Foresight Energy (FELPQ) 10-Q 2019 Q2 Quarterly report

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 June 30, 2019

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common units representing limited partner interests	FELP	New York Stock Exchange (“NYSE”)

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 every Interactive Data File required to be submitted 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 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  ☐
		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 August 1, 2019, the registrant had 80,939,221 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 Statements 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	22
Item 3.Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.Controls and Procedures	31
PART II
OTHER INFORMATION
Item 1.Legal Proceedings	32
Item 1A.Risk Factors	32
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3.Defaults Upon Senior Securities	32
Item 4.Mine Safety Disclosures	32
Item 5.Other Information	32
Item 6. Exhibits	33
Signatures	34

2

PART I – FINANCIAL INFORMATION.

Item 1. Financial Statements.

Foresight Energy LP

Unaudited Condensed Consolidated Balance Sheets

(In Thousands)

	June 30,		December 31,
	2019		2018
Assets
Current assets:
Cash and cash equivalents	$	2,982	$	269
Accounts receivable		27,327		32,248
Due from affiliates		43,897		49,613
Financing receivables - affiliate		3,527		3,392
Inventories, net		84,688		56,524
Prepaid royalties - affiliate		—		2,000
Deferred longwall costs		23,850		14,940
Other prepaid expenses and current assets		8,256		10,872
Contract-based intangibles		795		1,326
Total current assets		195,322		171,184
Property, plant, equipment and development, net		2,113,473		2,148,569
Financing receivables - affiliate		58,907		60,705
Prepaid royalties, net		6,933		2,678
Other assets		11,995		4,311
Contract-based intangibles		363		726
Total assets	$	2,386,993	$	2,388,173
Liabilities and partners’ capital
Current liabilities:
Current portion of long-term debt and finance lease obligations	$	11,028	$	53,709
Current portion of sale-leaseback financing arrangements		7,080		6,629
Accrued interest		19,063		24,304
Accounts payable		126,596		99,735
Accrued expenses and other current liabilities		66,533		67,466
Asset retirement obligations		6,578		6,578
Due to affiliates		20,648		17,740
Contract-based intangibles		7,509		8,820
Total current liabilities		265,035		284,981
Long-term debt and finance lease obligations		1,271,813		1,194,394
Sale-leaseback financing arrangements		187,066		189,855
Asset retirement obligations		39,959		38,966
Other long-term liabilities		17,583		16,428
Contract-based intangibles		63,729		66,834
Total liabilities		1,845,185		1,791,458
Limited partners' capital:
Common unitholders (80,939 and 80,844 units outstanding as of June 30, 2019 and December 31, 2018, respectively)		347,617		377,880
Subordinated unitholder (64,955 units outstanding as of June 30, 2019 and December 31, 2018)		194,191		218,835
Total partners' capital		541,808		596,715
Total liabilities and partners' capital	$	2,386,993	$	2,388,173

See accompanying notes.

3

Foresight Energy LP

Unaudited Condensed Consolidated Statements of Operations

(In Thousands, Except per Unit Data)

	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
Revenues:
Coal sales	$	224,488		$	269,992		$	491,825		$	508,379
Other revenues		2,428			1,430			4,163			3,769
Total revenues		226,916			271,422			495,988			512,148
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)		122,216			136,982			256,197			257,552
Cost of coal purchased		2,090			3,906			4,465			5,657
Transportation		49,790			59,034			108,624			105,477
Depreciation, depletion and amortization		43,244			55,312			89,792			106,732
Contract amortization and write-off		(1,836	)		(70,424	)		(3,522	)		(71,844	)
Accretion on asset retirement obligations		552			559			1,103			1,290
Selling, general and administrative		8,008			10,534			16,655			18,309
Long-lived asset impairments		—			110,689			—			110,689
Other operating (income) expense, net		(94	)		(42,983	)		(161	)		(43,631	)
Operating income		2,946			7,813			22,835			21,917
Other expenses
Interest expense, net		36,618			37,035			73,328			72,708
Net loss	$	(33,672	)	$	(29,222	)	$	(50,493	)	$	(50,791	)
Net loss available to limited partner units - basic and diluted:
Common unitholders	$	(18,681	)	$	(14,090	)	$	(25,849	)	$	(23,879	)
Subordinated unitholder	$	(14,991	)	$	(15,132	)	$	(24,644	)	$	(26,912	)
Net loss per limited partner unit - basic and diluted:
Common unitholders	$	(0.23	)	$	(0.18	)	$	(0.32	)	$	(0.30	)
Subordinated unitholder	$	(0.23	)	$	(0.23	)	$	(0.38	)	$	(0.41	)
Weighted average limited partner units outstanding - basic and diluted:
Common units		80,939			79,842			80,927			79,347
Subordinated units		64,955			64,955			64,955			64,955
Distributions declared per limited partner unit	$	—		$	0.0565		$	0.0600		$	0.1130

See accompanying notes.

4

Foresight Energy LP

Unaudited Condensed Consolidated Statements 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
Balance at January 1, 2019	$	377,880			80,844,319	$	218,835			64,954,691	$	596,715
Net loss		(7,168	)		—		(9,653	)		—		(16,821	)
Cash distributions		(4,856	)		—		—			—		(4,856	)
Conversion of warrants, net		—			10,087		—			—		—
Equity-based compensation		233			—		—			—		233
Issuance of equity-based awards		—			84,815		—			—		—
Distribution equivalent rights on LTIP awards		(25	)		—		—			—		(25	)
Balance at March 31, 2019	$	366,064			80,939,221	$	209,182			64,954,691	$	575,246
Net loss		(18,681	)		—		(14,991	)		—		(33,672	)
Equity-based compensation		234			—		—			—		234
Balance at June 30, 2019	$	347,617			80,939,221	$	194,191			64,954,691	$	541,808

	Limited Partners
	Common			Number of		Subordinated			Number of		Total Partners'
	Unitholders			Common Units		Unitholder			Subordinated Units		Capital
Balance at January 1, 2018	$	421,161			77,644,489	$	254,665			64,954,691	$	675,826
Net loss		(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	)
Balance at March 31, 2018	$	407,018			79,826,538	$	242,885			64,954,691	$	649,903
Net loss		(14,090	)		—		(15,132	)		—		(29,222	)
Cash distributions		(4,510	)		—		—			—		(4,510	)
Conversion of warrants, net		—			94,527		—			—		—
Equity-based compensation		175			—		—			—		175
Distribution equivalent rights on LTIP awards		(18	)		—		—			—		(18	)
Balance at June 30, 2018	$	388,575			79,921,065	$	227,753			64,954,691	$	616,328

See accompanying notes.

5

Foresight Energy LP

Unaudited Condensed Consolidated Statements of Cash Flows

(In Thousands)

	Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
Cash flows from operating activities
Net loss	$	(50,493	)	$	(50,791	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		89,792			106,732
Amortization of debt discount		1,419			1,326
Contract amortization and write-off		(3,522	)		(71,844	)
Accretion on asset retirement obligations		1,103			1,290
Equity-based compensation		467			352
Long-lived asset impairments		—			110,689
Insurance proceeds included in investing activities		—			(42,947	)
Changes in operating assets and liabilities:
Accounts receivable		4,921			7,916
Due from/to affiliates, net		8,624			309
Inventories		(20,817	)		(3,327	)
Prepaid expenses and other assets		(4,723	)		(5,050	)
Prepaid royalties		(2,255	)		3,154
Accounts payable		26,861			11,423
Accrued interest		(5,241	)		10,848
Accrued expenses and other current and long-term liabilities		(5,616	)		2,007
Other		352			201
Net cash provided by operating activities		40,872			82,288
Cash flows from investing activities
Investment in property, plant, equipment and development		(62,043	)		(32,228	)
Return of investment on financing arrangements with Murray Energy (affiliate)		1,663			1,539
Insurance proceeds		—			42,947
Net cash (used in) provided by investing activities		(60,380	)		12,258
Cash flows from financing activities
Borrowings under revolving credit facility		89,000			50,000
Payments on revolving credit facility		(13,000	)		(15,000	)
Payments on long-term debt and finance lease obligations		(42,681	)		(78,633	)
Distributions paid		(4,856	)		(9,020	)
Payments on sale-leaseback and short-term financing arrangements		(6,242	)		(5,312	)
Net cash provided by (used in) financing activities		22,221			(57,965	)
Net increase in cash and cash equivalents		2,713			36,581
Cash and cash equivalents, beginning of period		269			2,179
Cash and cash equivalents, end of period	$	2,982		$	38,760

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. 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, Murray Energy acquired an additional 46% voting interest in FEGP, thereby increasing Murray Energy’s voting interest in FEGP to 80%.

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”); Macoupin Energy, LLC (“Macoupin”); and Hillsboro Energy, LLC (“Hillsboro”). Mining operations at our Hillsboro complex had been idled since March 2015 due to a combustion event (the “Hillsboro Combustion Event”). In January 2019, we resumed production and development activities at our Hillsboro complex with one continuous miner unit.  Our mined coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern half of the United States, as well as overseas markets.

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, 2018 included in our Annual Report on Form 10-K filed with the SEC on February 27, 2019. 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, 2019. Intercompany transactions are eliminated in consolidation.

2. New Accounting Standards

In February 2016, the FASB updated guidance regarding the accounting for leases (the “New Lease Guidance”). The New Lease Guidance 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 New Lease Guidance also expands the required quantitative and qualitative disclosures surrounding leases. The New Lease Guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years.

We adopted the New Lease Guidance as of January 1, 2019 using a modified retrospective transition approach for leases existing at, or entered into after, the adoption date.  Under this transition approach, comparative information for periods prior to January 1, 2019 is not adjusted. Upon adoption, we elected the package of practical expedients permitted under the New Lease Guidance, which allows for the carry forward of historical lease classification.  We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements.   

The adoption of the New Lease Guidance resulted in the addition of $7.6 million in lease right-of-use assets and lease liabilities on our consolidated balance sheet at January 1, 2019. The adoption of the New Lease Guidance did not have a material effect on our results of operations and had no impact on cash flows. Additionally, there was no cumulative adjustment to partners’ capital. Refer to Note 13 for the additional financial statement disclosures required by the New Lease Guidance.

7

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 as reductions to the corresponding expenses included in cost of coal produced and transportation expense.

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 may 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:

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(In Thousands)
Coal sales - Domestic	$	131,212	$	146,682	$	272,161	$	289,397
Coal sales - International		93,276		123,310		219,664		218,982
Total coal sales	$	224,488	$	269,992	$	491,825	$	508,379

Contract Balances

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

	June 30, 2019		December 31, 2018
	(In Thousands)
Receivables - Included in 'Accounts receivable'	$	23,454	$	27,521
Receivables - Included in 'Due from affiliates'		36,197		42,234
Total contract balances	$	59,651	$	69,755

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.

8

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 842 Leases and therefore are outside the scope of ASC 606.

4. Supplemental Cash Flow Information

The following is supplemental information to the condensed consolidated statement of cash flows:

	Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(In Thousands)
Supplemental disclosures of non-cash investing activities:
Depreciation, depletion and amortization capitalized into development costs	$	6,383	$	—
Short-term insurance financing	$	1,202	$	985

5. Accounts Receivable

Accounts receivable consist of the following:

	June 30, 2019		December 31, 2018
	(In Thousands)
Trade accounts receivable	$	23,454	$	27,521
Other receivables		3,873		4,727
Total accounts receivable	$	27,327	$	32,248

6. Inventories, Net

Inventories, net consist of the following:

	June 30, 2019		December 31, 2018
	(In Thousands)
Parts and supplies	$	17,646	$	16,665
Raw coal		4,456		6,919
Clean coal		62,586		32,940
Total inventories	$	84,688	$	56,524

7. Property, Plant, Equipment and Development, Net

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

	June 30, 2019			December 31, 2018
	(In Thousands)
Land, land rights and mineral rights	$	1,638,853		$	1,631,939
Machinery and equipment		619,046			589,113
Machinery and equipment under finance leases		127,064			127,064
Buildings and structures		226,193			223,111
Development costs		70,214			41,717
Other		3,449			3,449
Property, plant, equipment and development		2,684,819			2,616,393
Less: accumulated depreciation, depletion and amortization		(571,346	)		(467,824	)
Property, plant, equipment and development, net	$	2,113,473		$	2,148,569

9

8. Long-Term Debt and Finance Lease Obligations

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

	June 30, 2019			December 31, 2018
	(In Thousands)
Term Loan due 2022	$	743,286		$	762,906
Second Lien Notes due 2023		425,000			425,000
Revolving Credit Facility ($170.0 million capacity)		113,000			37,000
5.78% longwall financing arrangement		—			9,338
5.555% longwall financing arrangement		3,110			10,845
Finance lease obligations		7,918			13,906
Subtotal - Total long-term debt and finance lease obligations principal outstanding		1,292,314			1,258,995
Unamortized debt discounts		(9,473	)		(10,892	)
Total long-term debt and finance lease obligations		1,282,841			1,248,103
Less: current portion		(11,028	)		(53,709	)
Non-current portion of long-term debt and finance lease obligations	$	1,271,813		$	1,194,394

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.  During the three months ended June 30, 2019, we prepaid $19.6 million of outstanding borrowings under the Excess Cash Flow Provisions for the annual period ended December 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 June 30, 2019, there was $113.0 million in outstanding borrowings under our Revolving Credit Facility and available borrowing capacity under the Revolving Credit Facility, net of outstanding letters of credit of $12.3 million, was $44.7 million.

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9. Related-Party Transactions

Overview

Affiliated entities of FELP principally include: (a) Murray Energy, owner of a 80% interest in our general partner, owner of all of the outstanding subordinated limited partner units, and owner of approximately 12% of the outstanding common limited partner units and (b) Foresight Reserves, its affiliates, and other entities owned and controlled by the estate of Chris Cline, the former majority owner and former chairman of our general partner. We routinely engage in transactions in the normal course of business with Murray Energy 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, land purchases, and sale-leaseback financing arrangements. We also acquire mining equipment from subsidiaries of Murray Energy.

Limited Partnership Agreement

FEGP manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. Murray Energy and Foresight Reserves have the right to select the directors of the general partner. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to reelection by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership’s business. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses incurred or payments made by the general partner on behalf of the Partnership. No amounts were incurred by the general partner or reimbursed under the partnership agreement from the IPO date to June 30, 2019.

Transactions with Murray Energy and Affiliates

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 (currently $5.2 million per quarter as of June 30, 2019).

Murray Energy Transport Lease and Overriding Royalty Agreements

In April 2015, American Century Transport LLC (“American Transport”), a subsidiary of the Partnership, entered into a purchase and sale agreement (the “PSA”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, pursuant to which American Energy sold to American Transport certain mining and transportation assets for $63.0 million. Concurrent with the PSA, American Transport entered into a lease agreement (the “Transport Lease”) with American Energy pursuant to which (i) American Transport leased to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at American Energy’s Century Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport receives from American Energy a fee ranging from $1.15 to $1.75 for every ton of coal mined, processed and/or transported using such assets, subject to a quarterly recoupable minimum fee of $1.7 million for an initial term of fifteen years. The Transport Lease is being accounted for as a direct financing lease.  The total remaining minimum payments under the Transport Lease was $74.5 million at June 30, 2019, with unearned income equal to $23.2 million. The unearned income is reflected as other revenue over the term of the lease using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned. As of June 30, 2019, the outstanding Transport Lease financing receivable was $51.3 million, of which $3.3 million was classified as current in the consolidated balance sheet.

Also, in April 2015, American Century Minerals LLC (“American Century Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement (“ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company (collectively, “AEC”), pursuant to which AEC granted to American Century Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The ORRA is subject to a minimum recoupable quarterly fee of $0.5 million and has an initial term of eighteen years. This overriding royalty was accounted for as a financing arrangement.  The total remaining minimum payments under the ORRA was $27.2 million at June 30, 2019, with unearned income equal to $16.0 million. The payments

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the Partnership receives with respect to the ORRA are reflected partially as a return of the initial investment (reduction in the affiliate financing receivable) and partially as other revenue over the life of the agreement using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned.  As of June 30, 2019, the outstanding ORRA financing receivable was $11.2 million, of which $0.3 million was classified as current in the consolidated balance sheet.

Coals Sales and Purchases with Murray Energy and Affiliates

We sell coal to Javelin Global Commodities (“Javelin”), which is an international commodities marketing and trading joint venture owned by Murray Energy, Uniper (formerly E.ON Global Commodities SE), and management of Javelin. We incur sales and marketing expenses on export sales to Javelin.  In addition, we are responsible for transportation costs on certain export sales to Javelin.  

From time to time, we also purchase and sell coal to Murray Energy and its affiliates to, among other things, meet each of our customer contractual obligations.

Murray Energy Transportation Arrangements

Murray Energy may transport coal under our transportation agreement with a third-party rail company, resulting in usage fees owed to the third-party rail company by the Partnership.  These usage fees are billed to Murray Energy, resulting in no impact to our consolidated statements of operations. The usage of the railway line with this third-party rail company by Murray Energy counts towards the minimum annual throughput volumes with the third-party rail company, thereby reducing the Partnership’s exposure to contractual liquidated damage charges.  There were no usage fees during the three and six months ended June 30, 2019 and 2018, respectively.

We have an arrangement with Murray Energy whereby 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 damages, Murray Energy reimbursed the Partnership $1.8 million and $2.1 million for the three months ended June 30, 2019 and 2018, respectively, and $3.7 million and $4.6 million for the six month ended June 30, 2019 and 2018, respectively. The amounts are included in transportation on the consolidated statements of operations.

Similarly, we have an arrangement in which Murray Energy utilized capacity within our transportation network, thereby reducing our exposure to certain contractual liquidated damage charges. No capacity was utilized during the three and six months ended June 30, 2019.  To compensate Murray Energy for our reduced contractual liquidated damages, we reimbursed Murray Energy $0.9 million and $1.1 million for the three and six months ended June 30, 2018, respectively. The amounts are included in transportation on the consolidated statements of operations.

We earn terminal revenues for Murray Energy’s occasional usage of our Sitran transloading facility.

Other Murray Energy Transactions

We regularly purchase equipment, supplies, rebuild, and other services from affiliates of Murray Energy. On occasion, our subsidiaries provide similar services to affiliates of Murray Energy.  

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

Transactions with Foresight Reserves and Affiliates

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.

Other Foresight Reserves Transactions

We are party to two surface leases in relation to the coal preparation plant and rail loadout facility at Williamson with New River Royalty, a subsidiary of Foresight Reserves. The primary terms of the leases expire on October 15, 2021, but may be extended by New

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River Royalty for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases.

We are party to a surface lease at our Sitran terminal with New River Royalty. The annual lease amount is $50,000 and the primary term of the lease expires on December 31, 2020, but it may be extended at the election of Sitran for successive five year periods.

We are also party to various land easements and similar agreements with New River Royalty with varying terms and renewal options. Annual lease amounts on these arrangements are not significant individually or in aggregate.

In January 2019, we purchased two tracts of land from New River Royalty for total consideration of $6.1 million.

Reserves Investor Group

The Reserves Investor Group includes the estate of 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 certain refinancing transactions in March 2017, 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 June 30, 2019, CRDC owned $9.9 million and $29.1 million of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023, respectively.

As of June 30, 2019, the Cline Trust owned $9.9 million of the outstanding principal on our Term Loan due 2022. The Cline Trust is also a holder of 17,556 of FELP’s outstanding warrants as of June 30, 2019.

Beginning in 2019, we are party to an agreement with an affiliate of the Reserves Investor Group in which we receive royalties based on certain methane gas sales. Royalty revenues on this arrangement were not significant during the three and six months ended June 30, 2019.  

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

Affiliated Company	Balance Sheet Location	June 30, 2019		December 31, 2018
		(In Thousands)
Murray Energy and affiliated entities (1)	Due from affiliates - current	$	43,897	$	49,613
Murray Energy and affiliated entities	Financing receivables - affiliate - current	$	3,527	$	3,392
Murray Energy and affiliated entities	Financing receivables - affiliate - noncurrent	$	58,907	$	60,705
Foresight Reserves and affiliated entities	Prepaid royalties - affiliate - current	$	—	$	2,000
Murray Energy and affiliated entities (1)	Due to affiliates - current	$	16,462	$	15,924
Foresight Reserves and affiliated entities	Due to affiliates - current		4,186		1,816
Total - Due to affiliates - current		$	20,648	$	17,740

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

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A summary of (income) expenses incurred with affiliated entities is as follows for the three and six months ended June 30, 2019 and 2018:

	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(In Thousands)						(In Thousands)
Transactions with Murray Energy and Affiliated Entities (including Javelin)
Coal sales (1)	$	(111,858	)	$	(121,328	)	$	(253,370	)	$	(206,410	)
Purchased coal (6)	$	2,090		$	3,906		$	4,465		$	5,657
Transport Lease revenues (2)	$	(1,784	)	$	(1,005	)	$	(2,999	)	$	(2,599	)
ORRA revenues (2)	$	(644	)	$	(426	)	$	(1,164	)	$	(1,127	)
Terminal revenues (2)	$	—		$	—		$	—		$	(44	)
Transportation services on certain export sales (4)	$	2,683		$	1,829		$	4,994		$	2,807
Sales and marketing expenses (7)	$	1,339		$	1,647		$	3,407		$	2,913
Goods and services purchased (5)	$	1,353		$	4,981		$	3,125		$	9,099
Goods and services provided (8)	$	(47	)	$	(100	)	$	(72	)	$	(100	)
Management services (7)	$	4,429		$	4,287		$	8,714		$	8,270
Transactions with Foresight Reserves and Affiliated Entities
Royalty expense (3)	$	10,938		$	10,724		$	17,445		$	16,111
Land leases (3), (4)	$	29		$	70		$	111		$	130

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, net, as applicable

(6) – Cost of coal purchased

(7) – Selling, general and administrative

(8) – Other operating (income) expense, net

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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:

	Three Months Ended June 30,									Three Months Ended June 30,
	2019									2018
	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	$	(18,681	)	$	(14,991	)	$	(33,672	)	$	(14,090	)	$	(15,132	)	$	(29,222	)
Denominator:
Weighted-average units to calculate basic EPU		80,939			64,955			145,894			79,842			64,955			144,797
Plus: effect of dilutive securities (1)		—			—			—			—			—			—
Weighted-average units to calculate diluted EPU		80,939			64,955			145,894			79,842			64,955			144,797
Basic net loss per unit	$	(0.23	)	$	(0.23	)	$	(0.23	)	$	(0.18	)	$	(0.23	)	$	(0.20	)
Diluted net loss per unit	$	(0.23	)	$	(0.23	)	$	(0.23	)	$	(0.18	)	$	(0.23	)	$	(0.20	)

(1) Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three months ended June 30, 2019 and 2018, approximately 0.4 million and 0.3 million phantom units, respectively, were anti-dilutive, and therefore excluded from the diluted EPU calculation. Diluted EPU also is not impacted during any period by the Warrants (defined in Note 11) outstanding.

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The following table illustrates the Partnership’s calculation of net loss per common and subordinated unit for the six month periods indicated:

	Six Months Ended June 30,									Six Months Ended June 30,
	2019									2018
	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	$	(25,849	)	$	(24,644	)	$	(50,493	)	$	(23,879	)	$	(26,912	)	$	(50,791	)
Denominator:
Weighted-average units to calculate basic EPU		80,927			64,955			145,882			79,347			64,955			144,302
Plus: effect of dilutive securities (1)		—			—			—			—			—			—
Weighted-average units to calculate diluted EPU		80,927			64,955			145,882			79,347			64,955			144,302
Basic net loss per unit	$	(0.32	)	$	(0.38	)	$	(0.35	)	$	(0.30	)	$	(0.41	)	$	(0.35	)
Diluted net loss per unit	$	(0.32	)	$	(0.38	)	$	(0.35	)	$	(0.30	)	$	(0.41	)	$	(0.35	)

(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 six months ended June 30, 2019 and 2018, approximately 0.4 million and 0.3 million phantom units, respectively, were anti-dilutive, and therefore excluded from the diluted EPU calculation. Diluted EPU also is not impacted during any period by the Warrants (defined in Note 11) outstanding.

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 refinancing transactions in March 2017, 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. Therefore, the Warrants are no longer remeasured to fair value. As of June 30, 2019, there are 50,480 Warrants outstanding and exercisable into 14.3 common units of FELP at an exercise price of $0.7983 per common unit.

Long-Term Debt

The fair value of long-term debt as of June 30, 2019 and December 31, 2018 was $954.4 million and $1,166.6 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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12. Contingencies

Litigation Matters

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

We cannot reasonably estimate the ultimate legal and financial liability with respect to all pending litigation matters. However, we believe, based on our examination of such matters, that the ultimate liability will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  As of June 30, 2019, we have $1.3 million accrued, in aggregate, for various litigation matters.

Insurance Recoveries

We are currently in discussions with our insurance providers in regards to further potential recoveries under our policy related to the Hillsboro Combustion Event. From the date of the Hillsboro Combustion Event through June 30, 2019, we have recognized $91.0 million of insurance recoveries related to the recovery of mitigation costs, losses on machinery and equipment, 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 $96.8 million as of June 30, 2019 to secure reclamation and other performance commitments.

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13. Leases

Lease Overview

The Partnership leases certain mineral reserves. The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The lease agreements typically require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. Certain of these minimum royalties are recoupable against production royalties over a contractually defined period of time (typically five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments.

The Partnership also leases surface rights, water rights, barge fleeting rights, rail cars, mining equipment, and office space under lease agreements of varying expiration dates with affiliated entities and independent third parties in the normal course of business.  These leases generally require fixed regular payments based upon the specified agreements.  Certain of these leases provide for the option to renew and / or purchase of the underlying asset at various times during the life of the lease, generally at its then-fair market value.  In situations in which it is reasonably certain that the option to renew will be exercised, the Partnership includes the renewal period in the calculation of lease right-of-use asset and lease liability.  The discount rates used in determining the lease right-of-use assets and lease liabilities are based upon an average rate of interest that the Partnership would have to pay to borrow on a collateralized basis over a similar term.    

Leases	Balance Sheet Location	June 30, 2019
		(In Thousands)
Assets
Operating lease right-of-use assets	Other assets	$	6,141
Operating lease right-of-use assets - affiliate	Other assets		1,912
Finance lease right-of-use assets (1)	Property, plant, equipment, and development, net		51,053
Total lease right-of-use assets		$	59,106
Liabilities
Current:
Operating lease liabilities	Accrued expenses and other current liabilities	$	3,144
Operating lease liabilities - affiliate	Accrued expenses and other current liabilities		174
Finance lease liabilities	Current portion of long-term debt and finance lease obligations		7,918
Non-current:
Operating lease liabilities	Other long-term liabilities		2,997
Operating lease liabilities - affiliate	Other long-term liabilities		1,738
Finance lease liabilities	Long-term debt and finance lease obligations		—
Total lease liabilities		$	15,971

(1) Finance lease right-of-use assets are recorded net of accumulated amortization of $76.0 million as of June 30, 2019.

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Lease Cost	Statement of Operations Location	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
		(In Thousands)
Operating lease cost (2)	Cost of coal produced (excluding depreciation, depletion and amortization); Transportation; Selling, general and administrative	$	949	$	2,093
Operating lease cost - affiliate	Cost of coal produced (excluding depreciation, depletion and amortization); Transportation		29		111
Variable operating lease cost (1)	Cost of coal produced (excluding depreciation, depletion and amortization)		2,192		4,792
Finance lease cost:
Amortization of right-of-use assets	Depreciation, depletion and amortization		3,602		7,204
Interest on lease liabilities	Interest expense, net		134		310
Total lease cost		$	6,906	$	14,510

(1) Variable operating lease cost consists primarily of contingent rental payments related to the rail loadout facility at Williamson Energy.  We pay contingent rental fees, net of a fixed per ton amount received for maintaining the facility, on each ton of coal passed through the rail loadout facility.

(2) Includes any short-term lease cost and sublease income, which are not material.

Lease Terms and Discount Rates	June 30, 2019
Weighted-average remaining lease term (years)
Operating leases		5.5
Operating leases - affiliate		19.3
Finance leases		0.4
Weighted-average discount rate
Operating leases		7.00	%
Operating leases - affiliate		7.00	%
Finance leases		5.81	%

Other Information	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(In Thousands)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	884	$	1,942
Operating cash flows from operating leases - affiliate		6		62
Operating cash flows from finance leases		145		329
Financing cash flows from finance leases		3,015		5,989
Lease assets obtained in exchange for new operating lease liabilities		558		1,928

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The following presents future minimum lease payments, by year, with initial terms greater than one year, as of June 30, 2019:

	Operating Leases			Operating Leases – Affiliate			Finance Leases			Total
	(In Thousands)
2019 (remaining)	$	1,955		$	112		$	8,060		$	10,127
2020		2,202			175			—			2,377
2021		1,179			175			—			1,354
2022		231			176			—			407
2023		231			176			—			407
Thereafter		1,739			2,676			—			4,415
Total lease payments		7,537			3,490			8,060			19,087
Less: interest		(1,396	)		(1,578	)		(142	)		(3,116	)
Total lease liabilities	$	6,141		$	1,912		$	7,918		$	15,971

Sale-Leaseback Financing Arrangements

Macoupin Energy Sale-Leaseback Financing Arrangement

In January 2009, Macoupin entered into a sales agreement with WPP, LLC (“WPP”) and HOD, LLC (“HOD”) (subsidiaries of Natural Resource Partners LP (“NRP”)) to sell certain mineral reserves and rail facility assets (the “Macoupin Sales Arrangement”). Macoupin received $143.5 million in cash in exchange for certain mineral reserve and transportation assets. Simultaneous with the closing, Macoupin entered into a lease with WPP for mining the mineral reserves (the “Mineral Reserves Lease”) and with HOD for the use of the rail loadout and rail loop (the “Macoupin Rail Loadout Lease” and the “Rail Loop Lease,” respectively). The Mineral Reserves Lease is a 20-year noncancelable lease that contains renewal elections for six additional five-year terms. The Macoupin Rail Loadout Lease and the Rail Loop Lease are 99 year noncancelable leases. Under the Mineral Reserves Lease, Macoupin makes monthly payments equal to the greater of $5.40 per ton or 8.00% of the sales price, plus $0.60 per ton for each ton of coal sold from the leased mineral reserves, subject to a minimum royalty of $4.0 million per quarter through December 31, 2028. After the initial 20-year term, the annual minimum royalty is $10,000 per year. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty under the Mineral Reserves Lease and tonnage fees paid under the Macoupin Rail Loadout and Rail Loop Leases discussed below exceed $4.0 million, Macoupin may generally recoup any unrecouped quarterly payments made during the preceding 20 quarters on a first paid, first recouped basis. The Macoupin Rail Loadout Lease and Rail Loop Lease require an aggregate payment of $3.00 ($1.50 for the rail loop facility and $1.50 for the rail load-out facility) for each ton of coal loaded through the facility for the first 30 years, up to 3.4 million tons per year. After the initial 30-year term, Macoupin would pay an annual rental payment of $20,000 per year for usage of the rail loadout and rail loop. The Macoupin Sales Arrangement, Mineral Reserves Lease, Macoupin Rail Loadout Lease and Rail Loop Lease are collectively accounted for as a financing arrangement (the “Macoupin Sale-Leaseback”). This financing arrangement is recourse to Macoupin and not recourse to Foresight Energy LP or any of its other subsidiaries.

At June 30, 2019 and December 31, 2018, the carrying value of the Macoupin Sale-Leaseback was $130.4 million and $131.4 million, respectively. The effective interest rate on the financing obligation was 14.8% and 14.8% as of June 30, 2019 and December 31, 2018, respectively. Interest expense was $4.3 million and $4.6 million for the three months ended June 30, 2019 and 2018, respectively, and $8.9 million and $9.1 million for the six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019 and December 31, 2018, interest of $0.8 million and $0.5 million, respectively, was accrued in the condensed consolidated balance sheets for the Macoupin Sale-Leaseback.

Sugar Camp Energy Sale-Leaseback Financing Arrangement

In March 2012, Sugar Camp entered into a sales agreement with HOD for which it received a total of $50.0 million in cash in exchange for certain rail loadout assets (“Sugar Camp Sales Agreement”). Simultaneous with the closing, Sugar Camp entered into a lease transaction with HOD for the use of the rail loadout (the “Sugar Camp Rail Loadout Lease”). The Sugar Camp Rail Loadout Lease is a 20-year noncancelable lease that contains renewal elections for 16 additional five-year terms. Under the Sugar Camp Rail Loadout Lease, Sugar Camp will pay a monthly royalty of $1.10 per ton for every ton of coal mined from specified reserves and loaded through the rail loadout. The royalty is subject to adjustment based on the time it takes for Sugar Camp to complete each longwall move. The royalty payments are subject to a minimum payment amount of $1.3 million per quarter for the first twenty years the lease is in effect. After the initial 20-year term, Sugar Camp would pay an annual rental payment of $10,000 per year. To the extent the minimum payment exceeds amounts owed based on actual coal loaded, the excess is recoupable within two years of payment. The Sugar Camp Sales Agreement and Sugar Camp Rail Loadout Lease are collectively accounted for as a financing arrangement (the “Sugar Camp Sale-Leaseback”).

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At June 30, 2019 and December 31, 2018, the carrying value of the Sugar Camp Sale-Leaseback was $63.8 million and $65.1 million, respectively. The effective interest rate on the financing, which is derived from the timing and tons of coal to be mined as set forth in the current mine plan and the related cash payments, was 8.1% and 8.1% at June 30, 2019 and December 31, 2018, respectively. Interest expense was $1.1 million and $1.2 million for the three months ended June 30, 2019 and 2018, respectively, and $2.4 million and $2.6 million for the six months ended June 30, 2019 and 2018, respectively. As of June 30, 2019 and December 31, 2018, interest of $0.1 million and $0.2 million, respectively, was accrued in the consolidated balance sheets for the Sugar Camp Sale-Leaseback.

Sale-Leaseback Maturity Tables

The following summarizes the maturities of expected principal payments, based on current mine plans, on the Partnership’s sale-leaseback financing arrangements and the associated accrued interest at June 30, 2019:

	Sale-Leaseback Financing Arrangements		Accrued Interest
	(In Thousands)
2019 (remaining)	$	4,131	$	904
2020		6,357		—
2021		7,634		—
2022		9,056		—
2023		9,977		—
Thereafter		156,991		—
Total	$	194,146	$	904

The aggregate amounts of remaining minimum lease payments on the Partnership’s sale-leaseback financing arrangements are $215.8 million. Minimum payments from June 30, 2019 through 2023 are as follows:

	2019 (remaining)		2020		2021		2022		2023
Minimum lease payments	$	10,500	$	21,000	$	21,000	$	21,000	$	21,000

Murray Energy Transport Lease and Overriding Royalty Agreements

Refer to Note 9 for information and disclosures related to the Transport Lease and the ORRA.

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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 February 27, 2019.

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,” the “Partnership”, “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 nearly 2.1 billion tons of coal reserves (including 322 million tons of coal reserves associated with our Hillsboro complex), 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 four underground mining complexes in the Illinois Basin. Williamson and Sugar Camp are longwall operations, with the Williamson complex operating one longwall system and the Sugar Camp complex operating two longwall mining systems.  Macoupin and

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Hillsboro are currently continuous miner operations.  Prior to the combustion event, Hillsboro operated with one longwall mining system.

Mining operations at Hillsboro were idle since March 2015 due to a combustion event. In October 2018, we reached a settlement of various litigation matters arising from the combustion event.  In January 2019, we resumed production and development activities at Hillsboro with one continuous miner unit.  We continue to evaluate our future options at Hillsboro.

Our coal is sold to a diverse customer base, including electric utility and industrial companies in the eastern half of the United States and internationally. We generally sell a significant portion 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, Louisiana and Mobile, Alabama.

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)beforeinterest,incometaxes,depreciation, depletion,amortizationandaccretion.AdjustedEBITDAisalsoadjustedforequity-basedcompensation,losses/gains on commodity derivative contracts, settlements of derivative contracts, contract amortization and write-off, 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 also includes any insurance recoveries received, regardless of whether they relate to the recovery of mitigation costs, the receipt of business interruption proceeds, or the recovery of losses on machinery and equipment.

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.

Results of Operations

Comparison of Three Months Ended June 30, 2019 to Three Months Ended June 30, 2018

Coal Sales. The following table summarizes coal sales information during the three months ended June 30, 2019 and 2018 (in thousands, except per ton data).

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Variance
Coal sales	$	224,488	$	269,992	$	(45,504	)	-16.9	%
Tons sold		5,005		5,867		(862	)	-14.7	%
Coal sales realization per ton sold(1)	$	44.85	$	46.02	$	(1.17	)	-2.5	%
Netback to mine realization per ton sold(2)	$	34.90	$	35.96	$	(1.06	)	-2.9	%
(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.

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The decrease in coal sales revenue from the prior year period was due to lower coal sales volumes combined with lower coal sales realization per ton sold.  Coal sales volumes for the three months ended June 30, 2019 were lower as compared to the prior year period due primarily to lower sales volumes placed into the export market.  Declining API2 pricing on export volumes resulted in lower overall coal sales realizations.  

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 June 30, 2019 and 2018 (in thousands, except per ton data).

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Variance
Cost of coal produced (excluding depreciation,   depletion and amortization)	$	122,216	$	136,982	$	(14,766	)	-10.8	%
Produced tons sold		4,960		5,779		(819	)	-14.2	%
Cash cost per ton sold(1)	$	24.64	$	23.70	$	0.94		4.0	%
Tons produced		5,416		5,419		(3	)	-0.1	%
(1) - Cash cost per ton sold is defined as cost of coal produced (excluding depreciation, depletion and amortization) divided by produced tons sold.

The decrease in cost of coal produced (excluding depreciation, depletion and amortization) from the prior year period was due to an overall decrease in produced tons sold offset by an increase in the cash cost per ton sold.  The increase in cash cost per ton sold was primarily a function of the decrease in produced tons sold.     

Cost of Coal Purchased.  From time to time, we purchase coal from Murray Energy and its affiliates to, among other things, meet customer contractual obligations.  Such purchases totaled $2.1 million and $3.9 million during the three months ended June 30, 2019 and 2018, respectively.

Transportation.Our cost of transportation for the three months ended June 30, 2019 decreased approximately $9.2 million from the three months ended June 30, 2018 due to a decrease in produced tons sold and a larger percentage of our sales going to the export market during the prior year period, which have higher associated transportation and transloading costs. These decreases were slightly offset by increases due to high river levels at the export facilities near New Orleans.  

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization expense for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018 was primarily due to a lower depreciable asset base resulting from the aggregate impairment charge at our Hillsboro complex in the prior year period, as well as $3.2 million of depreciation, depletion and amortization capitalized into development cost associated with our Hillsboro complex during the current period.  

Contract Amortization and Write-off.During the three months ended June 30, 2019 and 2018, we recorded amortization benefit of $1.8 million and $70.4 million, respectively, on the favorable/unfavorable sales and royalty contract assets and liabilities.  Included in the prior year period was a benefit of $69.1 million associated with the write-off of an unfavorable royalty agreement.   

Selling, General and Administrative.  The decrease in selling, general and administrative expense for the three months ended June 30, 2019 as compared to the prior year period was primarily due to decreased sales and marketing expenses resulting from lower sales volumes and legal expenses incurred in the prior year period associated with the Hillsboro and Macoupin litigation matters settled in October of 2018.

Long-lived Asset Impairments.  During the three months ended June 30, 2018, we recorded an aggregate impairment charge of $110.7 million related to certain long-lived assets and mineral reserves associated with our Hillsboro complex.

Other Operating (Income) Expense, Net.  Other operating (income) expense, net for the three months ended June 30, 2018, included the receipt of $43.0 million in payments from insurance companies related to the Hillsboro combustion event.

Interest Expense, Net.  Interest expense, net for the three months ended June 30, 2019 was comparable to the three months ended June 30, 2018 primarily as a result of lower overall outstanding principal balances offset by additional outstanding borrowings on our revolving credit facility.

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Adjusted EBITDA. Adjusted EBITDA decreased $59.0 million from the prior year period due to the receipt of insurance proceeds in the prior year period combined with overall decreased sales volumes, lower coal sales realization per ton, and higher cost per ton sold in the current year period. The table below reconciles net loss to Adjusted EBITDA for the three months ended June 30, 2019 and 2018 (in thousands).

	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018
Net loss(1)	$	(33,672	)	$	(29,222	)
Interest expense, net		36,618			37,035
Depreciation, depletion and amortization		43,244			55,312
Accretion on asset retirement obligations		552			559
Contract amortization and write-off		(1,836	)		(70,424	)
Equity-based compensation		234			175
Long-lived asset impairments		—			110,689
Adjusted EBITDA	$	45,140		$	104,124
(1) - Included in net loss during the three months ended June 30, 2018 was insurance proceeds of $44.1 million from the Hillsboro mine combustion event.

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

Comparison of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2018

Coal Sales. The following table summarizes coal sales information during the six months ended June 30, 2019 and 2018 (in thousands, except per ton data).

	Six Months Ended June 30, 2019		Six Months Ended June 30, 2018		Variance
Coal sales	$	491,825	$	508,379	$	(16,554	)	-3.3	%
Tons sold		10,701		11,107		(406	)	-3.7	%
Coal sales realization per ton sold(1)	$	45.96	$	45.77	$	0.19		0.4	%
Netback to mine realization per ton sold(2)	$	35.81	$	36.27	$	(0.46	)	-1.3	%
(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 decrease in coal sales revenue from the prior year period was due to lower coal sales volumes.  Coal sales volumes for the six months ended June 30, 2019 were lower as compared to the prior year period due primarily to lower sales volumes placed into the export market.  Although API2 pricing has declined significantly during the six months ended June 30, 2019, our contracted position allowed us to maintain overall comparable coal sales realizations on export tons.  

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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 six months ended June 30, 2019 and 2018 (in thousands, except per ton data).

	Six Months Ended June 30, 2019		Six Months Ended June 30, 2018		Variance
Cost of coal produced (excluding depreciation,   depletion and amortization)	$	256,197	$	257,552	$	(1,355	)	-0.5	%
Produced tons sold		10,606		10,978		(372	)	-3.4	%
Cash cost per ton sold(1)	$	24.16	$	23.46	$	0.70		3.0	%
Tons produced		11,481		11,086		395		3.6	%
(1) - Cash cost per ton sold is defined as cost of coal produced (excluding depreciation, depletion and amortization) divided by produced tons sold.

The decrease in cost of coal produced (excluding depreciation, depletion and amortization) from the prior year period was due to an overall decrease in produced tons sold offset by an increase in the cash cost per ton sold.  The increase in cash cost per ton sold was primarily a function of the decrease in produced tons sold.    

Cost of Coal Purchased.  From time to time, we purchase coal from Murray Energy and its affiliates to, among other things, meet customer contractual obligations.  Such purchases totaled $4.5 million and $5.7 million during the six months ended June 30, 2019 and 2018, respectively.

Transportation.Our cost of transportation for the six months ended June 30, 2019 was comparable to the six months ended June 30, 2018, with slight increases due to high river levels at the export facilities near New Orleans.    

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization expense for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018 was primarily due to a lower depreciable asset base resulting from the aggregate impairment charge at our Hillsboro complex in the prior year period, as well as $6.4 million of depreciation, depletion and amortization capitalized into development cost associated with our Hillsboro complex during the current period.  

Contract Amortization and Write-off.During the six months ended June 30, 2019 and 2018, we recorded amortization benefit of $3.5 million and $71.8 million, respectively, on the favorable/unfavorable sales and royalty contract assets and liabilities.  Included in the prior year period was a benefit of $69.1 million associated with the write-off of an unfavorable royalty agreement.    

Selling, General and Administrative.  The decrease in selling, general and administrative expense for the six months ended June 30, 2019 as compared to the prior year period was primarily due to legal expenses incurred in the prior year period associated with the Hillsboro and Macoupin litigation matters settled in October of 2018.

Long-lived Asset Impairments.  During the six months ended June 30, 2018, we recorded an aggregate impairment charge of $110.7 million related to certain long-lived assets and mineral reserves associated with our Hillsboro complex.

Other Operating (Income) Expense, Net.  Other operating (income) expense, net for the six months ended June 30, 2018, included the receipt of $43.0 million in payments from insurance companies related to the Hillsboro combustion event.

Interest Expense, Net.  Interest expense, net for the six months ended June 30, 2019 was comparable to the six months ended June 30, 2018 primarily as a result of lower overall outstanding principal balances offset by additional outstanding borrowings on our revolving credit facility.

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Adjusted EBITDA. Adjusted EBITDA decreased $58.5 million from the prior year period due to the receipt of insurance proceeds in the prior year period combined with overall decreased sales volumes, lower coal sales realization per ton, and higher cost per ton sold in the current year period.  The table below reconciles net loss to Adjusted EBITDA for the six months ended June 30, 2019 and 2018 (in thousands).

	Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
Net loss(1)	$	(50,493	)	$	(50,791	)
Interest expense, net		73,328			72,708
Depreciation, depletion and amortization		89,792			106,732
Accretion on asset retirement obligations		1,103			1,290
Contract amortization and write-off		(3,522	)		(71,844	)
Equity-based compensation		467			352
Long-lived asset impairments		—			110,689
Adjusted EBITDA	$	110,675		$	169,136
(1) - Included in net loss during the six months ended June 30, 2018 was insurance proceeds of $44.1 million from the Hillsboro mine combustion event.

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

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). Our primary sources of operating liquidity consist of cash generated from operations, cash on hand, and a $170.0 million revolving credit facility (the “Revolving Credit Facility”). As of June 30, 2019, we had $3.0 million of cash on hand and available borrowing capacity under the Revolving Credit Facility (net of outstanding letters of credit) of $44.7 million.

The Credit Facilities (defined below) 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.

During the three months ended June 30, 2019, we prepaid $19.6 million of outstanding borrowings pursuant to the Excess Cash Flow Provisions under the Credit Facilities for the annual period ending December 31, 2018.  The prepayment was payable 95 days after year-end.  

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 and development 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.

Development 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. Development capital expenditures consist of current and potential future capital expenditures at our Hillsboro complex. Future longwall development and the associated 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.

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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 pay distributions.

Changes in Cash Flows

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

	Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(In Thousands)
Net cash provided by operating activities	$	40,872		$	82,288
Net cash (used in) provided by investing activities	$	(60,380	)	$	12,258
Net cash provided by (used in) financing activities	$	22,221		$	(57,965	)

For the six months ended June 30, 2019, net cash provided by operating activities was $40.9 million compared to $82.3 million provided by operating activities for the six months ended June 30, 2018. The decrease in cash provided by operating activities for the current period is primarily the result of decreased coal sales revenues and various working capital variances.  Significant working capital variances as compared to the prior period included:

• a $8.3 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 $17.5 million unfavorable inventory variance resulting from increased coal inventory levels and the varying composition of coal inventory levels between the mine sites and export terminals;  

• a $8.1 million unfavorable variance in accounts receivable and other assets which is a function of the timing of cash receipts;

• a $7.8 million favorable variance in accounts payable and accrued expenses which is a function of the timing of vendor payments; and

• a $16.1 million unfavorable variance in accrued interest which is a function of the timing of interest payments on our long-term debt obligations.

For the six months ended June 30, 2019, net cash used in investing activities was $60.4 million compared to $12.3 million net cash provided by investing activities for the six months ended June 30, 2018.  Cash used in investing activities in the current year period resulted primarily from increased capital expenditures associated with land purchases from New River Royalty, a new portal at our Sugar Camp complex, and development of our Hillsboro complex.  Cash provided by investing activities in the prior year period was the result of the receipt of $43.0 million of insurance recoveries offset by $32.2 million in capital expenditures.  

For the six months ended June 30, 2019, net cash provided by financing activities was $22.2 million compared to $58.0 million used in financing activities for the six months ended June 30, 2018. Cash provided by financing activities in the current year period resulted from $76.0 million in net borrowings on the Revolving Credit Facility offset by $42.7 million in payments on long-term debt and finance lease obligations, $6.2 million in payments on sale-leaseback and short-term financing arrangements, and $4.9 million in distributions paid to common unitholders.  In the prior year period, cash used in financing activities primarily related to $78.6 million in payments on long-term debt and finance lease obligations and $9.0 million in distributions paid to common unitholders, offset by $35 million in net borrowings on the Revolving Credit Facility.  

Long-Term Debt and Sale-Leaseback Financing Arrangements

Description of the Senior Secured First-Priority Credit Facilities (the “Credit Facilities”)

The Credit Facilities consist of a 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 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 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:

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•in the case of the Term Loan due 2022, at the Partnership’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 Partnership’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 originally required 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. However, the prepayments required pursuant to the Excess Cash Flow Provisions are to be applied against the future scheduled quarterly amortization payments on the Term Loan due 2022. Accordingly, no additional amortization payments on the Term Loan due 2022 are required prior to 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 FELP) and are or will be unconditionally guaranteed, jointly and severally, on a senior secured first-priority basis by each of the Partnership’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, currently 3.50:1.00 and stepping down by 0.25x in the first quarter 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 June 30, 2019, $743.3 million in principal was outstanding under the Term Loan due 2022 and there was $113.0 million in borrowings outstanding under the Revolving Credit Facility. During the three months ended June 30, 2019, we prepaid $19.6 million of outstanding borrowings pursuant to the Excess Cash Flow Provisions under the Credit Facilities for the annual period ending December 31, 2018.  The prepayment was payable 95 days after year-end.

Description of the Second Lien Senior Secured Notes due 2023 (the “Second Lien Notes due 2023”)

The Second Lien Notes due 2023 consist of $425 million in aggregate principal with 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 Second Lien Notes due 2023 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 Second Lien Notes due 2023 are unconditionally guaranteed, jointly and severally, on a senior secured second-priority basis by each of the Partnership’s wholly-owned domestic subsidiaries that guarantee the Credit Facilities (which do not include Hillsboro Energy LLC). The Second Lien Notes due 2023 contains certain usual and customary negative covenants and events of default, including related to a change in control.

Prior to April 1, 2020, the Second Lien Notes due 2023 may be redeemed 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 Partnership may redeem up to 35% of the aggregate principal amount of the Second Lien Notes due 2023 at a price equal to 111.50% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed with the proceeds from a qualified equity offering, subject to at least 50% of the aggregate principal amount of the Second Lien Notes due 2023 remaining outstanding after giving effect to any such redemption. On or after April 1, 2020, the Second Lien Notes due 2023 may be redeemed at a price equal to: (i) 105.750% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed prior to April 1, 2021; (ii) 102.875% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed on or after April 1, 2021 but prior to April 1, 2022; and (iii) 100.000% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed thereafter.

Longwall Financing Arrangements and Finance 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 finance 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

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termination payments of $2.8 million are due at the end of the lease terms. As of June 30, 2019, $7.9 million was outstanding under these finance 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, certain covenants and definitions in the credit agreements and guaranty agreements conform to the covenants and definitions in the Credit Facilities. The outstanding balance as of June 30, 2019 was $3.1 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 was June 2019. In addition, certain covenants and definitions in the credit agreements and guaranty agreements conform to the covenants and definitions in the Credit Facilities. There is no outstanding balance as of June 30, 2019, and all amounts associated with the 5.78% longwall financing arrangement have been repaid.

Sale-Leaseback Financing Arrangements

In 2009, Macoupin sold certain of its coal reserves and rail facility assets to 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 had a carrying value of $130.4 million as of June 30, 2019 and an effective interest rate of 14.8%.

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 $63.8 million as of June 30, 2019 and an effective interest rate of 8.1%.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements, including 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 and take-or-pay transportation obligations, 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 primarily secure our obligations for certain employee and environmental obligations. At June 30, 2019, we had $12.3 million of letters of credit outstanding, which were 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 $96.8 million as of June 30, 2019 to secure reclamation and other performance commitments.

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 February 27, 2019.

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.

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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 February 27, 2019.  Other than as indicated in this Quarterly Report on Form 10-Q related to the adoption of the new lease standard, there have been no significant changes to our prior critical accounting policies and estimates subsequent to December 31, 2018, 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 June 30, 2019, of our nearly $1.3 billion in long-term debt and finance lease obligations outstanding, $856.3 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 $8.6 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 June 30, 2019. 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 February 27, 2019.

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 February 27, 2019, 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. There have been no material changes during the three months ended June 30, 2019 to the risk factors previous disclosed in our Annual Report on Form 10-K filed with the SEC on February 27, 2019 other than as disclosed below:

We were notified by the NYSE that we were not in compliance with certain NYSE continued listing requirements.  Our disclosure of the notice of non-compliance could negatively affect our business, financial condition, and results of operations.

On June 13, 2019, we received a notice from the NYSE that we were not in compliance with a NYSE continued listing standard because our average closing price per common unit for a consecutive 30-trading-day period was less than $1.00. Our non-compliance with the NYSE continued listing requirements could adversely affect our relationships with our suppliers, customers, and potential customers and their decisions to conduct business with us. Such decisions could negatively affect our business, financial condition, and results of operations. 

If we do not regain compliance, our common units will be subject to the NYSE’s suspension and delisting procedures.  A suspension or delisting could adversely affect our relationships with our suppliers, customers, and potential customers and their decisions to conduct business with us. Such decisions could negatively affect our business, financial condition, and results of operations. In addition, a suspension or delisting could impair our ability to raise additional capital through equity or debt financing and our ability to attract and retain employees and members of management by means of equity-based compensation.

In the event of a delisting, our common units could be traded over-the-counter. In the event of such trading, it is likely that there would be significantly less liquidity in the trading of our common units, decreases in institutional and other investor demand for our common units, coverage by securities analysts, market making activity and information available concerning trading prices and volume, and fewer broker-dealers willing to execute trades in our common units. The occurrence of any of these events could result in a further decline in the market price of our common units.

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 June 30, 2019) filed in XBRL.  The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed”.
*	Filed herewith.
**	Furnished

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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 August 7, 2019.

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

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