregation Of Revenue [Line Items]
Receivables - Included in 'Accounts receivable'	25,179
Receivables - Included in 'Due from affiliates - current'	20,395
Total contract balances	$ 45,574

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Supplemental Cash Flow Information - Supplemental Cash Flow Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($)
Predecessor
Supplemental disclosures of non-cash financing activities:
Reclassification of warrant liability to partners' capital	$ 41,888

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Supplemental Cash Flow Information - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Cash and cash equivalents	$ 18,553	$ 2,179	$ 4,235
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$ 18,553	$ 2,179	14,724
Predecessor
Cash and cash equivalents				$ 103,690
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows			14,724	116,921
Other Prepaid Expenses and Current Assets
Restricted cash			$ 10,489
Other Prepaid Expenses and Current Assets | Predecessor
Restricted cash				10,731
Other Assets | Predecessor
Restricted cash				$ 2,500

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Supplemental Cash Flow Information - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018
Trade Accounts Receivable Securitization Program
Supplemental Cash Flow Information [Line Items]
Termination period	2017-12

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Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Receivables [Abstract]
Trade accounts receivable	$ 25,179	$ 31,225
Other receivables	3,432	3,933
Total accounts receivable	$ 28,611	$ 35,158

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Inventories, Net - Schedule of Inventories, Net (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Inventory [Line Items]
Parts and supplies	$ 17,366	$ 17,196
Total inventories	56,557	40,539
Raw coal
Inventory [Line Items]
Coal	3,777	5,577
Clean coal
Inventory [Line Items]
Coal	$ 35,414	$ 17,766

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Property, Plant, Equipment and Development, Net (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Property Plant And Equipment [Abstract]
Land, land rights and mineral rights	$ 1,639,980	$ 1,639,980
Machinery and equipment	545,570	580,649
Machinery and equipment under capital lease	127,064	127,064
Buildings and structures	221,625	221,625
Development costs	20,450	16,644
Other	3,449	3,449
Property, plant, equipment and development	2,558,138	2,589,411
Less: accumulated depreciation, depletion and amortization	(217,515)	(210,806)
Property, plant, equipment and development, net	$ 2,340,623	$ 2,378,605

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Long-Term Debt and Capital Lease Obligations (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Capital lease obligations	$ 22,566,000	$ 25,378,000
Subtotal - Total long-term debt and capital lease obligations principal outstanding	1,315,532,000	1,328,140,000
Unamortized debt discounts	(12,953,000)	(13,608,000)
Total long-term debt and capital lease obligations	1,302,579,000	1,314,532,000
Less: current portion	(99,623,000)	(109,532,000)
Long-term debt and capital lease obligations	1,202,956,000	1,205,000,000
Term Loan due 2022
Debt Instrument [Line Items]
Long-term debt	816,750,000	818,813,000
Second Lien Notes due 2023
Debt Instrument [Line Items]
Long-term debt	425,000,000	425,000,000
5.78% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt	28,012,000	28,012,000
5.555% longwall financing arrangement
Debt Instrument [Line Items]
Long-term debt	23,204,000	$ 30,937,000
Revolving Credit Facility ($170.0 Million capacity)
Debt Instrument [Line Items]
Revolving Credit Facility	$ 0

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Long-Term Debt and Capital Lease Obligations (Parenthetical) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Term Loan due 2022
Debt Instrument [Line Items]
Debt instrument maturity year	2022
Second Lien Notes due 2023
Debt Instrument [Line Items]
Debt instrument maturity year	2023
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%
Revolving Credit Facility ($170.0 Million capacity)
Debt Instrument [Line Items]
Maximum borrowings capacity under credit facility	$ 170,000,000

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Long-Term Debt and Capital Lease Obligations - Term Loan Due 2022 - Additional Information (Details) - Term Loan due 2022 - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Excess cash Flow provisions calculated after year end	95 days
Prepayments of outstanding borrowings under excess cash flow provisions		$ 53.8
Minimum
Debt Instrument [Line Items]
Debt instrument, LIBOR floor rate	1.00%
LIBOR
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility	5.75%
Base Rate
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility	4.75%

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Long-Term Debt and Capital Lease Obligations - Second Lien Notes Due 2023 - Additional Information (Details) - Second Lien Notes due 2023	3 Months Ended
	Mar. 31, 2018
Debt Instrument [Line Items]
Debt instrument maturity date	Apr. 01, 2023
Debt instrument interest percentage	11.50%
Debt instrument interest payable description	The Second Lien Notes due 2023 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.
Debt instrument frequency of periodic interest payment	semi-annually

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Long-Term Debt and Capital Lease Obligations - Revolving Credit Facility - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018 USD ($)
Revolving Credit Facility ($170.0 Million capacity)
Debt Instrument [Line Items]
Maximum borrowings capacity under credit facility	$ 170,000,000
Revolving credit facility	0
Letters of credit outstanding amount	9,000,000
Line of credit facility current borrowing capacity	$ 161,000,000
Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Debt instrument, LIBOR floor rate	0.00%
Revolving Credit Facility | Minimum | LIBOR
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility	5.25%
Revolving Credit Facility | Minimum | Base Rate
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility	4.25%
Revolving Credit Facility | Maximum | LIBOR
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility	5.50%
Revolving Credit Facility | Maximum | Base Rate
Debt Instrument [Line Items]
Interest rate on borrowings under credit facility	4.50%

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Related-Party Transactions - Additional Information (Details) $ in Thousands				1 Months Ended	3 Months Ended			9 Months Ended	11 Months Ended
		Mar. 28, 2017 USD ($)	Mar. 27, 2017 USD ($) shares	Apr. 30, 2015 USD ($)	Mar. 31, 2018 USD ($) Trust Renewal $ / T shares		Mar. 31, 2017 USD ($)	Sep. 30, 2017	Mar. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($) shares	Apr. 16, 2015
Related Party Transaction [Line Items]
Class of Warrant or Right, Outstanding | shares					142,530				142,530
Financing receivables - affiliates					$ 3,200				$ 3,200	$ 3,138
Cost of coal purchased					1,751
Coal sales					238,387
Reimbursement of transportation expenses					2,500
Term Loan due 2022
Related Party Transaction [Line Items]
Long-term debt					816,750				816,750	$ 818,813
Transport and Overriding Royalty Agreements
Related Party Transaction [Line Items]
Other revenues					1,600		$ 1,600
Total remaining minimum payments of transportation lease					83,100				83,100
Unearned income from financing leasing services					28,100
Outstanding financing receivable					55,000				55,000
Financing receivables - affiliates					3,000				3,000
ORRA
Related Party Transaction [Line Items]
Other revenues					700		800
Outstanding financing receivable					11,400				11,400
Financing receivables - affiliates					200				200
Remaining minimum payments under agreement					29,600				29,600
Unearned income under agreement					$ 18,200				$ 18,200
Reserves Investor Group
Related Party Transaction [Line Items]
Number of trusts established | Trust					4
Predecessor
Related Party Transaction [Line Items]
Proceeds from common unit issuance to Murray Energy (affiliate)							60,586
Cost of coal purchased							7,973
Coal sales							227,813
Murray Energy Transaction | Predecessor
Related Party Transaction [Line Items]
Proceeds from sale of voting interest				$ 1,370,000
Percentage of outstanding limited partner units issued				50.00%							50.00%
Proceeds from common unit issuance to Murray Energy (affiliate)			$ 60,600
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					$ 100		200
Purchase of equipment, supplies and rebuild services					4,118	[1]	2,100
Cost of coal purchased					1,751	[2]	8,000
Coal sales					85,100		60,700
Reimbursement of transportation expenses					$ 200
Murray Energy And Affiliated Entities | Predecessor
Related Party Transaction [Line Items]
Purchase of equipment, supplies and rebuild services	[1]						2,061
Cost of coal purchased	[2]						7,973
Foresight Energy GP Limited Liability Company | Murray Energy Transaction | Predecessor
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
Foresight Energy Limited Liability IDRS | Murray Energy Transaction
Related Party Transaction [Line Items]
Class of Warrant or Right, Outstanding | shares					0				0	17,556
Foresight Energy Limited Liability IDRS | Murray Energy Transaction | Predecessor
Related Party Transaction [Line Items]
Issuance of common units (in units) | shares			9,628,108
Percentage of voting interests acquired				77.50%
Manager
Related Party Transaction [Line Items]
Management and administration services, quarterly payment					$ 5,000
Management and administration services, annual payment					20,000
Manager | Murray Energy Management Services Agreement
Related Party Transaction [Line Items]
Management and administration expenses, net					4,000
Manager | Predecessor
Related Party Transaction [Line Items]
Management and administration services, quarterly payment				$ 3,500
Management and administration services, annual payment				$ 14,000
Manager | Predecessor | Murray Energy Management Services Agreement
Related Party Transaction [Line Items]
Management and administration expenses, net							2,500
Manager
Related Party Transaction [Line Items]
Purchase of equipment, supplies and rebuild services					100		100
Javelin
Related Party Transaction [Line Items]
Payments for transportation costs for certain export sales					1,000		500
Payments for sales and marketing costs					1,300		700
Cline Resource and Development Company (“CRDC”) | Reserves Investor Group | Term Loan due 2022
Related Party Transaction [Line Items]
Long-term debt					9,900				$ 9,900
Cline Resource and Development Company (“CRDC”) | Reserves Investor Group | Second Lien Notes due 2023
Related Party Transaction [Line Items]
Long-term debt					$ 5,000				$ 5,000
Cline Trust Company LLC | Reserves Investor Group
Related Party Transaction [Line Items]
Class of Warrant or Right, Outstanding | shares					17,556				17,556
Cline Trust Company LLC | Reserves Investor Group | Term Loan due 2022
Related Party Transaction [Line Items]
Long-term debt					$ 9,900				$ 9,900
Cline Trust Company LLC | Reserves Investor Group | Second Lien Notes due 2023
Related Party Transaction [Line Items]
Long-term debt					$ 20,000				$ 20,000
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%
Affiliated Joint Venture | Predecessor
Related Party Transaction [Line Items]
Purchase of mining supplies from affiliates							$ 3,000

[1] Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment and development, net, as applicable

[2] Cost of coal purchased

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Related-Party Transactions - Summary of Certain Affiliate Amounts Included in Condensed Consolidated Balance Sheets (Details) - USD ($) $ in Thousands		Mar. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Due from affiliates - current		$ 26,315	$ 37,685
Financing receivables - affiliate - current		3,200	3,138
Due from affiliates - noncurrent			947
Financing receivables - affiliate - noncurrent		63,257	64,097
Prepaid royalties - current and noncurrent		1,579	4,000
Due to affiliates - current		12,399	13,324
Murray Energy And Affiliated Entities | Affiliates
Related Party Transaction [Line Items]
Due from affiliates - current	[1]	26,315	37,685
Financing receivables - affiliate - current		3,200	3,138
Due from affiliates - noncurrent			947
Financing receivables - affiliate - noncurrent		63,257	64,097
Due to affiliates - current	[1]	11,384	11,591
Foresight Reserves and Affiliated Entities | Affiliates
Related Party Transaction [Line Items]
Prepaid royalties - current and noncurrent		1,579	4,000
Due to affiliates - current		$ 1,015	$ 1,733

[1] Includes amounts due to/from Javelin, a joint venture partially owned by Murray Energy.

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Related-Party Transactions - Summary of Certain Expenditures and Expenses (Revenues) Incurred With Affiliated Entities (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018		Mar. 31, 2017
Related Party Transaction [Line Items]
Purchased coal		$ 1,751
Predecessor
Related Party Transaction [Line Items]
Purchased coal				$ 7,973
Murray Energy and Affiliated Entities (Including Javelin)
Related Party Transaction [Line Items]
Coal sales	[1]	(85,082)
Transportation services	[2]	978
Sales and marketing expenses	[3]	1,266
Murray Energy and Affiliated Entities (Including Javelin) | Predecessor
Related Party Transaction [Line Items]
Coal sales	[1]			(60,749)
Transportation services	[2]			525
Sales and marketing expenses	[3]			692
Murray Energy And Affiliated Entities
Related Party Transaction [Line Items]
Overriding royalty and lease revenues	[4]	(2,296)
Terminal revenues	[4]	(44)
Purchased goods and services		4,118	[5]	2,100
Purchased coal		1,751	[6]	8,000
Management services, net	[3]	3,983
Murray Energy And Affiliated Entities | Predecessor
Related Party Transaction [Line Items]
Overriding royalty and lease revenues	[4]			(2,355)
Terminal revenues	[4]			(226)
Purchased goods and services	[5]			2,061
Purchased coal	[6]			7,973
Management services, net	[3]			2,547
NRP and Affiliated Entities | Predecessor
Related Party Transaction [Line Items]
Royalty expense	[7]			3,669
Loadout services	[7]			2,134
Sales-leaseback interest expense	[8]			6,244
Foresight Reserves and Affiliated Entities
Related Party Transaction [Line Items]
Royalty expense	[7]	5,387
Land leases	[2],[7]	$ 60
Foresight Reserves and Affiliated Entities | Predecessor
Related Party Transaction [Line Items]
Royalty expense	[7]			1,521
Land leases	[2],[7]			$ 57

[1] Coal sales

[2] Transportation

[3] Selling, general and administrative

[4] Other revenues

[5] Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment and development, net, as applicable

[6] Cost of coal purchased

[7] Cost of coal produced (excluding depreciation, depletion and amortization)

[8] Interest expense, net

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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
	Mar. 31, 2018	Mar. 31, 2017
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units	$ (21,569)
Weighted-average units to calculate basic EPU	143,801
Weighted-average units to calculate diluted EPU	143,801
Basic net loss per unit	$ (0.15)
Diluted net loss per unit	$ (0.15)
Common Units
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units	$ (9,789)
Weighted-average units to calculate basic EPU	78,846
Weighted-average units to calculate diluted EPU	78,846
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	$ (11,780)
Weighted-average units to calculate basic EPU	64,955
Weighted-average units to calculate diluted EPU	64,955
Basic net loss per unit	$ (0.18)
Diluted net loss per unit	$ (0.18)
Predecessor
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units		$ (111,184)
Weighted-average units to calculate basic EPU		131,488
Weighted-average units to calculate diluted EPU		131,488
Basic net loss per unit		$ (0.85)
Diluted net loss per unit		$ (0.85)
Predecessor | Common Units
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units		$ (56,259)
Weighted-average units to calculate basic EPU		66,533
Weighted-average units to calculate diluted EPU		66,533
Basic net loss per unit		$ (0.85)
Diluted net loss per unit		$ (0.85)
Predecessor | Subordinated Units
Distribution Made To Limited Partner [Line Items]
Net loss available to limited partner units		$ (54,925)
Weighted-average units to calculate basic EPU		64,955
Weighted-average units to calculate diluted EPU		64,955
Basic net loss per unit		$ (0.85)
Diluted net loss per unit		$ (0.85)

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Earnings per Limited Partner Unit - Summary of Partnership's Calculation of Net Loss per Common and Subordinated Unit (Parenthetical) (Details) - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Class of Warrant or Right, Outstanding	142,530
Warrant exchange rate for common units	13.4
Exercise price of the warrants	$ 0.8531
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		400,000

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Fair Value of Financial Instruments - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Aug. 31, 2016	Mar. 31, 2018	Dec. 31, 2017
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Warrants outstanding		142,530
Warrant exchange rate for common units		13.4
Exercise price of the warrants		$ 0.8531
Fair value of Long-Term Debt		$ 1,205.1	$ 1,178.1
Unaffiliated Owners | Predecessor
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Warrants issued	516,825

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Contingencies - Additional Information (Details)		3 Months Ended	12 Months Ended
	Apr. 11, 2018 Term	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jan. 31, 2016 USD ($)
Loss Contingencies [Line Items]
Minimum deficiency payment not made		$ 83,500,000
Insurance recoveries			$ 46,900,000
Estimated insurance recoveries		0
Outstanding performance bonds		85,800,000
Surety Bond
Loss Contingencies [Line Items]
Outstanding letters of credit		$ 4,500,000
Macoupin
Loss Contingencies [Line Items]
Possible loss contingencies			$ 9,500,000
Hillsboro Energy, LLC
Loss Contingencies [Line Items]
Potentially additional fees and interest rate per month		1.00%
Hillsboro Energy, LLC | Subsequent Event
Loss Contingencies [Line Items]
Mineral rights lease term	20 years
Mineral rights option to renew lease term	5 years
Mineral rights maximum lease term | Term	6
Predecessor | Macoupin
Loss Contingencies [Line Items]
Possible loss contingencies				$ 3,300,000

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Subsequent Event - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	May 08, 2018	Jun. 30, 2018	Mar. 31, 2018
Subsequent Event [Line Items]
Cash distribution, announced per unit payable			$ 0.0565
Common Units | Subsequent Event
Subsequent Event [Line Items]
Cash distribution, announcement date	May 08, 2018
Cash distribution, announced per unit payable	$ 0.0565
Cash distribution, payable date	May 31, 2018
Cash distribution, record date	May 21, 2018
Scenario Forecast | Minimum
Subsequent Event [Line Items]
Aggregate impairment charge		$ 134
Scenario Forecast | Maximum
Subsequent Event [Line Items]
Aggregate impairment charge		$ 172