Foresight Energy (FELPQ) 10-Q 2020 Q1 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 March 31, 2020

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
N/A	N/A	N/A

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 May 1, 2020, the registrant had 80,996,773 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	27
Item 3.Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.Controls and Procedures	36
PART II
OTHER INFORMATION
Item 1.Legal Proceedings	37
Item 1A.Risk Factors	37
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.Defaults Upon Senior Securities	37
Item 4.Mine Safety Disclosures	37
Item 5.Other Information	37
Item 6. Exhibits	38
Signatures	39

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PART I – FINANCIAL INFORMATION.

Item 1. Financial Statements.

Foresight Energy LP

(Debtor-In-Possession)

Unaudited Condensed Consolidated Balance Sheets

(In Thousands)

	March 31,		December 31,
	2020		2019
Assets
Current assets:
Cash and cash equivalents	$	61,300	$	33,905
Accounts receivable		13,289		19,241
Due from affiliates, net of reserve		16,962		23,131
Financing receivables - affiliate		—		297
Inventories, net		70,506		58,784
Deferred longwall costs		17,232		20,641
Other prepaid expenses and current assets		17,210		13,402
Contract-based intangibles		516		726
Total current assets		197,015		170,127
Property, plant, equipment and development, net		1,891,564		1,923,625
Financing receivables - affiliate, net of reserve		—		—
Prepaid royalties, net		11,382		11,382
Other assets		20,106		13,985
Total assets	$	2,120,067	$	2,119,119
Liabilities and partners’ capital
Current liabilities:
Current portion of long-term debt	$	53,586	$	1,317,302
Current portion of sale-leaseback financing arrangements		2,500		12,190
Accrued interest		390		45,885
Accounts payable		11,395		109,909
Accrued expenses and other current liabilities		47,834		58,123
Asset retirement obligations		3,313		3,313
Due to affiliates		2,325		15,836
Contract-based intangibles		5,918		6,268
Total current liabilities		127,261		1,568,826
Long-term debt		—		—
Sale-leaseback financing arrangements		56,608		147,915
Asset retirement obligations		53,372		55,643
Other long-term liabilities		6,853		14,480
Contract-based intangibles		59,307		60,624
Total liabilities not subject to compromise		303,401		1,847,488
Liabilities subject to compromise		1,509,337		—
Total liabilities		1,812,738		1,847,488
Limited partners' capital:
Common unitholders (80,997 units outstanding as of March 31, 2020 and December 31, 2019)		217,397		197,586
Subordinated unitholder (64,955 units outstanding as of March 31, 2020 and December 31, 2019)		89,932		74,045
Total partners' capital		307,329		271,631
Total liabilities and partners' capital	$	2,120,067	$	2,119,119

See accompanying notes.

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Foresight Energy LP

(Debtor-In-Possession)

Unaudited Condensed Consolidated Statements of Operations

(In Thousands, Except per Unit Data)

	Three Months Ended March 31, 2020			Three Months Ended March 31, 2019
Revenues:
Coal sales	$	99,142		$	267,337
Other revenues		547			1,735
Total revenues		99,689			269,072
Costs and expenses:
Cost of coal produced (excluding depreciation, depletion and amortization)		79,985			133,981
Cost of coal purchased		—			2,375
Transportation		1,103			58,834
Depreciation, depletion and amortization		36,511			46,548
Contract amortization		(1,456	)		(1,686	)
Accretion on asset retirement obligations		684			551
Selling, general and administrative		6,582			8,647
Other operating (income) expense, net		(33	)		(67	)
Operating (loss) income		(23,687	)		19,889
Other expenses
Interest expense, net		25,204			30,817
Interest expense, net - sale-leaseback financing arrangements		539			5,893
Reorganization items, net		(85,128	)		—
Net income (loss)	$	35,698		$	(16,821	)
Net income (loss) available to limited partner units - basic and diluted:
Common unitholders	$	19,811		$	(7,168	)
Subordinated unitholder	$	15,887		$	(9,653	)
Net income (loss) per limited partner unit - basic and diluted:
Common unitholders	$	0.24		$	(0.09	)
Subordinated unitholder	$	0.24		$	(0.15	)
Weighted average limited partner units outstanding - basic and diluted:
Common units		80,997			80,915
Subordinated units		64,955			64,955
Distributions declared per limited partner unit	$	—		$	0.06

See accompanying notes.

4

Foresight Energy LP

(Debtor-In-Possession)

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, 2020	$	197,586		80,996,773	$	74,045		64,954,691	$	271,631
Net income		19,811		—		15,887		—		35,698
Balance at March 31, 2020	$	217,397		80,996,773	$	89,932		64,954,691	$	307,329

	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

See accompanying notes.

5

Foresight Energy LP

(Debtor-In-Possession)

Unaudited Condensed Consolidated Statements of Cash Flows

(In Thousands)

	Three Months Ended March 31, 2020			Three Months Ended March 31, 2019
Cash flows from operating activities
Net income (loss)	$	35,698		$	(16,821	)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		36,511			46,548
Amortization of debt discount		1,025			700
Contract amortization		(1,456	)		(1,686	)
Accretion on asset retirement obligations		684			551
Equity-based compensation		—			233
Non-cash reorganization items, net		(97,878	)		—
Changes in operating assets and liabilities:
Accounts receivable		5,952			4,974
Due from/to affiliates, net		4,952			9,519
Inventories		(6,248	)		(4,228	)
Prepaid expenses and other assets		(6,520	)		(9,235	)
Prepaid royalties		—			5
Accounts payable		(5,395	)		17,062
Accrued interest		20,945			7,380
Accrued expenses and other current and long-term liabilities		(536	)		(6,157	)
Other		74			322
Net cash (used in) provided by operating activities		(12,192	)		49,167
Cash flows from investing activities
Investment in property, plant, equipment and development		(9,924	)		(35,096	)
Return of investment on financing arrangements with Murray Energy (affiliate)		297			823
Net cash used in investing activities		(9,627	)		(34,273	)
Cash flows from financing activities
Borrowings under DIP facility		55,000			—
Borrowings under revolving credit facility		—			21,000
Payments on revolving credit facility		—			(13,000	)
Payments on long-term debt and finance lease obligations		—			(10,709	)
Distributions paid		—			(4,856	)
Payment of debt issuance costs		(1,682	)		—
Payments on sale-leaseback and short-term financing arrangements		(4,104	)		(4,112	)
Net cash provided by (used in) financing activities		49,214			(11,677	)
Net increase in cash and cash equivalents		27,395			3,217
Cash and cash equivalents, beginning of period		33,905			269
Cash and cash equivalents, end of period	$	61,300		$	3,486

See accompanying notes.

6

Foresight Energy LP

(Debtor-In-Possession)

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 subsidiaries and 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 has four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). Mining operations at our Hillsboro complex had been idled since March 2015 due to a combustion event (the “Hillsboro Combustion Event”). In January 2019, we resumed continuous miner production and development activities at our Hillsboro complex and in March 2020, longwall production at our Hillsboro complex resumed.  In March 2020, mining operations at our Macoupin complex were idled.  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, 2019 included in our Annual Report on Form 10-K filed with the SEC on April 6, 2020. 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, 2020. Intercompany transactions are eliminated in consolidation.

Filing Under Chapter 11 of the Bankruptcy Code, Liquidity, Capital Resources, Debt Obligations, and Going Concern Considerations

The thermal coal markets that we traditionally serve have been meaningfully challenged over the past three to four years and deteriorated significantly in the last several months. The impact of depressed demand and pricing in both domestic and international markets has impacted us significantly in recent months: customers with pre-existing commitments have refused to accept delivery, and with export markets depressed there is no alternative market to place product. As a result, we have suffered recurring operating losses, have a working capital deficiency, and have not complied with certain covenants on our credit facilities, as discussed further below.  These circumstances have required us to seek protection under Chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”). These factors raise substantial doubt about the Partnership’s ability to continue as a going concern.  The Partnership’s ability to continue as a going concern is dependent upon, among other things, its ability to become profitable and maintain profitability, its ability to access sufficient liquidity and its ability to successfully implement its overall Chapter 11 strategy and restructuring, as further discussed below.  The condensed consolidated financial statements are prepared on a going concern basis and do not include any adjustments that may be required if the Partnership were unable to continue as a going concern.

On March 10, 2020 (the “Petition Date”), the Partnership, including FEGP, FELP, and its direct and indirect subsidiaries (collectively, the “Foresight Debtors”) filed voluntary petitions for relief under chapter 11 (the “Bankruptcy Petitions”) of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri (the “Bankruptcy Court”).  The Foresight Debtors sought, and

7

received, Bankruptcy Court authorization to jointly administer the Chapter 11 cases (the “Foresight Chapter 11 Cases”) under the caption “In re: Foresight Energy LP, et al.” Case No. 20-41308.  The Foresight Debtors will continue to manage their properties and operate their business as a “debtor in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provision of the Bankruptcy Code and the orders of the Bankruptcy Court.  

Commencement of the Foresight Chapter 11 Cases constituted an event of default under the Partnership’s credit facilities as well as the indentures governing the Partnership’s debt instruments, as further described in Note 8, and all unpaid principal and accrued and unpaid interest due thereunder became immediately due and payable.  Any efforts to enforce such payment obligations are automatically stayed as a result of the commencement of the Foresight Chapter 11 Cases and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.  

On the Petition Date, the Foresight Debtors filed a number of motions with the Bankruptcy Court generally designed to stabilize their operations and facilitate their transition into Chapter 11.  Certain of these motions sought authority from the Bankruptcy Court for the Debtors to make payment upon, or otherwise honor, certain prepetition obligations (e.g., obligations related to certain employee wages, salaries, and benefits; certain vendors and other providers essential to the Foresight Debtors operations; etc.).  The Bankruptcy Court has entered orders approving the relief sought in these motions.

Commencement of the Foresight Chapter 11 Cases automatically stayed most actions against the Foresight Debtors, including actions to collect indebtedness incurred prior to the Petition Date or to exercise control over the Foresight Debtors property.  Subject to certain exceptions under the Bankruptcy Code, the commencement of the Foresight Chapter 11 Cases also automatically stayed the continuation of most legal proceedings or the filing of other actions against or on behalf of the Foresight Debtors or their property to recover on, collect, or secure a claim arising prior to the Petition Date or to exercise control over property of the Foresight Debtors bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such claim.  Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under their police and regulatory powers.

The U.S. Trustee for the Eastern District of Missouri filed a notice appointing an official committee of unsecured creditors (the “Unsecured Creditors’ Committee”) on March 17, 2020.  The Unsecured Creditors’ Committee represents all unsecured creditors of the Foresight Debtors and has a right to be heard on all matters that come before the Bankruptcy Court.

As a result of the commencement of the Foresight Chapter 11 Cases, the realization of the Foresight Debtors assets and the satisfaction of liabilities are subject to significant uncertainty.  For the Foresight Debtors to emerge successfully from Chapter 11, they must obtain the Bankruptcy Court’s approval of a plan of reorganization (a “Chapter 11 Plan”), which will enable them to transition from Chapter 11 into ordinary course operations as reorganized entities outside of bankruptcy.  A Chapter 11 Plan determines the rights and treatment of claims of various creditors and equity holders, and is subject to the ultimate outcome of negotiations and Bankruptcy Court decisions ongoing through the date on which the Chapter 11 Plan is confirmed.

On the Petition Date the Foresight Debtors entered into a Restructuring Support Agreement (the “RSA”) with holders of over 69% in aggregate principal amount of the Foresight Debtors outstanding senior secured first-priority credit facility (the “Consenting First Lien Lenders”) and holders of over 82% in aggregate principal amount of the Foresight Debtors outstanding senior secured notes (the “Consenting Second Lien Noteholders” and together with the Consenting First Lien Lenders, the “Consenting Creditors”). As set forth in the RSA, the Foresight Debtors and the Consenting Creditors (collectively, the “RSA Parties”) have agreed to the principal terms of a proposed financial restructuring (the “Restructuring”) of the Partnership. The Restructuring is contemplated to be implemented through the Chapter 11 Plan.

The RSA contemplates a comprehensive deleveraging of the Partnership’s balance sheet and an approximately $1.1 billion reduction of the Partnership’s funded debt. Specifically, the RSA provides as follows:

• Subject to dilution as set forth in the RSA, holders of the Partnership’s outstanding senior secured first-priority credit facilities will receive their pro rata share of 92.75% of the equity securities of the reorganized Partnership (the “New Common Equity”).

• Subject to dilution in the RSA, holders of the Partnership’s Second Lien Notes due 2023 will receive their pro rata share of 7.25% of the New Common Equity.

• Holders of the Partnership’s general unsecured debt (the “General Unsecured Debt”) will receive their pro rata share of a determined cash pool; provided that the size of the determined cash pool may vary depending on whether holders of General Unsecured Debt, voting as a class, accept or reject the Chapter 11 Plan; provided, further, the Partnership, with the approval of the Consenting First Lien Lenders holding more than 60% in principal amount of the first lien claims held by the Consenting First Lien Lenders in the aggregate as of the time of such determination, may classify any General Unsecured Debt below a certain dollar threshold into a convenience class pursuant to section 1122 of United States Code, 11 U.S.C. §§ 101–1532, with holders of such debt receiving different treatment than holders of other General Unsecured Debt.

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• Equity and voting interests in FELP and FEGP (including common units, general partner interests, subordinated units, warrants and options to purchase equity interests) and all incentive distribution rights in FELP and FEGP will be cancelled and will be of no further force or effect. Holders of such interests will receive no recovery on account of such interests.

• The Foresight Chapter 11 Cases will be funded with the Debtor-in-Possession Credit and Guaranty Agreement (the “DIP Facility”) with a borrowing limit of $175 million, $100 million of which is a new money multi-draw term loan facility, and $75 million of which is a term loan facility that will roll up the claims of the Consenting Creditors. The Consenting Creditors have committed to provide the full amount of the DIP Facility.

• The DIP Facility will be refinanced by a new $225 million senior secured first-priority term loan facility (the “First Lien Exit Facility”) upon the Partnership’s emergence from the Foresight Chapter 11 Cases. The First Lien Exit Facility will have a 7-year maturity and bear interest at a rate between LIBOR (subject to a 1.50% floor) +800 basis points.

• An ad hoc group of the Consenting Creditors anticipate entering into a backstop agreement pursuant to which they will backstop the entire amount of the First Lien Exit Facility.

The RSA includes certain milestones for the progress of the Foresight Chapter 11 Cases, which include the dates by which the Foresight Debtors are required to, among other things, obtain certain court orders and consummate the Restructuring.  In addition, the RSA Parties will have the right to terminate the RSA (and their support for the Restructuring) under certain circumstances, including, in the case of the Foresight Debtors, if the board of directors, board of managers or such similar governing party of any Foresight Debtors determines in good faith that performance under the RSA would be inconsistent with its fiduciary duties. Accordingly, no assurance can be given that the Restructuring described in the RSA will be consummated.

The Foresight Debtors also entered into support agreements with certain of its principal commercial counterparties, including with Natural Resource Partners LP (“NRP”). The NRP support agreement (the “NRP Restructuring Support Agreement”) calls for, among other things, the suspension of all tonnage royalty payments, override royalty payments, wheelage payments, rail loop and loadout fees, rental fees, minimum deficiency payments, and other related amounts due to NRP and its affiliates or subsidiaries for 2020 and 2021 in exchange for a fixed annual amount paid ratably over the same period.  

Specific to the Macoupin complex, the NRP Restructuring Support Agreement requires the payment of an annual idling fee from 2020 through 2023 and for FELP to maintain the mine in a manner that preserves the facilities, infrastructure, and equipment.  However, at any time FELP may recommence production at Macoupin with a new lease to be negotiated between FELP and NRP.  Beginning on January 1, 2024, the NRP Restructuring Support Agreement calls for the following (assuming production has not resumed at Macoupin):

• NRP has the option to cause FELP to surrender the Macoupin complex, plus all permits and equipment to support mining operations, and assume all liabilities;

• FELP may offer to sell the Macoupin complex, plus all permits and equipment to support mining operations, in exchange for one dollar plus the assumption of Macoupin reclamation obligations;

• FELP may continue to idle the mine in exchange for the payment of the annual idling fee; or

• FELP may permanently seal the mine and commence reclamation activities at the Macoupin complex.

On March 11, 2020 (the “DIP Closing Date”), the Foresight Debtors filed a motion (the “DIP Motion”) seeking authorization to use cash collateral and to approve financing under the DIP Facility by and among FELLC as borrower (the “DIP Borrower”), FELP and certain subsidiaries of the FELLC as guarantors (together with the DIP Borrower, the “DIP Loan Parties”), the Consenting Creditors, and Cortland Capital Market Services LLC as administrative and collateral agent (the “DIP Agent”).  

The DIP Facility has a 180-day term unless, prior to the end of such 180-day period, one or more termination events (including the consummation of a Chapter 11 Plan) occurs.

The amount committed and made available under the DIP Facility is $175 million, which consists of a $100 million new money multi-draw term loan (with $55 million funded on the DIP Closing Date and $45 million available on a delayed draw basis upon the entry of a final order approving the DIP Facility (the “Final Order”) by the bankruptcy court hearing the Foresight Debtors bankruptcy cases) and, subject to the entry of the Final Order, a $75 million roll-up term loan of the first lien claims of the Consenting Creditors.  The DIP Facility bears interest based on, at the DIP Borrower’s option, an adjusted LIBOR rate plus an applicable margin of 11.00% (subject to a 1.00% floor) or an alternate base rate plus an applicable margin of 10.00% (subject to a 2.00% floor).  In addition to paying interest on outstanding principal under the DIP Facility, the DIP Borrower will be required to pay a commitment fee to the Consenting Creditors in respect of the delayed draw term loan commitment at a rate equal to 1.00% per annum.  The DIP Facility also provides for the payment of cash upfront fees and payment in newly-issued common equity upon consummation of the Foresight Debtors bankruptcy cases of put option premium and exit fees (or, in the event of a termination of the DIP Facility prior thereto, payment of such amounts in cash).  The Final Order was entered on April 9, 2020.

The DIP Facility contains certain customary affirmative covenants. The negative covenants in the DIP Facility, include, among other things, limitations on our ability to do the following, subject to certain exceptions and baskets:

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• incur additional debt;

• create liens on certain assets;

• make certain loans or investments (including acquisitions);

• pay dividends on or make distributions in respect of our capital stock or make other restricted payments;

• consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

• sell or otherwise dispose of assets;

• enter into certain transactions with our affiliates;

• enter into sale-leaseback transactions;

• change our lines of business;

• restrict liens;

• change our fiscal year; and

• modify the terms of certain debt or organizational agreements.

The DIP Facility has (i) a maximum capital expenditure covenant calculated on a cumulative basis with testing beginning as of March 31, 2020 and continuing thereafter monthly through July 31, 2020 and (ii) a minimum liquidity covenant of (1) $20 million prior to the funding of delayed draw term loans and (2) $40 million on or after the funding of delayed draw term loans.  Moreover, the DIP Facility includes a budget covenant restricting us from (1) realizing aggregate operating receipts, (2) making aggregate operating disbursements (other than certain affiliate payments, payments of interest and payment of professional fees) and (3) making certain affiliate operating disbursements that, in the case of aggregate operating receipts, fail to at least equal a certain percentage of an agreed budgeted amount and, in the case of operating disbursements, exceed by more than a certain percentage an agreed budgeted amount over each applicable two-week or four-week budget testing period.

Subject to certain exceptions, the DIP Facility is secured by priming, first-priority liens on substantially all assets of the Foresight Debtors pursuant to an order of the Bankruptcy Court hearing the Foresight Chapter 11 Cases.

The DIP Facility contains certain customary events of default, including relating to certain events (which include failure to satisfy agreed milestones) in respect of the Foresight Chapter 11 Cases.  If an event of default occurs and is continuing, the Consenting Creditors under the DIP Facility will be entitled to take various actions, including the acceleration of amounts due under the DIP Facility. Key DIP Facility milestones relating to the Foresight Chapter 11 Cases, the failure of which, if not cured, amended, or waived, would result in an event of default, are as follows:

• no later than 35 days after the Petition Date, the Bankruptcy Court shall have entered the Final Order and the DIP Loan Parties shall have filed the Chapter 11 Plan;

• no later than 50 days after the Petition Date, the DIP Loan Parties shall have entered into each of renegotiatied contracts / leases (as defined in the RSA), in form and substance acceptable to the DIP Loan Parties (and other parties as defined in the RSA);

• no later than 70 days after the Petition Date, entry of an order by the Bankruptcy Court approving the acceptable Chapter 11 Plan disclosure statement;

• no later than 115 days after the Petition Date, entry of an order by the Bankruptcy Court confirming the acceptable Chapter 11 Plan; and

• no later than 130 days after the Petition Date, effectiveness of the acceptable Chapter 11 Plan.

During the three months ended March 31, 2020, we incurred legal and financial advisor professional fees of $12.8 million related to the above issues, which have been recorded within reorganization items, net in the condensed consolidated statements of operations.  We expect legal and financial advisor professional fees to continue to be substantial until such time as the above issues are remediated, if at all.

For periods subsequent to the commencement of the Foresight Chapter 11 Cases, the Partnership applies Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations, in preparing its condensed consolidated financial statements.  ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the Foresight Chapter 11 Cases from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the Foresight Chapter 11 Cases are recorded in a reorganization line item on the condensed consolidated statements of operations. In addition, the pre-petition obligations that may be impacted by the Foresight Chapter 11 Cases are classified on the condensed consolidated balance sheet as liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, which may differ from the ultimate settlement amounts.

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2. New Accounting Standards

There are no new accounting standards issued or effective during the current period which are expected to have a material impact on the Partnership’s condensed consolidated financial statements or related disclosures.

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 may occur when coal is loaded onto railcars at the mine or 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 March 31, 2020		Three Months Ended March 31, 2019
	(In Thousands)
Coal sales - Domestic	$	81,438	$	140,949
Coal sales - International		17,704		126,388
Total coal sales	$	99,142	$	267,337

Contract Balances

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

	March 31, 2020		December 31, 2019
	(In Thousands)
Receivables - Included in 'Accounts receivable'	$	11,249	$	16,025
Receivables - Included in 'Due from affiliates'		15,428		21,173
Total contract balances	$	26,677	$	37,198

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.

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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:

	Three Months Ended March 31, 2020		Three Months Ended March 31, 2019
	(In Thousands)
Supplemental disclosures of non-cash investing activities:
Depreciation, depletion and amortization capitalized into development costs	$	1,758	$	3,180

5. Accounts Receivable

Accounts receivable consist of the following:

	March 31, 2020		December 31, 2019
	(In Thousands)
Trade accounts receivable	$	11,249	$	16,025
Other receivables		2,040		3,216
Total accounts receivable	$	13,289	$	19,241

6. Inventories, Net

Inventories, net consist of the following:

	March 31, 2020		December 31, 2019
	(In Thousands)
Parts and supplies	$	14,314	$	14,858
Raw coal		2,681		161
Clean coal		53,511		43,765
Total inventories	$	70,506	$	58,784

7. Property, Plant, Equipment and Development, Net

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

	March 31, 2020			December 31, 2019
	(In Thousands)
Land, land rights and mineral rights	$	1,652,570		$	1,652,570
Machinery and equipment		754,396			753,965
Buildings and structures		229,641			229,641
Development costs		105,150			93,899
Other		3,469			3,469
Property, plant, equipment and development		2,745,226			2,733,544
Less: accumulated depreciation, depletion and amortization		(853,662	)		(809,919	)
Property, plant, equipment and development, net	$	1,891,564		$	1,923,625

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8. Long-Term Debt Obligations

Long-term debt obligations consist of the following:

	March 31, 2020			December 31, 2019
	(In Thousands)
DIP Facility	$	55,000		$	—
Term Loan due 2022		743,286			743,286
Second Lien Notes due 2023		425,000			425,000
Revolving Credit Facility ($170.0 million capacity)		157,000			157,000
Subtotal - Total long-term debt principal outstanding		1,380,286			1,325,286
Unamortized debt discounts and issuance costs		(8,641	)		(7,984	)
Total long-term debt		1,371,645			1,317,302
Less: current portion		(53,586	)		(1,317,302	)
Less: liabilities subject to compromise		(1,318,059	)		—
Non-current portion of long-term debt	$	—		$	—

DIP Facility

The DIP Facility consists of a $100 million new money, multi-draw term loan facility and a $75 million term loan facility which shall roll-up certain first-priority pre-petition claims of the DIP Facility lenders.  The DIP Facility bears interest at LIBOR (subject to a floor of 1.00%) plus 11.00% per annum and is subject to customary fees, covenants, and milestones.  See Note 1 for further details on the terms of the DIP Facility and related borrowings.

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 required 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.  

As a result of the Foresight Chapter 11 Cases, the principal and interest due under the Term Loan due 2022 became immediately due and payable.  As a result, the outstanding principal amounts associated with the Term Loan due 2022 are classified as a liability subject to compromise on the Partnership’s condensed consolidated balance sheet as of March 31, 2020, and as a current liability on the Partnership’s consolidated balance sheet as of December 31, 2019.  However, any efforts to enforce such payment obligations under the Term Loan due 2022 are automatically stayed as a result of the Foresight Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the Term Loan due 2022 are subject to the applicable provisions of the Bankruptcy Code.  

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.

On October 1, 2019, the Issuers elected to exercise the grace period with respect to the interest payment due under the Indenture governing the Second Lien Notes due 2023. The election to exercise the grace period extended the time period the Issuers have to make the approximately $24.4 million interest payment without triggering an event of default under the Indenture.

On October 23, 2019, the Issuers sought the consent of the holders of the Second Lien Notes due 2023 (collectively, the “Holders”) to amend (such amendments, the “Amendments”) the Indenture and sought the consent of the Holders to waive (such waiver, the “Waivers”) certain Defaults or Events of Defaults arising under the Indenture, in each case, as more fully described below.

As of October 30, 2019, the Issuers received consents to the Amendments from Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due 2023 not owned by the Issuers or their affiliates. As a result, on

October 30, 2019, the Issuers, the guarantors party thereto and Wilmington Trust, National Association, the trustee for the

Second Lien Notes due 2023, entered into a supplemental indenture (the “Supplemental Indenture”) providing for the

Amendments to the Indenture.

The Amendments (i) amend Section 6.01(b) of the Indenture to extend the grace period for payment of interest due on the

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Second Lien Notes due 2023 from 30 days to 90 days and (ii) amend Section 4.03(d) of the Indenture to exclude the fiscal period ended September 30, 2019 from the requirement that the Issuers hold a publicly accessible conference call to discuss the Issuers’ financial information for the relevant fiscal period.

As of October 30, 2019, Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due

2023 not owned by the Issuers or their affiliates also delivered Waivers that waived any Default or Event of Default, including under Section 6.01(b) of the Indenture, arising as a result of the Issuers’ failure to make the interest payment that was due to be paid by the Issuers on October 1, 2019. The Waivers did not waive any obligation of the Issuers to make such payment of interest, or the right of any Holder to receive such payment (including as contemplated by Section 6.07 of the Indenture).

On December 13, 2019, the Issuers sought the consent of the Holders to further amend (such amendments, the “Second Amendments”) the Indenture as more fully described below.

As of December 19, 2019, the Issuers received consents to the Second Amendments from Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due 2023 not owned by the Issuers or their affiliates. As a result, on

December 19, 2019, the Issuers, the guarantors party thereto and Wilmington Trust, National Association, the trustee for the

Second Lien Notes due 2023, entered into a second supplemental indenture (the “Second Supplemental Indenture”) providing for the

Second Amendments to the Indenture.

The Second Amendments (i) amend Section 6.01(b) of the Indenture to extend the grace period for payment of interest due on the

Second Lien Notes due 2023 from 90 days to 150 days and (ii) amend Section 4.03(d) of the Indenture to eliminate the requirement that the Issuers hold a publicly accessible conference call to discuss the Issuers’ financial information for the relevant fiscal period.

On February 24, 2020, the Issuers sought the consent of the Holders to further amend (such amendment, the “Third Amendment”) the Indenture as more fully described below.

As of February 26, 2020, the Issuers received consents to the Third Amendment from Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due 2023 not owned by the Issuers or their affiliates. As a result, on

February 26, 2020, the Issuers, the guarantors party thereto and Wilmington Trust, National Association, the trustee for the

Second Lien Notes due 2023, entered into a third supplemental indenture (the “Third Supplemental Indenture”) providing for the

Third Amendment to the Indenture.

The Third Amendment amends Section 6.01(b) of the Indenture to extend the grace period for payment of interest due on the

Second Lien Notes due 2023 from 150 days to 180 days.

As a result of the Foresight Chapter 11 Cases, the principal and interest due under the Second Lien Notes due 2023 became immediately due and payable.  As a result, the outstanding principal amounts associated with the Second Lien Notes due 2023 are classified as a liability subject to compromise on the Partnership’s condensed consolidated balance sheet as of March 31, 2020, and as a current liability on the Partnership’s consolidated balance sheet as of December 31, 2019.  However, any efforts to enforce such payment obligations under the Second Lien Notes due 2023 are automatically stayed as a result of the Foresight Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the Second Lien Notes due 2023 are subject to the applicable provisions of the Bankruptcy Code.

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. The Revolving Credit Facility requires 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 of 2021. We were not in compliance with the maximum net first lien secured leverage ratio as of March 31, 2020.

As a result of the Foresight Chapter 11 Cases, the principal and interest due under the Revolving Credit Facility became immediately due and payable.  As a result, the outstanding principal amounts associated with the Revolving Credit Facility are classified as a liability subject to compromise on the Partnership’s condensed consolidated balance sheet as of March 31, 2020, and as a current liability on the Partnership’s consolidated balance sheet as of December 31, 2019.  However, any efforts to enforce such payment obligations under the Revolving Credit Facility are automatically stayed as a result of the Foresight Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the Revolving Credit Facility are subject to the applicable provisions of the Bankruptcy Code. 

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Contractual Interest Expense

The Partnership has not recorded interest expense on the Term Loan due 2022, the Second Lien Note due 2023, and the Revolving Credit Facility since the Petition Date.  The Partnership’s contractual interest obligations totaled $33.4 million for the three months ended March 31, 2020.  However, as a result of the Foresight Chapter 11 Cases, $8.2 million of that amount was automatically stayed.

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 March 31, 2020.

Transactions with Murray Energy and Affiliates (including Javelin Global Commodities)

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. In March 2017, 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 March 31, 2020).

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 $71.0 million at March 31, 2020, with unearned income equal to $21.3 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 March 31, 2020, the outstanding Transport Lease financing receivable was $48.8 million, of which the entire amount was reserved owing to the uncertainty arising from the Murray Energy bankruptcy.

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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 $26.2 million at March 31, 2020, with unearned income equal to $15.1 million. The payments the Partnership receives with respect to the ORRA are reflected partially as a return of the initial investment (reduction in the affiliate financing receivable) and partially as other revenue over the life of the agreement using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned.  As of March 31, 2020, the outstanding ORRA financing receivable was $11.0 million, of which the entire amount was reserved owing to the uncertainty arising from the Murray Energy bankruptcy.

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

We had 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. No capacity was utilized under this arrangement during the three months ended March 31, 2020.  To compensate the Partnership for the reduced contractual liquidated damages, Murray Energy reimbursed the Partnership $1.9 million for the three months ended March 31, 2019. The amounts are included in transportation on the consolidated statements of operations.

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.  We also enter into combined procurement transactions with Murray Energy to combine scale and increase purchasing leverage.  

From time to time, we may 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”), affiliates of Foresight Reserves. Each of these leases have initial terms of 10 years with six renewal periods at the election of the lessees, and generally require the lessees to pay the greater of a per ton amount or a percentage 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 a percentage 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 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.

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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. During the three months ended March 31, 2020, CRDC and the Cline Trust divested their holding of our Term Loan due 2022 and our Second Lien Notes due 2023.

The Cline Trust is also a holder of 17,556 of FELP’s outstanding warrants as of March 31, 2020.

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

Affiliated Company	Balance Sheet Location	March 31, 2020			December 31, 2019
		(In Thousands)
Murray Energy	Due from affiliates - current	$	10,189		$	8,658
Javelin	Due from affiliates - current		8,155			14,473
less: Reserve on amounts due from Murray Energy (1)	Due from affiliates - current		(1,382	)		—
Total - Due from affiliates - current		$	16,962		$	23,131
Murray Energy (2)	Financing receivables - affiliate - current	$	—		$	297
Murray Energy	Financing receivables - affiliate - noncurrent	$	59,815		$	60,408
less: Reserve on amounts due from Murray Energy (1)	Financing receivables - affiliate - noncurrent		(59,815	)		(60,408	)
Total - Financing receivables - affiliate - noncurrent		$	—		$	—
Murray Energy	Due to affiliates - current	$	520		$	6,505
Javelin	Due to affiliates - current		385			6,364
Foresight Reserves and affiliated entities	Due to affiliates - current	$	1,420			2,967
Total - Due to affiliates - current		$	2,325		$	15,836
Murray Energy	Liabilities subject to compromise	$	5,877		$	—
Javelin	Liabilities subject to compromise		6,417			—
Total - Liabilities subject to compromise		$	12,294		$	—

(1) The reserve on amounts due from affiliates, representing amounts invoiced but not yet collected on the Transport Lease and ORRA, and the reserve on financing receivables related to the Transport Lease and ORRA, result from the uncertainty arising from the Murray Chapter 11 Cases (defined below).  

(2) Net financing receivables – affiliate of $0.3 million at December 31, 2019, represent amounts invoiced and collected on the Transport Lease and ORRA in 2020.

Murray Energy Bankruptcy

On October 29, 2019, Murray Energy Holdings Co. and certain of its direct and indirect subsidiaries (collectively, and excluding FELP and its direct and indirect subsidiaries, the “Murray Debtors”) filed voluntary petitions for relief under chapter 11 of the Bankruptcy Code (the “Murray Chapter 11 Cases”) in the United States Bankruptcy Court for the Southern District of Ohio Western Division (the “Murray Bankruptcy Court”). The Murray Debtors will continue to manage their properties and operate their businesses as a “debtor in possession” under the jurisdiction of the Murray Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Murray Bankruptcy Court.

In its filings with the Murray Bankruptcy Court, the Murray Debtors have indicated that they intend to continue performing their obligations under the various agreements with FELP and certain of its direct and indirect subsidiaries during the pendency of the Murray Chapter 11 Cases. On October 31, 2019, the Bankruptcy Court approved an order permitting the Murray Debtors to continue performing their intercompany transactions with FELP. In addition, the board of directors of FELP GP LLC has appointed a conflicts committee composed of independent directors tasked with closely monitoring the Murray Chapter 11 Cases and protecting FELP’s interests with respect to the Murray Debtors.  Although FELP and the Murray Debtors currently intend to continue performing their respective obligations under the agreements among FELP and the Murray Debtors, there can be no assurance that FELP or the Murray Debtors will not, in the future, reject, repudiate, renegotiate or terminate any or all of such agreements. As a result, our ability to receive payments on our arrangements with the Murray Debtors may be impaired pending the outcome of the Murray Chapter 11 Cases, if the operation of any Murray Energy mines were to cease, or if Murray Energy’s creditworthiness was to deteriorate further.  The Partnership would bear the risk for any Murray Energy payment default.

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A summary of (income) expenses incurred with affiliated entities is as follows for the three months ended March 31, 2020 and 2019:

	Three Months Ended March 31, 2020			Three Months Ended March 31, 2019
	(In Thousands)
Transactions with Murray Energy
Coal sales (1)	$	(27,128	)	$	(15,124	)
Purchased coal (6)	$	—		$	2,375
Transport Lease revenues (2)	$	(406	)	$	(1,215	)
ORRA revenues (2)	$	(141	)	$	(520	)
Goods and services purchased (5)	$	1,212		$	1,772
Goods and services provided (8)	$	(12	)	$	(25	)
Management services (7)	$	4,290		$	4,285
Transactions with Javelin
Coal sales (1)	$	(17,704	)	$	(126,388	)
Transportation services on certain export sales (4)	$	235		$	2,311
Sales and marketing expenses (7)	$	223		$	2,068
Transactions with Foresight Reserves and Affiliated Entities
Royalty expense (3)	$	5,474		$	6,507
Land leases (3), (4)	$	32		$	82

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 income (loss) per common and subordinated unit for the three month periods indicated:

	Three Months Ended March 31,						Three Months Ended March 31,
	2020						2019
	Common Units		Subordinated Units		Total		Common Units			Subordinated Units			Total
	(In Thousands, Except Per Unit Data)						(In Thousands, Except Per Unit Data)
Numerator:
Net income (loss) available to limited partner units	$	19,811	$	15,887	$	35,698	$	(7,168	)	$	(9,653	)	$	(16,821	)
Denominator:
Weighted-average units to calculate basic EPU		80,997		64,955		145,952		80,915			64,955			145,870
Plus: effect of dilutive securities (1)		—		—		—		—			—			—
Weighted-average units to calculate diluted EPU		80,997		64,955		145,952		80,915			64,955			145,870
Basic net income (loss) per unit	$	0.24	$	0.24	$	0.24	$	(0.09	)	$	(0.15	)	$	(0.12	)
Diluted net income (loss) per unit	$	0.24	$	0.24	$	0.24	$	(0.09	)	$	(0.15	)	$	(0.12	)

(1) Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three months ended March 31, 2020, there were no unvested units outstanding owing to the cancellation of the Long Term Incentive Plan. For the three months ended March 31, 2019, approximately 0.4 million unvested units 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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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 March 31, 2020, 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 March 31, 2020 and December 31, 2019 was $178.9 million and $398.4million, respectively. The fair value of long-term debt was calculated based on (i) quoted prices in markets that are not active and (ii) the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms.  These are considered Level 2 and Level 3 fair value measurements, respectively.

12. Contingencies

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 March 31, 2020, we have $1.3 million accrued, in aggregate and included within liabilities subject to compromise, for various litigation matters.

Coronavirus (COVID-19)

On March 11, 2020, the World Health Organization declared the outbreak of the novel strain of the coronavirus (COVID-19) a global pandemic. As a result, social and economic uncertainties have arisen which potentially could negatively impact our operations. Other financial impacts could occur, though any such potential impact is unknown at this time.         

Performance Bonds

We had outstanding surety bonds with third parties of $98.2 million as of March 31, 2020 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. Mineral reserve leases are exempt from the balance sheet recognition requirements of the ASC 842 Leases.

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	March 31, 2020		December 31, 2019
		(In Thousands)
Assets
Operating lease right-of-use assets	Other assets	$	3,826		4,576
Operating lease right-of-use assets - affiliate	Other assets		1,843		1,867
Total lease right-of-use assets		$	5,669	$	6,443
Liabilities
Current:
Operating lease liabilities	Accrued expenses and other current liabilities	$	1,873	$	2,201
Operating lease liabilities - affiliate	Accrued expenses and other current liabilities		175		175
Non-current:
Operating lease liabilities	Other long-term liabilities		1,953		2,375
Operating lease liabilities - affiliate	Other long-term liabilities		1,668		1,692
Total lease liabilities		$	5,669	$	6,443

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Lease Cost	Statement of Operations Location	Three Months Ended March 31, 2020		Three Months Ended March 31, 2019
		(In Thousands)
Operating lease cost (2)	Cost of coal produced (excluding depreciation, depletion and amortization); Transportation; Selling, general and administrative	$	541	$	1,144
Operating lease cost - affiliate	Cost of coal produced (excluding depreciation, depletion and amortization); Transportation		32		82
Variable operating lease cost (1)	Cost of coal produced (excluding depreciation, depletion and amortization)		—		2,600
Finance lease cost (3):
Amortization of right-of-use assets	Depreciation, depletion and amortization		—		3,602
Interest on lease liabilities	Interest expense, net		—		176
Total lease cost		$	573	$	7,604

(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. Amounts for the three months ended March 31, 2020 are reflective of the provisions contained within the NRP Restructuring Support Agreement (see Note 1).

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

(3) In November 2019 all amounts associated with finance lease obligations were repaid and ownership of the related equipment was transferred to the Partnership.

Lease Terms and Discount Rates	March 31, 2020
Weighted-average remaining lease term (years)
Operating leases		6.8
Operating leases - affiliate		18.6
Weighted-average discount rate
Operating leases		7.00	%
Operating leases - affiliate		7.00	%

Other Information	Three Months Ended March 31, 2020		Three Months Ended March 31, 2019
	(In Thousands)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	810	$	1,058
Operating cash flows from operating leases - affiliate		56		56
Operating cash flows from finance leases (1)		—		184
Financing cash flows from finance leases (1)		—		2,974
Lease assets obtained in exchange for new operating lease liabilities		—		1,370

(1) In November 2019 all amounts associated with finance lease obligations were repaid and ownership of the related equipment was transferred to the Partnership.

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The following presents future minimum lease payments, by year, with initial terms greater than one year, as of March 31, 2020:

	Operating Leases			Operating Leases – Affiliate			Total
	(In Thousands)
2020 (remaining)	$	1,561		$	94		$	1,655
2021		1,240			150			1,390
2022		231			150			381
2023		231			150			381
2024		163			150			313
Thereafter		1,576			2,099			3,675
Total lease payments		5,002			2,793			7,795
Less: interest		(1,176	)		(950	)		(2,126	)
Total lease liabilities	$	3,826		$	1,843		$	5,669

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 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.

As a result of the NRP Restructuring Support Agreement (see Note 1), the terms and future expected cash flows of the Macoupin Sale-Lease were modified such that a gain of $93.4 million was recognized and included in reorganization items, net, on the condensed consolidated statements of operations during the three months ended March 31, 2020.  At March 31, 2020 and December 31, 2019, the carrying value of the Macoupin Sale-Leaseback was $8.0 million and $104.8 million, respectively. The effective interest rate on the financing obligation was 0.0% and 8.1% as of March 31, 2020 and December 31, 2019, respectively. Interest expense was $0.3 million and $4.6 million for the three months ended March 31, 2020 and 2019, respectively.  As of March 31, 2020 and December 31, 2019, interest of $0.0 million and $0.2 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

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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”).

As a result of the NRP Restructuring Support Agreement (see Note 1), the terms and future expected cash flows of the Sugar Camp Sale-Lease were modified such that a gain of $4.5 million was recognized and included in reorganization items, net, on the condensed consolidated statements of operations during the three months ended March 31, 2020.  At March 31, 2020 and December 31, 2019, the carrying value of the Sugar Camp Sale-Leaseback was $51.1 million and $55.3 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 1.5% and 3.5% at March 31, 2020 and December 31, 2019, respectively. Interest expense was $0.2 million and $1.3 million for the three months ended March 31, 2020 and 2019, respectively.  As of March 31, 2020 and December 31, 2019, interest of $0.0 million and $0.1 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 and the NRP Restructuring Support Agreement, on the Partnership’s sale-leaseback financing arrangements at March 31, 2020:

	Sale-Leaseback Financing Arrangements
	(In Thousands)
2020 (remaining)	$	2,000
2021		2,000
2022		5,408
2023		6,829
2024		4,901
Thereafter		37,970
Total	$	59,108

The aggregate amounts of remaining minimum lease payments on the Partnership’s sale-leaseback financing arrangements are $59.3 million. Minimum payments from March 31, 2020 through 2024, reflective of the NRP Restructuring Support Agreement, are as follows:

	2020 (remaining)		2021		2022		2023		2024
Minimum lease payments	$	2,000	$	2,000	$	7,000	$	7,000	$	5,000

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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14. Reorganization Items, Net

The Partnership’s reorganization items for the three months ended March 31, 2020 consisted of the following:

	Three Months Ended March 31, 2020
	(In Thousands)
Professional fees	$	12,750
Accounts payable settlement gains		(22	)
Gains on modification of sale-leaseback financing arrangements		(97,856	)
Reorganization items, net	$	(85,128	)

Cash payments for reorganization items totaled $10.2 million during the three months ended March 31, 2020.  Professional fees include approximately $6.9 million of amounts directly attributable to Foresight Chapter 11 Cases but incurred prior to the Petition Date.

15. Liabilities Subject to Compromise

Liabilities subject to compromise include unsecured or under-secured liabilities incurred prior to the Petition Date.  These liabilities represent the amounts expected to be allowed on known or potential claims to be resolved through the Foresight Chapter 11 Cases and remain subject to future adjustments based on negotiated settlements with claimants, actions of the Bankruptcy Court, rejection of executory contracts, proofs of claims or other events.  Additionally, liabilities subject to compromise also include certain items that may be assumed under a plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise.  Generally, actions to enforce or otherwise effect payment of prepetition liabilities are subject to the automatic stay or an approved motion of the Bankruptcy Court, as discussed in Note 1.

Liabilities subject to compromise consisted of the following:

	March 31, 2020
	(In Thousands)
Debt obligations	$	1,318,059
Accrued interest		66,138
Accounts payable		93,097
Accrued expenses and other liabilities		19,749
Due to affiliates		12,294
Liabilities subject to compromise	$	1,509,337

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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 Foresight Chapter 11 Cases and associated effects;

•   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;

• Force majeure events and the economic impact related to COVID-19.

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 April 6, 2020.

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 73 million tons of coal reserves associated with our recently idled Macoupin 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 three operating underground mining complexes in the Illinois Basin: Williamson, Sugar Camp, and Hillsboro which are

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longwall operations.  Macoupin, which was a continuous miner operation, was idled in March 2020 owing to the significant challenges in the thermal coal markets.  The Williamson and Hillsboro complexes operating one longwall system each; the Sugar Camp complex operates with two longwall mining systems.

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.  In March 2020, longwall production resumed 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 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.

The thermal coal markets that we traditionally serve have been meaningfully challenged over the past three to four years, and deteriorated significantly in the last year. This sector-wide decline has been driven largely by (a) the closure of approximately 93,000 megawatts of coal-fired electric generating capacity in the United States, (b) a record production of inexpensive natural gas, and (c) the growth of wind and solar energy, with gas and renewables, displacing coal used by U.S. power plants.

During its peak in 2007, coal was the power source for half of electricity generation in the United States and by the end of 2019, coal-fired electricity generation fell to approximately 23 percent. These challenges have intensified recently as (i) certain electric utility companies have filed for bankruptcy protection and others have sought, and received, subsidies for their nuclear generation capacity to avoid bankruptcy, at the expense of coal-fired facilities, (ii) domestic natural gas prices hit 20-year lows this past summer, (iii) overall demand for electricity in the United States declined two percent in 2019, and (iv) the recent coronavirus (COVID-19) pandemic has led to declines in commercial and industrial electricity demand. At the same time, demand for U.S. coal from international utilities has been subject to its own set of negative forces, and the European benchmark price for thermal coal has continued its decline since late 2018.

Filing Under Chapter 11 of the Bankruptcy Code

On the Petition Date, we commenced the Foresight Chapter 11 Cases in the Bankruptcy Court.  Further information regarding our bankruptcy filing under Chapter 11 of the Bankruptcy Code, as well as information on our liquidity, capital resources, debt obligations and going concern matters, are disclosed in Part I. “Item 1. Financial Statements – Note 1. Organization, Nature of Business and Basis of Presentation” of this Quarterly Report on Form 10-Q.

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,contract amortization, reorganization itemsandmaterialnonrecurringorotheritems whichmaynotreflectthetrendoffutureresults. 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.

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Results of Operations

Comparison of the Three Months Ended March 31, 2020 to the Three Months Ended March 31, 2019

Coal Sales. The following table summarizes coal sales information during the three months ended March 31, 2020 and 2019 (in thousands, except per ton data).

	Three Months Ended March 31, 2020		Three Months Ended March 31, 2019		Variance
Coal sales	$	99,142	$	267,337	$	(168,195	)	-62.9	%
Tons sold		3,232		5,696		(2,464	)	-43.3	%
Coal sales realization per ton sold(1)	$	30.68	$	46.93	$	(16.25	)	-34.6	%
Netback to mine realization per ton sold(2)	$	30.33	$	36.61	$	(6.28	)	-17.2	%
(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 combined with lower coal sales realization per ton sold.  Coal sales volumes for the three months ended March 31, 2020 were lower as compared to the prior year period due to lower domestic and export market demand.  Lower overall coal sales realizations were primarily due to decreased pricing on export volumes, which were a function of market considerations as well as modified sales terms of our export contracts, whereby our mines are the delivery point of our export volumes in exchange for our customers bearing the responsibility and cost of transporting the coal to export facilities on the Gulf of Mexico.  

Cost of Coal Produced (Excluding Depreciation, Depletion and Amortization). The following table summarizes cost of coal produced (excluding depreciation, depletion and amortization) information for the three months ended March 31, 2020 and 2019 (in thousands, except per ton data).

	Three Months Ended March 31, 2020		Three Months Ended March 31, 2019		Variance
Cost of coal produced (excluding depreciation,   depletion and amortization)	$	79,985	$	133,981	$	(53,996	)	-40.3	%
Produced tons sold		3,232		5,646		(2,414	)	-42.8	%
Cash cost per ton sold(1)	$	24.75	$	23.73	$	1.02		4.3	%
Tons produced		3,819		6,065		(2,246	)	-37.0	%
(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 a slight increase in the cash cost per ton sold.  The increase in cash cost per ton sold was primarily due to reduced production in response to challenging market conditions.       

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.  There were no purchases during the three months ended March 31, 2020. Purchases totaled $2.4 million during the three months ended March 31, 2019.

Transportation.Our cost of transportation for the three months ended March 31, 2020 decreased approximately $57.7 million from the three months ended March 31, 2019. This decrease was due to a decrease in produced tons sold, a larger percentage of our sales going to the export market during the prior year period, as well as modified sales terms of our export contracts, whereby our mines are the delivery point of our export volumes in exchange for our customers bearing the responsibility and cost of transporting the coal to export facilities on the Gulf of Mexico.  

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization expense for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 was primarily due to a lower depreciable and depletable asset base resulting from the aggregate impairment charge at our Macoupin complex in 2019.  

Contract Amortization. During the three months ended March 31, 2020 and 2019, we recorded amortization benefit of $1.5 million and $1.7 million, respectively, on the favorable/unfavorable sales and royalty contract assets and liabilities.     

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Selling, General and Administrative.  The decrease in selling, general and administrative expense for the three months ended March 31, 2020 as compared to the prior year period was primarily due to decreased sales and marketing expenses resulting from lower export sales volumes.

Interest Expense, Net.  Interest expense, net for the three months ended March 31, 2020 decreased as compared to the three months ended March 31, 2019 primarily as a result of the Foresight Chapter 11 Cases, in which interest on pre-petition debt obligations subsequent to the Petition Date is not required to be incurred or paid.  

Interest Expense, Net – Sale-Leaseback Financing Arrangements. Revisions to the mine plans and modifications under the NRP Restructuring Support Agreement resulted in a decrease of $5.4 million in interest expense on sale-leaseback financing arrangements during the three months ended March 31, 2020 as compared to the prior year period. We account for such changes by adjusting, in the period of the change, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied).

Reorganization Items, Net.  Reorganization items includes $12.8 million of legal and financial advisor professional fees related to the Foresight Chapter 11 Cases discussed in “Item 1. Financial Statements – Note 1. Organization, Nature of Business and Basis of Presentation” of this Quarterly Report on Form 10-Q.  We expect professional fees to continue to be substantial until such time that these issues are remediated.  Also included in reorganization items are gains totaling $97.9 million on the sale-leaseback financing arrangements resulting from modifications under the NRP Restructuring Support Agreement.

Adjusted EBITDA. Adjusted EBITDA decreased $53.5 million from the prior year period due to overall decreased sales volumes and lower coal sales realization per ton in the current year period. The table below reconciles net income (loss) to Adjusted EBITDA for the three months ended March 31, 2020 and 2019 (in thousands).

	Three Months Ended March 31, 2020			Three Months Ended March 31, 2019
Net income (loss)	$	35,698		$	(16,821	)
Interest expense, net		25,204			30,817
Interest expense, net - sale-leaseback financing arrangements		539			5,893
Depreciation, depletion and amortization		36,511			46,548
Accretion on asset retirement obligations		684			551
Contract amortization		(1,456	)		(1,686	)
Equity-based compensation		—			233
Reorganization items, net		(85,128	)		—
Adjusted EBITDA	$	12,052		$	65,535

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

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Liquidity and Capital Resources

Our liquidity has been significantly impacted by the Foresight Chapter 11 Cases.  For additional information, refer to Part I. “Item 1. Financial Statements – Note 1. Organization, Nature of Business and Basis of Presentation” of this Quarterly Report on Form 10-Q.

Our primary cash requirements include, but are not limited to, working capital needs, capital expenditures to maintain operations, and debt service costs (interest and principal). Our primary sources of operating liquidity consist of cash generated from operations, cash on hand, and the $175 million DIP Facility. As of March 31, 2020, we had $61.3 million of cash on hand, which includes $55 million of borrowings on the DIP Facility at the DIP Closing Date.  In April 2020, the additional $45 million of new money was funded by the DIP Facility.  

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.

Murray Energy Bankruptcy

On October 29, 2019, Murray Energy Holdings Co. and certain of its direct and indirect subsidiaries (collectively, and excluding FELP and its direct and indirect subsidiaries, the “Murray Debtors”) filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Ohio Western Division (the “Murray Bankruptcy Court”). The Murray Debtors sought, and received, Bankruptcy Court authorization to jointly administer the chapter 11 cases (the “Murray Chapter 11 Cases”) under the caption “In re: Murray Energy Holdings Co., et al.” Case No. 19-56885. The Murray Debtors will continue to manage their properties and operate their businesses as a “debtor in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

As of March 31, 2020, the Partnership had amounts receivable from Murray Energy and its subsidiaries (excluding Javelin) of $8.8 million included in due from affiliates on the consolidated balance sheet. This amount is net of a reserve of $1.4 million related to amounts invoiced but not collected under the Transport Lease and ORRA. Additionally, the financing receivables associated with the Transport Lease and ORRA, totaling $59.8 million, are fully reserved at March 31, 2020.  The Partnership also had amounts payable to Murray Energy and its subsidiaries (excluding Javelin) of $6.4 million at March 31, 2020.  

In its filings with the Murray Bankruptcy Court, the Murray Debtors have indicated that they intend to continue performing their obligations under the various agreements with FELP and certain of its direct and indirect subsidiaries during the pendency of the Murray Chapter 11 Cases. On October 31, 2019, the Bankruptcy Court approved an order permitting the Murray Debtors to continue performing their intercompany transactions with FELP. In addition, the board of directors of FELP GP LLC has appointed a conflicts committee composed of independent directors tasked with closely monitoring the Murray Chapter 11 Cases and protecting FELP’s interests with respect to the Murray Debtors.  Although FELP and the Murray Debtors currently intend to continue performing their respective obligations under the agreements among FELP and the Murray Debtors, there can be no assurance that FELP or the Murray Debtors will not, in the future, reject, repudiate, renegotiate or terminate any or all of such agreements. As a result, our ability to receive payments on our arrangements with the Murray Debtors may be impaired pending the outcome of the Murray Chapter 11 Cases, if the operation of any Murray Energy mines were to cease, or if Murray Energy’s creditworthiness was to deteriorate further.    The Partnership would bear the risk for any Murray Energy payment default. The failure to collect payment under these receivables and financing arrangements may materially adversely affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.  Considering these factors, the Partnership has recorded full reserves on all receivable amounts associated with the Transport Lease and ORRA long-term financing arrangements with subsidiaries of Murray Energy.

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Changes in Cash Flows

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

	Three Months Ended March 31, 2020			Three Months Ended March 31, 2019
	(In Thousands)
Net cash (used in) provided by operating activities	$	(12,192	)	$	49,167
Net cash used in investing activities	$	(9,627	)	$	(34,273	)
Net cash provided by (used in) financing activities	$	49,214		$	(11,677	)

For the three months ended March 31, 2020, net cash used in operating activities was $12.2 million compared to net cash provided by operating activities of $49.2 million for the three months ended March 31, 2019. The decrease in cash provided by operating activities for the current period is primarily the result of decreased coal sales revenues, the payment of professional fees associated with the Foresight Chapter 11 Cases, and various working capital variances.  Significant working capital variances as compared to the prior period included:

• a $4.6 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 $16.8 million unfavorable variance in accounts payable and accrued expenses which is a function of the timing of vendor payments; and

• a $13.6 million favorable variance in accrued interest which is a function of the timing of interest payments on our long-term debt obligations.

For the three months ended March 31, 2020, net cash used in investing activities was $9.6 million compared to $34.3 million net cash used in investing activities for the three months ended March 31, 2019.  Cash used in investing activities in the current year period was primarily for maintenance capital expenditures.  Cash used in investing activities in the prior year period was higher as it included land purchases totaling $6.1 million, the completion of a new portal at our Sugar Camp complex, and development of our Hillsboro complex.    

For the three months ended March 31, 2020, net cash provided by financing activities was $49.2 million compared to $11.7 million used in financing activities for the three months ended March 31, 2019. Cash provided by financing activities in the current year period resulted from $55.0 million in borrowings on the DIP Facility, offset by the payment of $1.7 million in fees and costs associated with the DIP Facility, and $4.1 million in payments on sale-leaseback and short-term financing arrangements.  In the prior year period, cash used in financing activities primarily related to $8.0 million in net borrowings on the Revolving Credit Facility, offset by $10.7 million in payments on long-term debt and finance lease obligations, $4.9 million in distributions paid to common unitholders, and $4.1 million in payments on sale-leaseback and short-term financing arrangements.  

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Long-Term Debt and Sale-Leaseback Financing Arrangements

Debtor-in-Possession Credit and Guarantee Agreement (the “DIP Facility”)

The Foresight Chapter 11 Cases are funded in part by the DIP Facility. The DIP Facility consists of a $100 million new money, multi-draw term loan facility and a $75 million term loan facility which shall roll-up certain first-priority pre-petition claims of the DIP Facility lenders.  The DIP Facility bears interest at LIBOR (subject to a floor of 1.00%) plus 11.00% per annum and is subject to customary fees, covenants, and milestones.  For additional information on the DIP Facility, refer to Part I. “Item 1. Financial Statements – Note 1. Organization, Nature of Business and Basis of Presentation” of this Quarterly Report on Form 10-Q.

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:

•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 agreement governing our Credit Facilities requires us to prepay outstanding borrowings, subject to certain exceptions. 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 agreement governing our Credit Facilities requires 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.  We were not in compliance with the maximum net first lien secured leverage ratio as of March 31, 2020.

As of March 31, 2020, $743.3 million in principal was outstanding under the Term Loan due 2022 and there was $157.0 million in borrowings outstanding under the Revolving Credit Facility.

As a result of the Foresight Chapter 11 Cases, the principal and interest due under the Credit Facilities are classified as a liability subject to compromise on the Partnership’s consolidated balance sheet as of March 31, 2020, as any efforts to enforce payment obligations under the Credit Facilities are automatically stayed as a result of the Foresight Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Credit Facilities are subject to the applicable provisions of the Bankruptcy Code.

Further information regarding our Credit Facilities is disclosed in Part I. “Item 1. Financial Statements – Note 1. Organization, Nature of Business and Basis of Presentation” of this Quarterly Report on Form 10-Q.

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Description of the 11.50% 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.

As of March 31, 2020, $425.0 million in principal was outstanding under the Second Lien Notes due 2023.

As a result of the Foresight Chapter 11 Cases, the principal and interest due under the Second Lien Notes due 2023 are classified as a liability subject to compromise on the Partnership’s consolidated balance sheet as of March 31, 2020, as any efforts to enforce payment obligations under the Second Lien Notes due 2023 are automatically stayed as a result of the Foresight Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Second Lien Notes due 2023 are subject to the applicable provisions of the Bankruptcy Code.

Further information regarding our Second Lien Notes due 2023 is disclosed in Part I. “Item 1. Financial Statements – Note 1. Organization, Nature of Business and Basis of Presentation” of this Quarterly Report on Form 10-Q.

Sale-Leaseback Financing Arrangements

Refer to “Item 1. Financial Statements – Note 13. Leases” of this Quarterly Report on Form 10-Q for information on the sale-leaseback financing arrangements.

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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 March 31, 2020, we had $2.0 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 $98.2 million as of March 31, 2020 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 April 6, 2020.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

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

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions in certain circumstances that affect amounts reported in the accompanying condensed consolidated financial statements and related footnotes. In preparing these financial statements, we have made our best estimates of certain amounts included in the financial statements. Application of these accounting policies and estimates, however, involves the exercise of judgment and use of assumptions as to future uncertainties, and as a result, actual results could differ from these estimates. In arriving at our critical accounting estimates, factors we consider include how accurate the estimates or assumptions have been in the past, how much the estimates or assumptions have changed and how reasonably likely such change may have a material impact. Our critical accounting policies and estimates are more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report on Form 10-K filed with the SEC on April 6, 2020.  There have been no significant changes to our prior critical accounting policies and estimates subsequent to December 31, 2019, or new accounting pronouncements impacting our results.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Commodity Price Risk

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

Interest Rate Risk

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At March 31, 2020, outstanding borrowings on our DIP Facility have interest rates that fluctuate based on changes in market interest rates. A one percentage point increase in the interest rates related to our borrowings on the DIP Facility would result in an annualized increase in interest expense of approximately $0.6 million.

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Item 4. Controls and Procedures.

We evaluated, under the supervision and with the participation of our management, including our chief executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2020. 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 April 6, 2020.

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 April 6, 2020, 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 we face. 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 March 31, 2020 to the risk factors previous disclosed in our Annual Report on Form 10-K filed with the SEC on April 6, 2020.

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

None.

Item 3. Defaults Upon Senior Securities.

Information regarding our debt arrangements are disclosed in Part I. “Item 1. Financial Statements – Note 1. Organization, Nature of Business and Basis of Presentation” of this Quarterly Report on Form 10-Q.

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 Quarterly Report on Form 10-Q.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Foresight Energy LP (f/k/a Foresight Energy Partners LP) (incorporated herein by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 filed on February 2, 2012 (SEC File No. 333-179304)).
3.2	First Amended and Restated Agreement of Limited Partnership of Foresight Energy LP (incorporated herein by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on June 23, 2014 (SEC File No. 001-36503)).
3.3	First Amendment to First Amended and Restated Agreement of Limited Partnership of Foresight Energy LP, dated as of August 30, 2016, entered into by Foresight Energy GP LLC (incorporated herein by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on September 6, 2016 (SEC File No. 001-36503)).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
32.1**	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2012.
32.2**	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2012.
95.1*	Mine Safety Disclosure Exhibit.
101*	Interactive Data File (Form 10-Q for the quarter ended March 31, 2020) 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 May 15, 2020.

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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