UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended September 30, 2016

OR

For the transition period from          to          

Commission File Number: 001-36503

 

Foresight Energy LP

(Exact Name of Registrant as Specified in its Charter)

 

 

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

 

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 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 November 4, 2016, the registrant had 66,104,673 common units and 64,954,691 subordinated units outstanding.

 

 

 

 

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TABLE OF CONTENTS

 

PART I

FINANCIAL INFORMATION

 

 

 

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PART I – FINANCIAL INFORMATION.

 

Item 1. Financial Statements.

Foresight Energy LP

Unaudited Condensed Consolidated Balance Sheets

 

 

See accompanying notes.

 

 

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Foresight Energy LP

Unaudited Condensed Consolidated Statements of Operations

 

 

See accompanying notes.

 

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Foresight Energy LP

Unaudited Condensed Consolidated Statement of Partners’ (Deficit) Capital

 

 

See accompanying notes.

 

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Foresight Energy LP

Unaudited Condensed Consolidated Statements of Cash Flows

 

See accompanying notes.

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Foresight Energy LP

Notes to Unaudited Condensed Consolidated Financial Statements

 

1. Organization, Nature of Business and Basis of Presentation

 

Foresight Energy LLC (“FELLC”), a perpetual-term Delaware limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves, LP (“Foresight Reserves”) owned 99.333% of FELLC and a member of FELLC’s management owned 0.667%. On June 23, 2014, in connection with the initial public offering (“IPO”) of Foresight Energy LP (“FELP”), Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common and subordinated units in FELP. FELP has been managed by Foresight Energy GP LLC (“FEGP”) since the IPO.  On April 16, 2015, Murray Energy Corporation (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% noncontrolling economic interest in FEGP and all of the outstanding subordinated units of FELP, representing a 50% ownership percentage of the Partnership’s limited partner units.

 

As used hereafter in this report, the terms “Foresight Energy LP,” “FELP,” the “Partnership,” “we,” “us” or like terms, refer to the combined consolidated results of Foresight Energy LP, and FELLC and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated. The information presented in this Quarterly Report on Form 10-Q contains, for all periods presented, the combined consolidated financial results of Foresight Energy LP, FELLC, and VIEs for which FELLC or its subsidiaries are the primary beneficiary.

 

The Partnership operates in a single reportable segment and currently has four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). Mining operations at our Hillsboro complex have been idled since March 2015 due to a combustion event (the “Hillsboro combustion event”). In April 2016, we temporarily sealed the entire mine to reduce the oxygen flow paths into the mine. We are uncertain as to when production will resume at this operation. Our mined coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern United States, as well as overseas markets. Intercompany transactions, including those between consolidated VIEs, and FELP and its consolidated subsidiaries, are eliminated in consolidation.

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, 2015 included in our Annual Report on Form 10-K filed with the SEC on March 15, 2016. The results of operations for the three and nine months ended September 30, 2016 are not necessarily indicative of results that can be expected for any future period, including the year ending December 31, 2016.

 

2. New Accounting Standards

In February 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-02, Amendments to the Consolidation Analysis. ASU 2015-02 changes the requirements and analysis required when determining the reporting entity’s need to consolidate an entity, including modifying the evaluation of limited partnership variable interest status, the presumption that a general partner should consolidate a limited partnership and the consolidation criterion applied by a reporting entity involved with variable interest entities. We adopted ASU 2015-02 during the first quarter of 2016 and it did not have an impact on our historical consolidation conclusions.

 

In April 2015, the FASB issued ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings of a transferred business before the date of a dropdown transaction should not be allocated to the limited partnership and therefore earnings per unit of the limited partners would not change as a result of the dropdown transaction. We adopted ASU 2015-06 during the first quarter of 2016 and it did not have an effect on our condensed consolidated financial statements or related disclosures.

 

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct

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deduction from the carrying amount of that debt liability, consistent with debt discounts. We adopted ASU 2015-03 on a retrospective basis during the first quarter of 2016. The adoption of ASU 2015-03 did not affect our results of operations or cash flows, but it required us to reclassify the deferred financing costs associated with certain of our long-term debt. We reclassified approximately $15.9 million of our deferred financing costs as of December 31, 2015 to long-term debt and capital lease obligations in our condensed consolidated financial statements to adhere to ASU 2015-03. The deferred financing costs associated with our revolving credit facility and trade AR securitization program continue to be presented as an asset on the condensed consolidated balance sheets.

 

In February 2016, the FASB issued ASU 2016-02, Leases, which contains updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements.

 

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation, which was issued to simplify the accounting for share-based payment transactions, including income tax consequences, the classification of awards as equity or liabilities, an option to recognize gross equity-based compensation expense with actual forfeitures recognized as they occur and the classification on the statement of cash flows. This pronouncement is effective for reporting periods beginning after December 15, 2016. We do not expect the adoption of this update to have a material impact on our consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Payments, which provides guidance on eight specific cash flow issues with the objective of reducing diversity in practice. The guidance is effective for interim and annual periods beginning after December 15, 2017. We early adopted this standard during the current quarter and as a result presented all cash costs for debt prepayment and debt extinguishment as cash outflows from financing activities. The prior period presented had no such costs.

No other new accounting pronouncement issued or effective during the fiscal year which was not previously disclosed in our Annual Report on Form 10-K had, or is expected to have, a material impact on our consolidated financial statements or related disclosures.

 

 

3. Restructuring Transactions

 

On December 4, 2015, the Delaware Court of Chancery issued a memorandum opinion concluding, among other things, that the purchase and sale agreement between Foresight Reserves and Murray Energy (see Note 13) constituted a change of control under the indenture (the “Indenture”) governing our 7.875% Senior Notes due 2021 (the “2021 Senior Notes”) and that an event of default occurred under the Indenture when we failed to offer to purchase the 2021 Senior Notes on or about May 18, 2015 (the “2015 Delaware Court of Chancery change-of-control litigation”). Because of the existence of “change of control” provisions and cross-default or cross-event of default provisions in our debt agreements, the purchase and sale agreement between Foresight Reserves and Murray Energy also resulted, directly or indirectly, in events of default under FELLC’s credit agreement governing its senior secured credit facilities (the “Credit Agreement”), Foresight Receivables LLC’s securitization program and certain other financing arrangements, including our longwall financing arrangements. The existence of an event of default prohibited us access to borrowings or other extensions of credit under our revolving credit facility and our failure to pay the semi-annual interest payments of $23.6 million due on February 15, 2016 and August 15, 2016 resulted in additional events of default. These conditions and circumstances above raised prior substantial doubt about the Partnership’s ability to continue as a going concern and therefore our auditor’s issued an audit opinion in connection with our 2015 consolidated financial statements with a “going concern” uncertainty explanatory paragraph.

 

On July 22, 2016, we entered into Amended and Restated Transaction Support Agreements (the “A&R Notes Transaction Support Agreements”) with existing consenting noteholders of the 2021 Senior Notes and certain equityholders of the Partnership, including Christopher Cline, Foresight Reserves LP and certain of its related parties and affiliates and Murray Energy, pursuant to which the parties agreed to modified terms of the restructuring of the Partnership’s indebtedness and certain governance and equity matters relating to the Partnership.

 

On August 30, 2016 (the “Closing Date”), we completed a global restructuring of our indebtedness. The restructuring transactions (the “Restructuring Transactions”), as described herein, alleviated existing defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Court of Chancery change-of-control litigation related to the purchase and sale agreement between Foresight Reserves and Murray Energy. See Notes 10 and 13 for additional discussion on the debt restructuring and certain governance and other matters impacted by the Restructuring Transactions.

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During the three and nine months ended September 30, 2016, we incurred legal and financial advisor fees of $6.1 million and $21.7 million, respectively, related to the above issues, which have been recorded as debt restructuring costs in the condensed consolidated statements of operations.

 

 

4. Transition and Reorganization Costs

 

In April 2015, in connection with Murray Energy acquiring an ownership interest in the Partnership and its general partner, we entered into a Management Services Agreement with Murray American Coal Inc. (the “Manager”), a subsidiary of Murray Energy (the “MSA”), with the intent of optimizing and reorganizing certain corporate administrative functions and generating synergies between the two companies through the elimination of headcount and duplicate selling, general and administrative expenses (see Note 13). The costs were primarily comprised of retention compensation to certain employees during the transition period and termination benefits to employees whose positions were eliminated as a result of the MSA. Transition and reorganization costs were comprised of the following for the three and nine months ended September 30, 2016 and 2015:

 

 

5. Commodity Derivative Contracts

The Partnership has commodity price risk for its coal sales as a result of changes in the market value of its coal. To minimize this risk, we enter into long-term, fixed price coal supply sales agreements and coal derivative swap contracts.

As of September 30, 2016 and December 31, 2015, we had outstanding coal derivative swap contracts to fix the selling price on 0.7 million tons and 1.1 million tons, respectively. Swaps are designed so that the Partnership receives or makes payments based on a differential between fixed and variable prices for coal. The coal derivative contracts are economic hedges to certain future unpriced (indexed) sales commitments through 2017. The coal derivative contracts are indexed to the Argus API 2 price index, the benchmark price for coal imported into northwest Europe. The coal derivative contracts are accounted for as freestanding derivatives and any gains or losses resulting from adjusting these contracts to fair value are recorded into earnings. We record the fair value of all positions with a given counterparty on a gross basis in the condensed consolidated balance sheets (see Note 17).

We have diesel fuel price exposure in our transportation and production processes and therefore are subject to commodity price risk as a result of changes in the market value of diesel fuel. Beginning in 2015, to limit our exposure to diesel fuel price volatility, we entered into swap agreements with financial institutions which provide a fixed price per unit for the volume of purchases being hedged. As of September 30, 2016 and December 31, 2015, we had swap agreements outstanding for 2016 to hedge the variable cash flows related to 0.3 million and 1.0 million gallons, respectively, of diesel fuel. The diesel fuel derivative contracts are accounted for as freestanding derivatives, and any gains or losses resulting from adjusting these contracts to fair value are recorded into earnings.

We have master netting agreements with all of our counterparties that allow for the settlement of contracts in an asset position with contracts in a liability position in the event of default. We manage counterparty risk through the utilization of investment grade commercial banks, diversification of counterparties and our counterparty netting arrangements.

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A summary of the settlements of commodity derivative contracts and (loss) gain on commodity derivative contracts for the three and nine months ended September 30, 2016 and 2015 is as follows:

 

 

We received $19.1 million in proceeds during the nine months ended September 30, 2015 from the settlement of derivatives that were reclassified from an operating cash flow activity to an investing activity in the consolidated statement of cash flows because the derivative contracts were settled prior to the expiration of their contractual maturities and prior to the delivery date of the underlying sales contracts.

 

6. Accounts Receivable

Accounts receivable consist of the following:

 

 

 

7. Inventories, Net

Inventories consist of the following:

 

 

 

8. Property, Plant, Equipment and Development, Net

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

 

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9. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following:

 

 

 

10. Long-Term Debt and Capital Lease Obligations

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

 

On August 30, 2016, we completed a global restructuring of our indebtedness. The Restructuring Transactions described below alleviated certain defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Court of Chancery change-of-control litigation related to the purchase and sale agreement between Foresight Reserves and Murray Energy. As a result of the Restructuring Transactions and the resolution of the 2015 Delaware Court of Chancery change-of-control litigation, certain of our outstanding long-term debt and capital lease obligations are no longer reflected as a current liability in the condensed consolidated balance sheets and we are no longer subject to default interest rates.

Also, as a result of the Restructuring Transactions, a loss on the early extinguishment of debt of $13.2 million was recognized during the three months ended September 30, 2016 for the write-off of $11.0 million of unamortized debt discount and debt issuance costs associated with the extinguishment of our 7.875% Senior Notes due 2021 and the reduction in borrowing capacity under our Revolving Credit Facility and due to the incurrence of $2.2 million in costs related to the modification of our debt which were expensed in accordance with the authoritative accounting literature on debt modifications. Lender and third-party professional fees totaling $13.5 million were deferred and will be amortized over the remaining lives of the respective debt instruments.

Exchange of 2021 Senior Notes for New Notes and Warrants

On the Closing Date, the Partnership exchanged $599.8 million in aggregate principal amount of our 2021 Senior Notes and the accrued and unpaid interest thereon for the following consideration:

 

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On the Closing Date, we also redeemed the remaining $175,000 in aggregate principal amount of 2021 Senior Notes that were not exchanged. Upon such redemption, the obligations under the 2021 Senior Notes were satisfied and discharged.

The Warrants were determined to meet the criteria of a detachable freestanding derivative liability instrument and the calculated fair value of the Warrants on the Closing Date was $34.0 million. See Note 17 for additional discussion on the fair value of the Warrants. A liability for the fair value of the Warrants was recorded in our condensed consolidated balance sheet as of the Closing Date and the offset was recognized as a debt discount to the New Notes.  The discount was allocated pro rata between the Second Lien Notes and the Exchangeable PIK Notes in proportion to the relative fair value of each instrument held by a person other than the Reserves Group (see Note 13) on the Closing Date (only the unaffiliated holders of the New Notes received the Warrants on the Closing Date). The $25.0 million discount allocated to the Second Lien Notes and the $9.0 million discount allocated to the Exchangeable PIK Notes will be amortized using the effective interest method over their respective maturities.

Terms of the New Notes

The Second Lien Notes were issued pursuant to an indenture and have a maturity date of August 15, 2021. The Second Lien Notes bear interest at a rate of: (i) 9.0% per annum until August 15, 2018 and 10.0% per annum thereafter, in each case, payable in cash on each interest payment date; and (ii) 1.0% per annum payable in kind. Interest will be payable semi-annually on February 15th and August 15th, commencing on February 15, 2017. The Issuers may redeem the Second Lien Notes in whole or in part subject to the redemption premiums and provisions in the indenture.  

The Exchangeable PIK Notes were issued pursuant to an indenture and have a maturity date of October 3, 2017 (the “Exchangeable PIK Notes Maturity Date”). The Exchangeable PIK Notes bear interest payable in kind at a rate of 15.0% per annum, payable on March 1, 2017 and October 3, 2017.

We may redeem, repurchase, refinance, defease or otherwise retire (any of the foregoing, a “redemption”) all of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at 100% of the principal amount thereof plus accrued interest (any such redemption, an “Exchangeable PIK Note Retirement”). In addition to the Exchangeable PIK Note Retirement, Murray Energy, an affiliate of Murray Energy or a group of persons which includes Murray Energy or any of its affiliates (collectively, the “Murray Group”) shall have the right to purchase all (but not less than all) of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at a price equal to 100% of the principal amount of the Exchangeable PIK Notes plus accrued interest (a “Murray Purchase,” and together with an Exchangeable PIK Note Retirement and any repayment of the Exchangeable PIK Notes in full in cash that occurs on the Exchangeable PIK Notes Maturity Date, a “Note Redemption”). Upon a Murray Purchase, the Murray Group will receive FELP units equal to the principal and interest settlement amount divided by the lesser of: (a) a number equal to one divided by 92.5% of the last thirty days weighted-average trading price or (b) 1.12007 common units per $1.00 principal amount of Exchangeable PIK Notes. The Issuer and Murray Energy may each purchase less than all of the Exchangeable PIK Notes, so long as the combination results in redemption of all of the Exchangeable PIK Notes. The Exchangeable PIK Note Retirement may be funded with the proceeds from an investment by the Murray Group or any member thereof in FELP, from general working capital or from any other source permitted by the Exchangeable PIK Notes Indenture (and subject to compliance with the Partnership’s other debt agreements). If the Exchangeable PIK Notes have not been redeemed or purchased for cash at 100% of the principal amount thereof plus accrued interest by the Exchangeable PIK Note Maturity Date, then all outstanding Exchangeable PIK Notes (including accrued interest) shall be exchanged for common units representing 75% of FELP’s outstanding limited partner units on the Exchangeable PIK Notes Maturity Date, subject to adjustment on account of certain anti-dilution protections.

The obligations under the New Notes are unconditionally guaranteed on a senior secured basis by each of FELP’s wholly owned domestic subsidiaries that guarantee the Senior Secured Credit Facilities (other than Foresight Energy Finance Corporation) and on a senior unsecured basis by FELP and are or will be secured by second-priority perfected liens on substantially all of our and the subsidiary guarantors’ existing and future assets, subject to certain exceptions.

Senior Secured Credit Facilities

On the Closing Date, FELLC entered into an amendment to its senior secured credit facilities (as amended, the “Senior Secured Credit Facilities”), pursuant to which outstanding defaults under its existing credit agreement were waived and the credit agreement was amended and restated as set forth in the third amended and restated credit agreement (the “Amended Credit Agreement”). Pursuant to the Amended Credit Agreement, $297.8 million in term loans remain outstanding and mature in August 2020 (the “Term Loan”) and the commitments under our $550.0 million revolving credit facility (the “Revolving Credit Facility”), which terminates in August 2018, was reduced to $475.0 million. In addition, the commitments under our Revolving Credit Facility will be further reduced to

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$450.0 million on December 31, 2016. The Amended Credit Agreement also adds an anti-hoarding provision under our Revolving Credit Facility which prohibits new borrowings if the aggregate amount of our unrestricted cash and cash equivalents (taking into account certain pending applications of cash) exceeds $35.0 million both before and after giving effect to such borrowings when taking into account the intended use of such loan proceeds for bona fide purposes within 60 days. Mandatory term loan prepayments are required to be made based on an excess cash flow calculation, as defined by the Amended Credit Agreement, for the second half of fiscal year 2016 and full fiscal year 2017, sales of assets, certain proceeds from insurance recoveries and condemnation awards and certain incurrence of indebtedness, subject, in each case, to customary exceptions and thresholds. As of September 30, 2016, we had $352.5 million in borrowings outstanding under the Revolving Credit Facility and $6.5 million in letters of credit.

Under the Amended Credit Agreement, borrowings under our Revolving Credit Facility bear interest at a rate equal to, at our option: (i) LIBOR (subject to a LIBOR floor of 0%) plus an applicable margin ranging from 3.50% to 4.50%; or (ii) a base rate plus an applicable margin ranging from 2.50% to 3.50%; in each case, determined in accordance with our consolidated net leverage ratio. Our Term Loans bear interest of a rate equal to, at our option: (i) LIBOR (subject to a LIBOR floor of 1.00%) plus 5.50%; or (ii) a base rate plus 4.50%. We are also required to pay a commitment fee of 0.50% to the lenders under the Revolving Credit Facility in respect of unutilized commitments thereunder and pay a fronting fee equal to 0.125% per annum of the amount available to be drawn under letters of credit. As of September 30, 2016, the weighted-average interest rate on Revolving Credit Facility and term loan borrowings was 5.0% and 6.5%, respectively.

The obligations under the Senior Secured Credit Facilities are unconditionally guaranteed on a senior unsecured basis by FELP and on a senior secured basis by our direct and indirect domestic subsidiaries and are or will be secured by first-priority perfected liens on substantially all of our and the subsidiary guarantors’ existing and future assets, subject to certain exceptions.

The Senior Secured Credit Facilities require that we comply on a quarterly basis with certain financial covenants, including a minimum consolidated interest coverage ratio of 2.00:1.00 and a maximum senior secured net leverage ratio ranging from 3.50:1.00 for the fiscal quarter ending September 30, 2016 to 2.75:1.00 for the fiscal quarter ending March 31, 2021 and thereafter. Our Senior Secured Credit Facilities prohibit certain restricted payments, including discretionary dividends, until the later to occur of: (i) June 30, 2018 and (ii) the date on which our obligations under our revolving credit facility have been paid in full, after which restricted payments can be made of up to $25.0 million per year, subject to certain adjustments and exceptions.

Amendments and Waivers Relating to Equipment Financing Arrangements

On the Closing Date, we entered into an amendment to the 5.78% longwall financing credit agreement under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last three semi-annual amortization payments. The new maturity date of the 5.78% longwall financing arrangement is June 2019.  In addition, the senior secured leverage ratio financial maintenance covenant was amended to be consistent with the Amended Credit Agreement.

On the Closing Date, we entered into an amendment to the 5.555% longwall financing credit agreement  under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last four semi-annual amortization payments. The new maturity date of the 5.555% longwall financing arrangement is September 2019.  In addition, the senior secured leverage ratio financial maintenance covenant was amended to be consistent with the Amended Credit Agreement.

In connection with the restructuring, we also executed waivers to cure outstanding defaults under the master lease agreements to our capital lease obligations. These waivers, among other things, ratified the existing terms of each applicable equipment financing agreement, provided the lessor with a waiver fee equal to one hundred basis points of the outstanding amount due under the agreement, increased the interest rate by one percent per annum, and, with respect to certain arrangements, released the lessor from any claims that such parties may have against the lessor with respect to the lease. The modification to the capital leases resulted in a $0.7 million increase to our capital lease obligations and the corresponding right-to-use assets.

A/R Securitization Agreement

 

In August 2016, we entered into an amended and restated receivables financing agreement pursuant to which commitments under the facility were reduced to $50.0 million. We recorded a loss on extinguishment of debt charge of $0.1 million during the first quarter of 2016 to write-off a portion of the deferred debt issue costs for the reduction in commitments as part of the forbearance agreement.

 

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Maturity Table

 

The following table summarizes the contractual principal maturities of long-term debt (excluding unamortized debt discounts and debt issuance costs) and capital lease obligations as of September 30, 2016 (in one-year increments from September 30, 2016):

 

 

11. Sale-Leaseback Financing Arrangements – Affiliate

In 2009, Macoupin sold certain of its coal reserves and rail facilities to WPP, LLC (“WPP”), a subsidiary of Natural Resource Partners, LP (“NRP”), and leased them back. The gross proceeds from this transaction were $143.5 million. In 2012, Sugar Camp sold certain rail facilities to HOD, LLC (“HOD”), a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million. NRP is an affiliated entity to the Partnership (see Note 13). In both transactions, because we had continuing involvement in the assets sold, the transactions were treated as sale-leaseback financing arrangements. Macoupin is currently in dispute with WPP in regards to the application of the recoupment provision of its lease (see Note 18).

As of September 30, 2016, the outstanding principal balance on the Macoupin and Sugar Camp sale-leaseback financing arrangements were $143.3 million and $50.0 million, respectively.

The implied effective interest rate as of September 30, 2016 on the Macoupin sale-leaseback financing arrangement and the Sugar Camp sale-leaseback financing arrangement was 13.9% and 13.1%, respectively. If there is a material change to the mine plans, the impact of a change in the effective interest rate to the condensed consolidated statement of operations could be significant. Interest expense recorded on the Macoupin sale-leaseback was $4.4 million and $5.9 million for the three months ended September 30, 2016 and 2015, respectively, and $13.9 million and $15.9 million for the nine months ended September 30, 2016 and 2015, respectively. Interest expense recorded on the Sugar Camp sale-leaseback was $1.7 million and $0.9 million for the three months ended September 30, 2016 and 2015, respectively, and $4.6 million and $3.9 million for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016 and December 31, 2015, interest totaling $1.3 million and $2.1 million, respectively, was accrued in the condensed consolidated balance sheets for the Macoupin and Sugar Camp sale-leaseback financing arrangements.

 

12. Asset Retirement Obligations

The change in the carrying amount of our asset retirement obligations was as follows for the nine months ended September 30, 2016:

 

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13. Related-Party Transactions

 

The chairman of our general partner’s board of directors and the controlling member of Foresight Reserves, Christopher Cline, directly and indirectly beneficially owns a 31% and 4% interest in the general and limited partner interests of NRP, respectively. We routinely engage in transactions in the normal course of business with NRP and its subsidiaries and Foresight Reserves and its affiliates. These transactions include production royalties, transportation services, administrative arrangements, supply agreements, service agreements, land leases and sale-leaseback financing arrangements (see Note 11, sale-leaseback financing arrangements are excluded from the discussion and tables below). Also, in connection with the reorganization of the Partnership pursuant to the execution of the MSA, Foresight Reserves paid retention bonuses to certain Partnership employees which were recorded as capital contributions during the period of payment (see Note 4).

 

On April 16, 2015, Foresight Reserves and Murray Energy executed a purchase and sale agreement whereby Murray Energy paid Foresight Reserves $1.37 billion to acquire a 34% voting interest in FEGP, 77.5% of FELP’s incentive distribution rights (“IDR”) and 100% of the outstanding subordinated units in FELP. FEGP has continued to govern the Partnership subsequent to this transaction. Murray Energy has an option (the “GP Option”), as amended as part of the Restructuring Transactions, to purchase an additional 46% of the voting interests in FEGP for $15 million and is also conditioned upon a Note Redemption prior to the Exchangeable PIK Note Maturity Date (see Note 10).      

 

Reserves Investor Group Tender Offer and Exchange

 

In connection with the Restructuring Transactions, on the Closing Date, the Reserves Investor Group (as defined below) acquired, with cash, $105.4 million of the outstanding 2021 Senior Notes (the “Tender Offer”). The Reserves Investor Group includes Christopher Cline, the four trusts established for the benefit of Mr. Cline’s children, Michael J. Beyer, the former Chief Executive Officer of FEGP and owner of 0.66% of the voting and 0.225% of the economic interests of FEGP and certain other limited liability companies owned or controlled by individuals with limited partner interests in Foresight Reserves through indirect ownership. Prior to the commencement of the Tender Offer, the Reserves Investor Group owned $83.0 million of the 2021 Senior Notes. The Reserves Investor Group then exchanged their aggregate $188.4 million of 2021 Senior Notes, plus $6.8 million of accrued and unpaid interest, for $179.9 million of Exchangeable PIK Notes and $15.2 million of Second Lien Notes (see Note 10 for additional discussion on the terms of the Exchangeable PIK Notes and Second Lien Notes).

 

Murray Purchase Right

 

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

 

Murray Energy Management Services Agreement

 

On April 16, 2015, the MSA was entered into pursuant to which the Manager will provide certain management and administration services to FELP for a quarterly fee of $3.5 million ($14.0 million on an annual basis), subject to contractual increases and other adjustments. To the extent FELP or FEGP directly incurs costs for certain services covered under the MSA, then the Manager’s quarterly fee is reduced accordingly. Also, to the extent the Manager utilizes outside service providers to perform any of the services under the MSA, then the Manager is responsible for those outside service provider costs. The initial term of the MSA extends through December 31, 2022 and is subject to termination provisions, including termination if the Note Redemption does not occur prior to the Exchangeable PIK Note Maturity Date and Murray Energy does not execute its GP Option.  If Murray executes its GP Option, it has the right to increase the annual MSA fee to $20.0 million per year.

 

After taking into account the contractual adjustments for direct costs incurred by FELP, the amount of net expense due to the Manager for the three months ended September 30, 2016 and 2015 was $2.6 million and $1.9 million, respectively, and for the nine months ended September 30, 2016 and 2015 was $7.1 million and $3.4 million, respectively.

 

Murray Energy Transport Lease and Overriding Royalty Agreements

 

On April 16, 2015, American Century Transport LLC (“American Transport”), a newly created 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

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to which (i) American Transport will lease to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at the Transport Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport will receive from American Energy a fee ranging from $1.15 to $1.75 for every ton of coal mined, processed and/or transported using such assets, subject to a quarterly recoupable minimum fee of $1.7 million. The Transport Lease is being accounted for as a direct financing lease. The total remaining minimum payments under the Transport Lease was $93.5 million at September 30, 2016, with unearned income equal to $34.4 million. The unearned income will be reflected as other revenue over the term of the lease using the effective interest method. Any amounts in excess of the contractual minimums will be recorded as other revenue when earned. As of September 30, 2016, the outstanding Transport Lease financing receivable was $59.1 million, of which $2.7 million was classified as current in the condensed consolidated balance sheet.

 

Also, on April 16, 2015, American Century Minerals LLC (“Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement (“ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company (collectively, “AEC”), pursuant to which AEC granted to Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The ORRA is subject to a minimum recoupable quarterly fee of $0.5 million. This overriding royalty was accounted for as a financing arrangement. The payments the Partnership receives with respect to the ORRA will be 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 will be recorded as other revenue when earned. The total remaining minimum payments under the ORRA was $32.6 million at September 30, 2016, with unearned income equal to $20.9 million. As of September 30, 2016, the outstanding ORRA financing receivable was $11.7 million, of which $0.2 million was classified as current in the condensed consolidated balance sheet.

 

Other Murray Transactions

 

During the three and nine months ended September 30, 2016, we purchased $0.6 million and $2.3 million, respectively, in equipment, supplies and rebuild services from affiliates of Murray Energy. During the three and nine months ended September 30, 2015, we purchased $1.2 million and $1.6 million, respectively, in equipment, supplies and rebuild services from affiliates of Murray Energy. During the three and nine months ended September 30, 2016, our affiliate, Coalfield Construction, provided $0.2 million and $0.7 million, respectively, in equipment, supplies and rebuild services to affiliates of Murray Energy.

 

During the three and nine months ended September 30, 2016, we purchased $0.2 and $0.7 million, respectively, in coal from Murray Energy and its affiliates to meet quality specifications under certain customer contracts.

 

During the three and nine months ended September 30, 2016, Murray Energy transported coal under our transportation agreement with a third-party rail company resulting in usage fees owed to the third-party rail company of $0.2 million and $4.0 million, respectively. These usage fees were billed to Murray Energy, resulting in no impact to our condensed consolidated statement of operations. The usage of the railway by Murray Energy counts toward the minimum annual throughput volume requirement with the third-party rail company, thereby reducing the Partnership’s exposure to contractual liquidated damage charges.

 

During the three and nine months ended September 30, 2016, we earned $0.3 million and $1.1 million, respectively, in other revenues for Murray Energy’s usage of our Sitran terminal.

 

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

 

Mineral Reserve Leases

 

Our mines have a series of mineral reserve leases with Colt, LLC (“Colt”) and Ruger, LLC (“Ruger”), subsidiaries of Foresight Reserves. Each of these leases have initial terms of 10 years with six renewal periods of five years each, at the election of the lessees, and generally require the lessees to pay the greater of $3.40 per ton or 8.0% of the gross sales price, as defined in the respective agreements, of such coal. We also have overriding royalty agreements with Ruger pursuant to which we pay royalties equal to 8.0% of the gross selling price, as defined in the agreements. Each of these mineral reserve leases generally requires a minimum annual royalty payment, which is recoupable only against actual production royalties from future tons mined during the period of 10 years following the date on which any such royalty is paid.

On the Closing Date, Colt entered into the Indefeasible Assignment of Minimum Royalties Agreement under Coal Leases (“Colt Assignment”) with a subsidiary of Murray Energy pursuant to which Colt assigned to Murray Energy all of Colt’s right to be paid certain annual minimum royalties that are payable under six coal mine leases (the “Colt Leases”) between Colt and FELP subsidiaries. The term of the Colt Assignment expires for each Colt Lease upon the expiration of the primary term under such lease. The last such primary term expires on May 31, 2022, after which Murray Energy shall no longer be entitled to be paid any annual minimum royalty under the Colt Leases.

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We also lease mineral reserves under lease agreements with subsidiaries of NRP, including WPP, HOD, and Independence Energy, LLC (“Independence”). The initial terms of these agreements vary, however, each carries an option by the lessee to extend the leases until all merchantable and mineable coal has been mined and removed. Royalty payments under these arrangements are generally determined based on the greater of a minimum per ton amount (ranging from $2.50 per ton to $5.40 per ton) or a percentage of the gross sales price (generally 8.0% - 9.0%), as defined in the respective agreements. We are also subject under certain of these mineral reserve agreements to overriding royalties and/or wheelage fees. Our mineral reserve leases with NRP subsidiaries generally also require minimum quarterly or annual royalties which are generally recoupable on future tons mined and sold during the preceding five-year period from the excess tonnage royalty payments on a first paid, first recouped basis.

 

In July 2015, we provided notice to WPP declaring a force majeure event at our Hillsboro mine due to elevated carbon monoxide levels as a result of a mine fire, which has required the stoppage of mining operations since March 2015. As a result of the force majeure event, we have not made $38.5 million in minimum deficiency payments to WPP in accordance with the force majeure provisions of the royalty agreement. WPP is asserting that the stoppage of mining operations as a result of the mine fire does not constitute an event of force majeure under the royalty agreement (see Note 18).

 

As of September 30, 2016 and December 31, 2015, we have established a $37.0 million and $46.3 million reserve, respectively, against contractual prepaid royalties between Hillsboro and WPP given that the recoupment of certain prior minimum royalty payments was improbable given the remaining recoupment period available and the current Hillsboro combustion event which has halted production. During the three and nine months ended September 30, 2016, the recoupment period of $3.1 million and $9.3 million, respectively, in prepaid royalties between Hillsboro and WPP expired, resulting in the write-off of the prepaid royalty and the corresponding reserve. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, the status of the Hillsboro combustion event, assessing mine production plans, sales commitments, current and forecasted future coal market conditions, and remaining years available for recoupment.

Limited Partnership Agreement

The Partnership’s general partner manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. Foresight Reserves and Murray Energy have the right to select the directors of the general partner. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to reelection by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership’s business. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses incurred or payments made by the general partner on behalf of the Partnership.

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

 

 

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A summary of certain expenses (income) incurred with affiliated entities is as follows for the three and nine months ended September 30, 2016 and 2015:

 

Principal location in the condensed consolidated financial statements:

(1) – Coal sales

(2) – Other revenues

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

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

(5) – Cost of coal purchased

(6) – Transportation

(7) – Selling, general and administrative  

 

We also purchased $1.7 million and $4.4 million in mining supplies from an affiliated joint venture under a supply agreement during the three months ended September 30, 2016 and 2015, respectively, and $4.9 million and $11.8 million for the nine months ended September 30, 2016 and 2015, respectively (see Note 14).

 

14. Variable Interest Entities (VIEs)

 

Our financial statements have historically included VIEs for which the Partnership or one of its subsidiaries were the primary beneficiary. Among those VIEs consolidated by the Partnership and its subsidiaries were Mach Mining, LLC; M-Class Mining, LLC; MaRyan Mining LLC; Patton Mining LLC; Viking Mining LLC; Coal Field Construction Company LLC; Coal Field Repair Services LLC; Logan Mining LLC; and LD Labor Company LLC (collectively, the “Contractor VIEs”). Each of the Contractor VIEs held a contract to provide one or more of the following services to a Partnership subsidiary: contract mining, processing and loading services, or construction and maintenance services. Each of the Contractor VIEs generally received a nominal per ton fee ($0.01 to $0.02 per ton) above its cost of operations as compensation for services performed. All of these entities were determined not to have sufficient equity at risk and were therefore VIEs. The Partnership was determined to be the primary beneficiary of each of these entities given it controlled these entities under a contractual cost-plus arrangement. During each of the three months ended September 30, 2016 and 2015, in aggregate, the Contractor VIEs earned income of $0 and $0.1 million, respectively, under the contractual arrangements with the Partnership and during each of the nine months ended September 30, 2016 and 2015, in aggregate, the Contractor VIEs earned income of $0.2 million and  $0.4 million, respectively. The Contractor VIE net income was recorded within net income attributable to noncontrolling interests in the condensed consolidated statements of operations.

 

On August 1, 2016, we acquired 100% of the outstanding equity units in each of the Contractor VIEs for aggregate cash consideration of $0.1 million. Because the Contractor VIEs have historically been consolidated as VIEs, and therefore represented entities under common control, the cash proceeds paid in excess of the net book values of the Contractor VIEs on the acquisition date was recorded as a deemed distribution in the statement of partners’ (deficit) capital. We do not expect any material changes to our operations from the acquisitions of the Contractor VIEs.

 

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In January 2016, we contributed $2.5 million to a new entity, Foresight Surety LLC (“Foresight Surety”), whose purpose was to obtain and maintain a letter of credit for the benefit of one of our surety bond providers. We hold all of the economic units of Foresight Surety and a professional service provider with which we have had a long-standing relationship holds all of its voting rights. Foresight Surety is a VIE given that the holder of all of the economic rights has no ability to exercise power over it. We were determined to be the primary beneficiary of Foresight Surety, and therefore consolidate Foresight Surety, as the professional service provider with all of the voting rights was determined to be acting as our de facto agent and therefore we would aggregate voting power. In February 2016, Foresight Surety obtained a $2.5 million letter of credit with a lender for the benefit of one of our surety bond providers. The letter of credit is secured by the $2.5 million of cash we contributed to Foresight Surety.

The liabilities recognized as a result of consolidating the VIEs do not necessarily represent additional claims on the general assets of the Partnership outside of the VIEs; rather, they represent claims against the specific assets of the consolidated VIEs. Conversely, assets recognized as a result of consolidating these VIEs do not necessarily represent additional assets that could be used to satisfy claims against the Partnership’s general assets. There are no restrictions on the VIE assets that are reported in the Partnership’s general assets. The total consolidated VIE assets and liabilities reflected in the Partnership’s condensed consolidated balance sheets are as follows:

 

 

 

(1)– Includes cash and cash equivalents of $4,332 as of December 31, 2015.

 

In May 2013, an affiliate owned by The Cline Group and a third-party supplier of mining supplies formed a joint venture whose purpose is the manufacture and sale of supplies primarily for use by the Partnership in the conduct of its mining operations. The agreement obligates the Partnership’s coal mines to purchase at least 90% of their aggregate annual requirements for certain mining supplies from the supplier parties, subject to exceptions as set forth in the agreement. The initial term of the amended agreement is five years and expires in April 2018. The supplies sold under this arrangement result in an agreed-upon, fixed-profit percentage for the joint venture. This joint venture was determined to be a VIE given that the equityholders do not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the joint venture as a result of the Partnership effectively guaranteeing a fixed-profit percentage on the supplies it purchases from the joint venture. We are not the primary beneficiary of this joint venture and, therefore, do not consolidate the joint venture, given that the power over the joint venture is conveyed through the board of directors of the joint venture and no party controls the board of directors.

 

15. Equity-Based Compensation

 

Long-Term Incentive Plan

 

The Partnership has a Long-Term Incentive Plan ("LTIP") for employees, directors, officers and certain key third-parties (collectively, the "Participants") which allows for the issuance of equity-based compensation. The LTIP awards granted thus far are phantom units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive FELP units. The board of directors of FEGP authorized 7.0 million common units to be granted under the LTIP, with 4.8 million remaining units available for issuance as of September 30, 2016.

 

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Our equity-based compensation expense, net of forfeitures, was $0.3 million and $1.3 million during the three months ended September 30, 2016 and 2015, respectively, and was $4.7 million and $12.9 million during the nine months ended September 30, 2016 and 2015, respectively. Included in selling, general and administrative expense for the nine months ended September 30, 2015 was $7.1 million of equity-based compensation expense for 215,954 common units and 215,796 subordinated units issued to the former chief executive officer of FEGP which were fully-vested on the date of grant. Approximately 91.6% of the Partnership's equity-based compensation during the nine months ended September 30, 2016 was reported in the condensed consolidated statement of operations as transition and reorganization costs, 1.0% as selling, general and administrative expenses and the remaining 7.4% recorded as cost of coal produced. All non-vested phantom awards include tandem distribution equivalent rights, which provide for the right to accrue quarterly cash distributions in an amount equal to the cash distributions the Partnership makes to unitholders during the vesting period and will be settled in cash upon vesting. The Partnership has $0.4 million accrued for this liability as of September 30, 2016. Any distributions accrued to a participant’s account will be forfeited if the related phantom award fails to vest according to the relevant vesting conditions.

 

A summary of LTIP award activity for the nine months ended September 30, 2016 is as follows:

 

 

16. Earnings per Limited Partner Unit

 

Limited partners’ interest in net (loss) income attributable to the Partnership and basic and diluted earnings per unit reflect net income attributable to the Partnership. We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in ASC 260, Earnings Per Share. The 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 IDRs 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 income (loss) is allocated to the limited partners, including the holder of the subordinated units, in accordance with their respective ownership percentages, after giving effect to any special income or expense allocations and incentive distributions paid to the general partner, if any. The IDR holders have the right to receive increasing percentages of quarterly distributions from operating surplus after certain distribution levels defined in the partnership agreement have been achieved. The general partner has no obligation to make distributions; therefore, undistributed earnings of the Partnership are not allocated to the IDR holder. Basic EPU is computed by dividing net earnings attributable to unitholders by the weighted-average number of units outstanding during each period. Diluted EPU reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.

 

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

 

 

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

 

 

 

 

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17. Fair Value of Financial Instruments

The table below sets forth, by level, the Partnership’s net financial assets and liabilities for which fair value is measured on a recurring basis:

 

 

 

The Partnership’s commodity derivative contracts are valued based on direct broker quotes and corroborated with market pricing data. See discussion below on the valuation of the Warrant liability.

The classification and amount of the Partnership’s financial instruments measured at fair value on a recurring basis, which are presented on a gross basis in the condensed consolidated balance sheets as of September 30, 2016 and December 31, 2015, are as follows:

 

 

 

During the three and nine months ended September 30, 2016 and 2015, there were no assets or liabilities that were transferred between Level 1 and Level 2.

 

 

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The following is a reconciliation of the beginning and ending balances measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the nine months ended September 30, 2016:

 

 

On the Closing Date, FELP issued Warrants to the unaffiliated owners of the Second Lien Notes to purchase an amount of common units equal to an aggregate of 4.5% of the total limited partner units of FELP outstanding on the date of a Note Redemption (after giving effect to the full exercise of the Warrants and the Note Redemption, subject to certain anti-dilution protections), exercisable upon a Note Redemption and until the tenth anniversary of the Note Redemption. The exercise price of the Warrants is $0.8928 per Common Unit, subject to certain adjustments. The number of common units issuable upon the conversion of the Warrants will be determinable as of the date of a Note Redemption. If a Note Redemption does not occur on or prior to the Exchangeable PIK Maturity Date, the Warrants will not become exercisable. The Warrants are required to be accounted for as a liability at fair value and the fair value must be revalued at each balance sheet date until the earlier of the exercise of the Warrants, their expiration, or until any of the features requiring liability treatment expires or is modified. The resulting non-cash gain or loss on the fair value revaluation at each balance sheet date is recorded as non-operating income in our condensed consolidated statement of operations

 

The fair value of the Warrants was calculated using the Black-Scholes pricing model (including the use of a binomial lattice to model the conversion and redemption scenarios for the Exchangeable PIK Notes) which is based, in part, upon unobservable inputs for which there is little or no market data (Level 3), requiring the Partnership to develop its own assumptions. A stock price volatility of 70%, a dividend yield of 0% and a risk-free forward rate of 1.74% was used in the Black-Scholes pricing model.

 

If factors change and different assumptions are used, the warrant liability and the change in estimated fair value could be materially different. Generally, as the market price of our common unit increases, the fair value of the Warrants increases, and conversely, as the market price of our common unit decreases, the fair value of the Warrants decreases. Also, a significant increase in the volatility of the market price of the Partnership's common unit, in isolation, would result in a higher fair value measurement; and a significant decrease in volatility would result in a lower fair value measurement.

Long-Term Debt

The fair value of long-term debt as of September 30, 2016 and December 31, 2015 was $1,349.6 million and $1,244.3 million, respectively. The fair value of long-term debt was calculated based on the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms. This is considered a Level 3 fair value measurement.

 

18. Contingencies

 

On August 30, 2016, FELP completed its global restructuring. The restructuring transactions alleviated existing defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Court of Chancery Court change-of-control litigation related to the purchase and sale agreement between the significant equity holders in the Partnership’s general partner, Foresight Reserves and Murray Energy.  In conjunction with the completion of the global restructuring, the litigation has been dismissed with prejudice. See Note 3 for additional discussion.

 

In January 2016, certain plaintiffs filed suit against us in the United States District Court for the Central District of Illinois Springfield Division under the Worker Adjustment and Retraining Notification Act (the “WARN Act”) claiming that they were terminated without cause on or about January 2016. While we believe that the terminations were properly conducted under the WARN Act, the parties resolved the case at mediation for $0.6 million and are currently seeking approval of the settlement from the United States District Court for the Central District of Illinois Springfield Division.

 

In January 2016, WPP sent a demand letter to Macoupin claiming it had misapplied the royalty recoupment provision involving a coal mining lease and a rail infrastructure lease resulting in underpayments of $3.3 million. In April 2016, WPP and HOD filed a complaint in the Circuit Court of Macoupin County, Illinois. We do not believe that the royalty recoupment provision was misapplied and have continued to apply the recoupment provision consistently with prior periods. While we believe that the language of the agreements and

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the parties’ course of performance thereunder support Macoupin’s position, should we not prevail, we would be responsible for paying WPP for any recoupment taken that is found to contravene the contractual language.

 

In July 2015, we provided notice to WPP, a subsidiary of NRP, declaring a force majeure event at our Hillsboro mine due to a combustion event. As a result of the force majeure event, as of September 30, 2016, we have not made $38.5 million in minimum deficiency payments to WPP in accordance with the force majeure provisions of the royalty agreement. On November 24, 2015, WPP filed a Complaint in the Circuit Court of Montgomery County, Illinois, alleging that (i) the stoppage of mining operations as a result of the mine fire does not constitute an event of force majeure under the royalty agreement, (ii) Hillsboro’s reliance on the force majeure language was a breach of the royalty agreement and (iii) WPP was fraudulently induced by Hillsboro to enter into the royalty agreement in the first instance. WPP seeks an award of punitive damages and attorneys’ fees under its fraud claim. WPP filed an Amended Complaint, repeating the same allegations against Hillsboro and adding FELP as a party-defendant.  FELP has filed a motion to dismiss and Plaintiff has filed a motion for Partial Summary Judgment.  An argument on certain issues will be held on November 14, 2016.  While we believe this is a force majeure event, as contemplated by the royalty agreement, and that the alleged claims are  without merit, should we not prevail, we would be responsible for funding any minimum deficiency payment amounts during the shutdown period to WPP and potentially additional fees.

 

In November 2012, six citizens filed requests for administrative review of Revision No. 1 to Permit No. 399 for the Hillsboro mine. Revision No. 1 allowed for conversion of the currently permitted coal refuse disposal facility from a non-impounding to an impounding structure. Shortly after the filing of Revision No. 1, one citizen withdrew his request. Following a hearing on both the Illinois Department of Natural Resources’ (“IDNR”) and Hillsboro’s motion to dismiss, the hearing officer dismissed the claims of two of the remaining five petitioners and also limited some of the issues remaining for administrative review. In June 2014, two of the remaining three petitioners dismissed their requests. A final hearing on the merits began in June 2015. The hearing officer granted Hillsboro’s motion for reconsideration of his decision denying its motion for summary decision on two grounds. The hearing officer’s decision on reconsideration disposed of the entire administrative proceeding in Hillsboro’s favor. On October 5, 2015, the petitioner filed an appeal of the hearing officer’s decision in the Circuit Court of Montgomery County, Illinois. Oral arguments on this appeal were continued by the Court and will now occur in December 2016 and Hillsboro intends to continue its defense of the issuance of the permit.  

 

Certain railcar lessors have asserted claims under their railcar leases with us for damage to railcars allegedly caused by our use of the railcars during the lease terms. We are currently investigating these claims and intend to defend these matters vigorously.

 

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

We cannot reasonably estimate the ultimate legal and financial liability with respect to all pending litigation matters. However, we believe, based on our examination of such matters, that the ultimate liability will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. As of September 30, 2016, we have $4.9 million accrued, in aggregate, for various litigation matters.

 

We are currently in discussions with our insurance provider in regards to potential recoveries under our policy related to the combustion event at our Hillsboro operation. During the three months ended September 30, 2016, we recorded $10.5 million to cost of coal produced (excluding depreciation, depletion and amortization) in our condensed consolidated statement of operations for the recovery of mitigation costs (net of our policy deductible) related to the Hillsboro combustion event. However, there can be no assurances that we will receive any further insurance recoveries related to this incident.

 

Performance Bonds

 

We had outstanding surety bonds with third parties of $82.4 million as of September 30, 2016 to secure reclamation and other performance commitments. In February 2016, we were required to post cash collateral of $2.5 million to our surety bond provider.

 

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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 above factors should be read in conjunction with the risk factors included in our Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) on March 15, 2016.

 

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”), Foresight Reserves and a member of FELLC’s management contributed their ownership interests in FELLC to FELP in exchange for which they were issued common and subordinated units in FELP. FELP has been managed by Foresight Energy GP LLC (“FEGP”) since the IPO.

On April 16, 2015, Murray Energy Corporation (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% noncontrolling economic interest in FEGP and all of the outstanding subordinated units of FELP, representing a 50% ownership percentage of the Partnership’s limited partner units.

 

The financial results include the combined financial position, results of operations and cash flows of FELP and FELLC and its subsidiaries for all periods presented. In this Item 2, all references to “FELP,” the “Partnership,” “we,” “us,” and “our” refer to the combined results of FELP and FELLC and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

We control over 3 billion tons of coal reserves, almost all of which exist in three large, contiguous blocks of coal: two in central Illinois and one in southern Illinois. Since our inception, we have invested significantly in capital expenditures to develop what we believe are industry-leading, geologically similar, low-cost and highly productive mines and related infrastructure. We currently operate under one reportable segment with four underground mining complexes in the Illinois Basin: Williamson, Sugar Camp and Hillsboro, all three of which are longwall operations, and Macoupin, which is a continuous miner operation. The Williamson and

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Hillsboro complexes each have one longwall system and Sugar Camp is operating with two longwall mining systems. Mining operations at our Hillsboro complex have been idle since March 2015 due to a combustion event. In April 2016, we temporarily sealed the entire mine to reduce the oxygen flow paths into the mine. We are uncertain as to when production will resume at this operation.

Our coal is sold to a diverse customer base, including electric utility and industrial companies in the eastern United States and internationally (primarily in Europe). We sell our coal to customers at delivery points other than just our mines, including, but not limited to, river terminals on the Ohio and Mississippi Rivers and at a port near New Orleans.

Restructuring Transactions

 

On December 4, 2015, the Delaware Court of Chancery issued a memorandum opinion concluding, among other things, that the purchase and sale agreement between Foresight Reserves and Murray Energy (see Note 13) constituted a “change of control” under the indenture (the “Indenture”) governing our 7.875% Senior Notes due 2021 (the “2021 Senior Notes”) and that an event of default occurred under the Indenture when we failed to offer to purchase the 2021 Senior Notes on or about May 18, 2015 (the “2015 Delaware Court of Chancery change-of-control litigation”). Because of the existence of “change of control” provisions and cross-default or cross-event of default provisions in our debt agreements, the purchase and sale agreement between Foresight Reserves and Murray Energy also resulted, directly or indirectly, in events of default under FELLC’s credit agreement governing its senior secured credit facilities (the “Credit Agreement”), Foresight Receivables LLC’s securitization program and certain other financing arrangements, including our longwall financing arrangements. The existence of an event of default prohibited us access to borrowings or other extensions of credit under our revolving credit facility and our failure to pay the semi-annual interest payments of $23.6 million due on February 15, 2016 and August 15, 2016 resulted in additional events of default. The conditions and circumstances above raised prior substantial doubt about the Partnership’s ability to continue as a going concern and therefore our auditor’s issued an audit opinion in connection with our 2015 consolidated financial statements with a “going concern” uncertainty explanatory paragraph.

 

On July 22, 2016, we entered into Amended and Restated Transaction Support Agreements (the “A&R Notes Transaction Support Agreements”) with certain consenting noteholders of the 2021 Senior Notes and certain equityholders of the Partnership, including Christopher Cline, Foresight Reserves LP and certain of its related parties and affiliates ( the “Reserves Group”) and Murray Energy, pursuant to which the parties agreed to modified terms of the restructuring of the Partnership’s indebtedness and certain governance and equity matters relating to the Partnership.

 

On August 30, 2016 (the “Closing Date”), we completed a global restructuring of our indebtedness. The restructuring transactions described below (the “Restructuring Transactions”) alleviated existing defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Chancery Court change-of-control litigation related to the purchase and sale agreement between Foresight Reserves and Murray Energy.  See “Item 1. Financial Statements – Note 10. Long-Term Debt and Capital Lease Obligations” and “Item 1. Financial Statements – Note 13. Related-Party Transactions” for additional discussion of the Restructuring Transactions.

 

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.

 

We define Adjusted EBITDA as net income (loss) attributable to controlling interests before interest, income taxes, depreciation, depletion, amortization and accretion. Adjusted EBITDA is also adjusted for equity-based compensation, losses/gains on commodity derivative contracts, settlements of derivative contracts, changes in the fair value of the warrants and material nonrecurring or other items which may not reflect the trend of future results. As it relates to derivatives, the Adjusted EBITDA calculation removes the total impact of derivative gains/losses on net income (loss) during the period and then adds/deducts to Adjusted EBITDA the aggregate settlements during the period.

 

Adjusted EBITDA is not a measure of performance defined in accordance with U.S. GAAP. However, management believes that Adjusted EBITDA is useful to investors in evaluating our performance because it is a commonly used financial analysis tool for measuring and comparing companies in our industry in areas of operating performance. Management believes that the disclosure of Adjusted EBITDA offers an additional view of our operations that, when coupled with our U.S. GAAP results and the reconciliation to U.S. GAAP results, provides a more complete understanding of our results of operations and the factors and trends affecting our business. Adjusted EBITDA should not be considered as an alternative to net income. 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

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companies in our industry, and (ii) it excludes financial information that some consider important in evaluating our performance. We compensate for these limitations by providing a reconciliation of Adjusted EBITDA to U.S. GAAP results to enable users to perform their own analysis of our operating results.

 

Results of Operations

 

Comparison of Three Months Ended September 30, 2016 to Three Months Ended September 30, 2015

 

Coal Sales. The following table summarizes coal sales information during the three months ended September 30, 2016 and 2015.

 

The decline in coal sales revenue from the prior year period was primarily due to a decline in coal sales volumes attributed to difficult coal market conditions driven by oversupply in the market, excess utility stockpiles and continued low natural gas prices.

 

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 September 30, 2016 and 2015.

 

 

The decrease in cost of coal produced (excluding depreciation, depletion and amortization) during the current quarter was primarily due to lower sales volumes and the recognition of $10.5 million of insurance recoveries related to the direct mitigation costs we incurred during 2015 and 2016 from the Hillsboro combustion event.

 

Transportation. Our cost of transportation for the three months ended September 30, 2016 decreased $1.1 million from the prior year period due to lower sales volumes and a lower percentage of our sales going to international markets during the current year period, partially offset by $2.6 million of higher charges for estimated shortfalls on minimum contractual throughput volume requirements.

 

Transition and Reorganization Costs. As part of the Murray Energy transaction, we entered into the MSA with Murray Energy with the intent of optimizing and reorganizing certain corporate administrative functions and generating synergies between the two companies through the elimination of headcount and duplicative selling, general and administrative costs. Transition and reorganization costs were $5.0 million for the three months ended September 30, 2015. The incurrence of these transition and reorganization costs concluded during the second quarter of 2016.

 

Selling, General and Administrative. The $2.6 million increase in selling, general and administrative expenses from the three months ended September 30, 2015 was primarily due to increased litigation accrual expense during the current year period related to various claims.

 

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Loss (Gain) on Commodity Derivative Contracts. We recorded a loss on our commodity derivative contracts of $6.0 million for the three months ended September 30, 2016, compared to a $17.5 million gain for the three months ended September 30, 2015. The loss during the current year period was due to a substantial increase in the API 2 forward price curve during the three months ended September 30, 2016, as opposed to a decline during the prior year period. For the three months ended September 30, 2016 and 2015, we realized net gains of $3.2 million and $10.9 million, respectively, on the settlement of commodity derivative contracts.

 

Interest Expense, Net. Interest expense, net for the three months ended September 30, 2016 increased $8.0 million from the prior year period due primarily to higher effective interest rates under the new and amended debt instruments as well as higher interest rates charged on the term loan, revolving credit facility and A/R securitization facility borrowings prior to the Closing Date of the Restructuring Transactions due to default interest rates being in effect.

 

Debt Restructuring Costs. The $6.1 million of debt restructuring costs incurred during the three months ended September 30, 2016 represents legal and other advisor fees incurred as a result of the unfavorable ruling under the 2015 Delaware Court of Chancery change-of-control litigation.

Change in fair value of warrants. The warrants issued as part of the Restructuring Transactions are required to be accounted for as a liability at fair value and the fair value must be revalued at each balance sheet date until the earlier of the exercise of the warrants, their expiration, or until any feature requiring liability treatments expires or is modified. The resulting non-cash gain or loss on the fair value revaluation at each balance sheet date is recorded as non-operating income in our condensed consolidated statement of operations. These warrants were revalued at fair value as of September 30, 2016 and the decrease in fair value from the Closing Date was recorded as a non-cash gain in our statement of operations.

Loss on extinguishment of debt. The $13.2 million loss on the early extinguishment of debt recognized during the three months ended September 30, 2016 was due to the write-off of $11.0 million of unamortized debt discount and debt issuance costs associated with the extinguishment of the 2021 Senior Notes and the reduction in borrowing capacity under our credit facility as well as the incurrence of $2.2 million in costs related to the modification of debt which were not deferred.

 

Adjusted EBITDA. Adjusted EBITDA declined $5.7 million from the prior year period due primarily to lower sales volumes and lower net back to mine realizations during the three months ended September 30, 2016, offset partially by the recognition of a $10.5 million insurance recovery related to direct mitigation costs incurred from the Hillsboro combustion event. The table below reconciles net (loss) income attributable to controlling interests to Adjusted EBITDA for the three months ended September 30, 2016 and 2015.

 

 

 

 

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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Comparison of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2015

 

Coal Sales. The following table summarizes coal sales information during the nine months ended September 30, 2016 and 2015.

 

 

The decline in coal sales revenue from the prior year period was due to a decline in coal sales volumes of 2.3 million tons and a decrease in coal sales realization of $1.32 per ton sold. The decline in coal sales volumes was attributed to a 2.2 million decline in production primarily as a result of the Hillsboro combustion event and difficult coal market conditions driven by oversupply in the market, excess utility stockpiles and continued low natural gas prices. Our coal sales realization per ton sold decreased from the prior year period due to a lower mix of international sales during the current year period and a small decline in both domestic and export realizations per ton. The decline in tons sold to the international market resulted in a corresponding decline in transportation expense during the current year period therefore the netback to mine realization per ton sold was more in-line with the prior year period.  

Other Revenues. Other revenues of $7.2 million and $3.3 million for the nine months ended September 30, 2016 and 2015, respectively, were primarily comprised of overriding royalty and lease revenues earned on the financing agreements entered into with affiliates of Murray Energy in April 2015. The increase over the prior year reflects these financing agreements being in place for the full nine month period in 2016.

 

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 nine months ended September 30, 2016 and 2015.

 

 

The decrease in cost of coal produced (excluding depreciation, depletion and amortization) was primarily due to lower sales volumes during the current year period. The cash cost per ton sold remained flat with the prior year period as the direct and indirect costs from the Hillsboro combustion event during the nine months ended September 30, 2015 were largely offset by a refund from one of our utility providers and the current year combustion event costs were offset by a $10.5 million insurance recovery related to the direct costs we incurred to mitigate the combustion event.

 

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Transportation. Our cost of transportation for the nine months ended September 30, 2016 decreased $31.1 million from the prior year period primarily due to lower sales volumes and a $0.91 per ton decrease in the average cost of transportation per ton sold. The decline in transportation cost per ton sold was due to a lower percentage of our sales going to international markets during the current year period, partially offset by $12.6 million of higher charges for estimated shortfalls on minimum contractual throughput volumes.

 

Selling, General and Administrative. The $6.6 million decline in selling, general and administrative expenses from the nine months ended September 30, 2015 was primarily due to a $7.1 million fully-vested equity award granted to the Partnership’s former chief executive officer during the first quarter of 2015.

 

Transition and Reorganization Costs. As part of the Murray Energy transaction, we entered into the MSA with Murray Energy with the intent of optimizing and reorganizing certain corporate administrative functions and generating synergies between the two companies through the elimination of headcount and duplicative selling, general and administrative costs. Transition and reorganization costs were $6.9 million for the nine months ended September 30, 2016, as compared to $17.3 million for the nine months ended September 30, 2015. The costs for the current year period were comprised of the remaining retention compensation to certain employees during the transition period. Included in transition and reorganization costs for the nine months ended September 30, 2016 were $2.3 million of costs paid by Foresight Reserves which were recorded as capital contributions, $4.3 million of equity-based compensation for the accelerated vesting of certain equity awards, and $0.2 million of other one-time charges related to the Murray Energy transaction.

 

Loss (Gain) on Commodity Derivative Contracts. We recorded a loss on our commodity derivative contracts of $17.3 million for the nine months ended September 30, 2016, compared to a $40.7 million gain for the nine months ended September 30, 2015. The loss during the current year period was due to a substantial increase in the API 2 forward price curve, whereas during the prior year period the API 2 forward price curve declined substantially. For the nine months ended September 30, 2016 and 2015, we had settlements of $13.1 million and $51.6 million, respectively, on commodity derivative contracts.

 

Other Operating Expense (Income), Net. Other operating expense (income), net decreased $11.7 million from the prior year period primarily due to a $13.5 million favorable legal settlement with Murray Energy during the nine months ended September 30, 2015.

 

Interest Expense, Net. Interest expense, net for the nine months ended September 30, 2016 increased $18.7 million from the prior year period due primarily to higher effective interest rates under the new and amended debt instruments as well as higher interest rates charged on the term loan, revolving credit facility and A/R securitization facility borrowings prior to the Closing Date of the debt restructuring due to default interest rates being in effect.

 

Debt Restructuring Costs. The $21.7 million of debt restructuring costs incurred during the nine months ended September 30, 2016 represents legal and other advisor fees incurred as a result of the unfavorable ruling under the 2015 Delaware Court of Chancery change-of-control litigation.

Change in fair value of warrants. The warrants issued as part of the Restructuring Transactions are required to be accounted for as a liability at fair value and the fair value must be revalued at each balance sheet date until the earlier of the exercise of the warrants, their expiration, or until any feature requiring liability treatments expires or is modified. The resulting non-cash gain or loss on the fair value revaluation at each balance sheet date is recorded as non-operating income in our condensed consolidated statement of operations. These warrants were revalued at fair value as of September 30, 2016 and the decrease in fair value from the Closing Date was recorded as a non-cash gain in our condensed consolidated statement of operations.

Loss on extinguishment of debt. The $13.3 million loss on the early extinguishment of debt recognized during the nine months ended September 30, 2016 was due to the write-off of $11.1 million of unamortized debt discount and debt issuance costs associated with the extinguishment of the 2021 Senior Notes and the reduction in borrowing capacity under our revolving facilities as well as the incurrence of $2.2 million in costs related to the modification of debt which were not deferred.

 

Adjusted EBITDA. Adjusted EBITDA declined $85.3 million from the prior year period due primarily to the settlements of $51.6 million in commodity derivative contracts during the nine months ended September 30, 2015, as compared to only $13.1 million during the nine months ended September 30, 2016 as well as lower sales volumes during the current year period. The table below reconciles net (loss) income attributable to controlling interests to Adjusted EBITDA for the nine months ended September 30, 2016 and 2015.

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

Liquidity and Capital Resources

 

Our primary cash requirements include, but are not limited to, working capital needs, capital expenditures, and debt service costs (interest and principal). The consummation of the Restructuring Transactions on August 30, 2016 alleviated certain defaults and events of default across the Partnership’s capital structure which restored our access to borrowings under our Revolving Credit Facility which had been restricted since December 2015. During this period, management was focused on the preservation and growth of our liquidity. As of September 30, 2016, we had $76.8 million of cash on hand. Our Revolving Credit Facility currently has a borrowing capacity of $475.0 million which declines to $450.0 million on December 31, 2016. As of September 30, 2016, we had borrowings of $352.5 million and letters of credit of $6.5 million outstanding under the Revolving Credit Facility. The August 30, 2016 amendment to the credit agreement put in place an anti-hoarding provision which prohibits new borrowings if the aggregate amount of our unrestricted cash and cash equivalents (taking into account certain pending applications of cash) exceeds $35.0 million both before and after giving effect to such borrowing when taking into account the intended use of such loan proceeds for bona fide purposes within 60 days.   

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 consist of maintenance and expansion capital expenditures. Maintenance capital expenditures are cash expenditures made to maintain our then-current operating capacity or net income as they exist at such time as the capital expenditures are made. Our maintenance capital expenditures can be irregular, causing the amount spent to differ materially from period to period.

 

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

 

Distributions

 

Our Senior Secured Credit Facilities, as amended on August 30, 2016, prohibit certain restricted payments, including discretionary dividends, until the later to occur of: (i) June 30, 2018 and (ii) the date on which our obligations under our revolving credit facility have been paid in full, after which restricted payments can be made of up to $25.0 million per year, subject to certain adjustments and exceptions. Our Senior Secured Credit Facilities allow for the payment of certain tax distributions during 2017 and 2018.

 

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Cash Flows

 

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

 

 

Cash provided by operating activities increased $6.6 million during the nine months ended September 30, 2016 as the decline in net income, excluding non-cash items, during the current year period was offset by favorable variances in working capital accounts, including:

 

 

Net cash used in investing activities was $23.7 million for the nine months ended September 30, 2016, compared to $124.3 million for the nine months ended September 30, 2015. The decline in net cash used in investing activities was partially due to a $41.5 million reduction in capital expenditures due to expansion capital for the second longwall mine at our Sugar Camp complex coming to an end in 2015, the strict controlling of maintenance capital expenditures to preserve liquidity, and the shutdown of production at our Hillsboro mine due to the mine fire. During the nine months ended September 30, 2015, we also made a $75.0 million investment in the Murray Energy transport lease and overriding royalty agreements (see “Item 1. Financial Statements – Note 13. Related-Party Transactions”) and received $19.1 million in proceeds from the settlement of certain outstanding derivative contracts prior to the economically hedged sale transaction occurring.

 

Net cash used in financing activities was $63.4 million for the nine months ended September 30, 2016, compared to $17.0 million for the nine months ended September 30, 2015. During the nine months ended September 30, 2016, we repaid $12.2 million of principal under our A/R securitization program and $33.5 million of principal under our longwall financing and capital lease arrangements. We also incurred debt issuance costs of $15.8 million directly related to the debt restructuring in August 2016. During the nine months ended September 30, 2015, we increased our net borrowings by $134.1 million and paid distributions of $144.7 million.

 

Long-Term Debt, Capital Lease Obligations and Sale-Leaseback Financing Arrangements

On August 30, 2016, we completed a global restructuring of our indebtedness. The Restructuring Transactions alleviated certain defaults and events of default across the Partnership’s capital structure that resulted from the 2015 Delaware Court of Chancery change-of-control litigation related to the purchase and sale agreement between Reserves and Murray Energy. As a result of the Restructuring Transactions and the resolution of the 2015 Delaware Court of Chancery change-of-control litigation, certain of our outstanding long-term debt and capital lease obligations are no longer reflected as a current liability in the condensed consolidated balance sheets and we are no longer subject to default interest rates.

Exchange of 2021 Senior Notes for New Notes and Warrants and Redemption of 2021 Senior Notes

The Partnership exchanged $599.8 million in aggregate principal amount of the 2021 Senior Notes and the accrued and unpaid interest thereon for the following consideration:

 

On the Closing Date, we also redeemed the remaining $175,000 in aggregate principal amount of 2021 Senior Notes that were not exchanged. Upon such redemption, the obligations under the 2021 Senior Notes were satisfied and discharged.

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The Warrants were determined to meet the accounting criteria of a detachable freestanding derivative liability instrument and the fair value of the Warrants on the Closing Date was calculated to be $34.0 million. See Note 17 for additional discussion on the fair value of the Warrants. A liability for the fair value of the Warrant was recorded on our condensed consolidated balance sheet as of the Closing Date and the offset was recognized as a debt discount to the New Notes.  The discount was allocated pro rata between the Second Lien Notes and the Exchangeable PIK Notes in proportion to the relative fair value of each instrument held by a person other than the Reserves Group (see Note 13) on the Closing Date (only the unaffiliated holders of the New Notes received the Warrants on the Closing Date). The $25.0 million discount allocated to the Second Lien Notes and the $9.0 million discount allocated to the Exchangeable PIK Notes will be amortized using the effective interest method over their respective maturities.

Terms of the New Notes

The Second Lien Notes were issued pursuant to an indenture and have a maturity date of August 15, 2021. The Second Lien Notes bear interest at a rate of: (i) 9.0% per annum until August 15, 2018 and 10.0% per annum thereafter, in each case, payable in cash on each interest payment date; and (ii) 1.0% per annum payable in kind. Interest will be payable semi-annually on February 15th and August 15th, commencing on February 15, 2017. The Issuers may redeem the Second Lien Notes in whole or in part subject to the redemption premiums and provisions in the indenture.  

The Exchangeable PIK Notes were issued pursuant to an indenture and have a maturity date of October 3, 2017 (the “Exchangeable PIK Notes Maturity Date”). The Exchangeable PIK Notes bear interest payable in kind at a rate of 15.0% per annum, payable on March 1, 2017 and October 3, 2017.

We may redeem, repurchase, refinance, defease or otherwise retire (any of the foregoing, a “redemption”) all of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at 100% of the principal amount thereof plus accrued interest (any such redemption, an “Exchangeable PIK Note Retirement”). In addition to the Exchangeable PIK Note Retirement, Murray Energy, an affiliate of Murray Energy or a group of persons which includes Murray Energy or any of its affiliates (collectively, the “Murray Group”) shall have the right to purchase all (but not less than all) of the Exchangeable PIK Notes on or prior to October 2, 2017 for cash at a price equal to 100% of the principal amount of the Exchangeable PIK Notes plus accrued interest (a “Murray Purchase,” and together with an Exchangeable PIK Note Retirement and any repayment of the Exchangeable PIK Notes in full in cash that occurs on the Exchangeable PIK Notes Maturity Date, a “Note Redemption”). Upon a Murray Purchase, the Murray Group will receive FELP units equal to the principal and interest settlement amount divided by the lesser of: (a) a number equal to one divided by 92.5% of the last thirty days weighted-average trading price or (b) 1.12007 common units per $1.00 principal amount of Exchangeable PIK Notes. However, the Issuer and Murray Energy may each purchase less than all of the Exchangeable PIK Notes, so long as the combination results in redemption of all of the Exchangeable PIK Notes. The Exchangeable PIK Note Retirement may be funded with the proceeds from an investment by the Murray Group or any member thereof in FELP, from general working capital or from any other source permitted by the Exchangeable PIK Notes Indenture (and subject to compliance with the Partnership’s other debt agreements). If the Exchangeable PIK Notes have not been redeemed or purchased for cash at 100% of the principal amount thereof plus accrued interest by the Exchangeable PIK Note Maturity Date, then all outstanding Exchangeable PIK Notes (including accrued interest) shall be exchanged for Common Units representing 75% of FELP’s outstanding limited partner units on the Exchangeable PIK Notes Maturity Date, subject to adjustment on account of certain anti-dilution protections.

The obligations under the New Notes are unconditionally guaranteed on a senior secured basis by each of FELP’s wholly owned domestic subsidiaries that guarantee the Senior Secured Credit Facilities (other than Foresight Energy Finance Corporation) and on a senior unsecured basis by FELP and are or will be secured by second-priority perfected liens on substantially all of our and the subsidiary guarantors’ existing and future assets, subject to certain exceptions.

Senior Secured Credit Facilities

On the Closing Date, FELLC entered into an amendment to its senior secured credit facilities (as amended, the “Senior Secured Credit Facilities”), pursuant to which outstanding defaults under its existing credit agreement were waived and the credit agreement was amended and restated as set forth in the third amended and restated credit agreement (the “Amended Credit Agreement”). Pursuant to the Amended Credit Agreement, a $297.8 million term loan remains outstanding and matures in August 2020 (the “Term Loan”) and the commitments under our $550.0 million revolving credit facility, which terminates in August 2018, was reduced to $475.0 million (the “Revolving Credit Facility”). As of September 30, 2016, we had $352.5 million in borrowings outstanding under the Revolving Credit Facility and $6.5 million in letters of credit. The commitments under our Revolving Credit Facility will be reduced further to $450.0 million on December 31, 2016. In addition, the Amended Credit Agreement adds an anti-hoarding provision under our Revolving Credit Facility which prohibits new borrowings if the aggregate amount of our unrestricted cash and cash equivalents (taking into account certain pending applications of cash) exceeds $35.0 million both before and after giving effect to such borrowing when taking into account the intended use of such loan proceeds for bona fide purposes within 60 days. Mandatory term loan prepayments are required to be made under our Term Loan based on an excess cash flow calculation, as defined in the Amended

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Credit Agreement, for the second half of fiscal year 2016 and full fiscal year 2017, sales of assets, proceeds of insurance and condemnation awards and certain incurrence of indebtedness, subject, in each case, to customary exceptions and thresholds.

Under the Amended Credit Agreement, borrowings under our Revolving Credit Facility bear interest at a rate equal to, at our option: (i) LIBOR (subject to a LIBOR floor of 0%) plus an applicable margin ranging from 3.50% to 4.50%; or (ii) a base rate plus an applicable margin ranging from 2.50% to 3.50%; in each case, determined in accordance with our consolidated net leverage ratio. Our Term Loan bears interest at a rate equal to, at our option: (i) LIBOR (subject to a LIBOR floor of 1.00%) plus 5.50%; or (ii) a base rate plus 4.50%. We are also required to pay a commitment fee of 0.50% to the lenders under the Revolving Credit Facility in respect of unutilized commitments thereunder and pay a fronting fee equal to 0.125% per annum of the amount available to be drawn under letters of credit. As of September 30, 2016, the weighted-average interest rate on Revolving Credit Facility and Term Loan borrowings was 5.0% and 6.5%, respectively.

The obligations under the Senior Secured Credit Facilities are unconditionally guaranteed on a senior unsecured basis by FELP and on a senior secured basis by our direct and indirect domestic subsidiaries and are or will be secured by first-priority perfected liens on substantially all of our and the subsidiary guarantors’ existing and future assets, subject to certain exceptions.

The Senior Secured Credit Facilities require that we comply on a quarterly basis with certain financial covenants, including a minimum consolidated interest coverage ratio of 2.00:1.00 and a maximum senior secured net leverage ratio ranging from 3.50:1.00 for the fiscal quarter ending September 30, 2016 to 2.75:1.00 for the fiscal quarter ending March 31, 2021 and thereafter. Our Senior Secured Credit Facilities prohibit certain restricted payments, including discretionary dividends, until the later to occur of: (i) June 30, 2018 and (ii) the date on which our obligations under our Revolving Credit Facility have been paid in full, after which restricted payments can be made of up to $25.0 million per year, subject to certain adjustments and exceptions.

 

Trade A/R Securitization Program

 

In January 2015, Foresight Energy LP and certain of its wholly-owned subsidiaries, entered into a $70 million receivables securitization program (the “Securitization Program”). Under this Securitization Program, our subsidiaries sell all of their customer trade receivables (the “Receivables”), on a revolving basis, to Foresight Receivables LLC, a wholly-owned and consolidated special purpose subsidiary of Foresight Energy LP (the “SPV”). The SPV then pledges its interests in the Receivables to the securitization program lenders, which make loans to the SPV. The Securitization Program has a three-year maturity which expires on January 12, 2018. The borrowings under the Securitization Program are variable-rate and also carry a commitment fee for unutilized commitments.

 

In August 2016, we entered into an amended and restated receivables financing agreement pursuant to which the Securitization Program was amended to permanently reduce commitments to $50.0 million. As of September 30, 2016, we had borrowings outstanding of $28.8 million under the Securitization Program.

 

 

Longwall Financing Arrangements and Capital Lease Obligations

 

In November 2014, we entered into a sale-leaseback financing arrangement with a financial institution under which we sold a set of longwall shields and related equipment for $55.9 million and leased the shields back under three individual leases. We account for these leases as capital lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases. Principal and interest payments are due monthly over the five-year terms of the leases. Aggregate termination payments of $2.8 million are due at the end of the lease terms. In connection with the Restructuring, we also executed waivers to cure outstanding defaults under the master lease agreements to our capital lease obligations. These waivers, among other things, ratified the existing terms of each applicable equipment financing agreement, provided the lessor with a waiver fee equal to one hundred basis points of the outstanding amount due under the agreement, increased the interest rate by one percent per annum, and, with respect to certain arrangements, released the lessor from any claims that such parties may have against the lessor with respect to the lease. As of September 30, 2016, $38.9 million was outstanding under these capital lease obligations.

 

In March 2012, we entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment, the interim longwall finance agreement was converted into six individual capital leases with maturities of four and five years beginning on September 1, 2012. Principal and interest payments are due monthly over the terms of the leases. In connection with the Restructuring, we also executed waivers to cure outstanding defaults under the master lease agreements to our capital lease obligations. These waivers, among other things, ratified the existing terms of each applicable equipment financing agreement, provided the lessor with a waiver fee equal to one hundred basis points of the outstanding amount due under the agreement, increased the interest rate by one percent per annum, and, with respect to certain arrangements, released the lessor from any claims that such parties may have against the lessor with respect to the lease. As of September 30, 2016, $7.0 million was outstanding under these capital lease obligations.

 

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In May 2010, we entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement also provided for financing of loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall equipment. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually in March and September until maturity. Principal is due in semiannual payments through maturity. On the Closing Date, we entered into an amendment to the 5.555% longwall financing credit agreement under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last four semi-annual amortization payments. The new maturity date of the 5.555% longwall financing arrangement is September 2019.  In addition, the senior secured leverage ratio financial maintenance covenant was amended to be consistent with the Amended Credit Agreement. The outstanding balance as of September 30, 2016 was $41.3 million.

 

In January 2010, we entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement also provided for financing of the loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall equipment. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually in June and December until maturity. Principal is due in semiannual payments through maturity. On the Closing Date, we entered into an amendment to the 5.78% longwall financing credit agreement under which the lenders waived the existing defaults and the maturity date was accelerated by one year by increasing the last three semi-annual amortization payments. The new maturity date of the 5.78% longwall financing arrangement is June 2019.  In addition, the senior secured leverage ratio financial maintenance covenant was amended to be consistent with the Amended Credit Agreement. The outstanding balance as of September 30, 2016 was $44.8 million.

 

Sale-Leaseback Financing Arrangements - Affiliate

 

In 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP LLC, a subsidiary of Natural Resources Partners LP (“NRP”), and leased them back. The gross proceeds from this transaction were $143.5 million. As Macoupin has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At September 30, 2016, the outstanding balance of the sale-leaseback financing arrangement was $143.3 million and the effective interest rate was 13.9%.

 

In 2012, Sugar Camp sold certain rail facility assets to HOD LLC, a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million. As Sugar Camp has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At September 30, 2016, the outstanding balance of the sale-leaseback financing arrangement was $50.0 million and the effective interest rate was 13.1%.

 

Off-Balance Sheet Arrangements

 

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

 

From time to time, we use bank letters of credit to secure our obligations for certain contracts and other obligations. At September 30, 2016, we had $6.5 million of letters of credit outstanding.

 

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 $82.4 million as of September 30, 2016 to secure reclamation and other performance commitments. In February 2016, we were required to post cash collateral of $2.5 million to our surety bond provider.

Long-Term Debt and Capital Lease Obligations Contractual Obligations

The following is a summary of our significant future contractual long-term and capital lease obligations as of September 30, 2016:

 

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Related-Party Transactions

 

See “Item 1. Financial Statements – Note 13. Related-Party Transactions” and “Item 1. Financial Statements – Note 11. Sale-Leaseback Financing Arrangements – Affiliates” of this Quarterly Report on Form 10-Q. See also Part III. “Item 13. Certain Relationships and Related Transactions” in the Annual Report on Form 10-K filed with the SEC on March 15, 2016.

 

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

 

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

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions in certain circumstances that affect amounts reported in the accompanying condensed consolidated financial statements and related footnotes. In preparing these financial statements, we have made our best estimates of certain amounts included in the financial statements. Application of these accounting policies and estimates, however, involves the exercise of judgment and use of assumptions as to future uncertainties, and as a result, actual results could differ from these estimates. In arriving at our critical accounting estimates, factors we consider include how accurate the estimates or assumptions have been in the past, how much the estimates or assumptions have changed and how reasonably likely such change may have a material impact. Our critical accounting policies and estimates are more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report on Form 10-K filed with the SEC on March 15, 2016. There have been no significant changes to our prior critical accounting policies and estimates subsequent to December 31, 2015, 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.

 

As of September 30, 2016, we have 0.7 million tons economically hedged with forward coal derivative contracts tied to the API 2 coal price index to partially mitigate coal price risk through 2017. The impact of our economic hedges to fix the selling price on unpriced (or index-based) coal sales contracts and forecasted sales is not reflected in the table above. A 10% change in the API 2 index would result in a $4.7 million change in the fair value of outstanding forward coal derivative contracts.

 

We have diesel fuel price exposure in our transportation and production processes and therefore are subject to commodity price risk as a result of changes in the market value of diesel fuel. To limit our exposure to price volatility, we have entered into swap agreements with financial institutions which allow us to pay a fixed price and receive a floating price, which provides a fixed price per unit for the volume of purchases being hedged. As of September 30, 2016, we had 0.3 million gallons of diesel fuel hedged through 2016. A 10% change in the price of diesel fuel would result in a $0.1 million change in the fair value of these derivative contracts.

 

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Interest Rate Risk

 

We are exposed to interest rate risk due to our existing level of indebtedness. At September 30, 2016, of our $1.4 billion in long-term debt and capital lease obligations outstanding, $679.1 million of outstanding borrowings have interest rates that fluctuate based on changes in market interest rates (excluding the impact of default interest rates). A one percentage point increase in the non-default interest rates related to our variable interest borrowings would result in an annualized increase in interest expense of approximately $4.2 million.

 

Item 4. Controls and Procedures.

 

We evaluated, under the supervision and with the participation of our management, including our chief executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2016. 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.

 

PART II – OTHER INFORMATION.

Item 1. Legal Proceedings.

 

See Part I. “Item 1. Financial Statements –Note 18, Contingencies,” to the condensed consolidated financial statements included in this report relating to certain legal proceedings, which information is incorporated by reference herein. See also Part I. “Item 3. Legal Proceedings” in our Annual Report on Form 10-K filed with the SEC on March 15, 2016.

 

Item 1A. Risk Factors.

 

You should carefully consider the risk factors discussed below and under Part I. “Item 1A. Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 15, 2016, which could have a material adverse effect on our business, financial condition, or future results. Such risks described herein and in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, also may have a material adverse effect on our business, operations, financial condition or future results.

 

In connection with the Restructuring Transactions (see “Item 1. Financial Statements – Note 3. Restructuring Transactions”, “Item 1. Financial Statements – Note 10. Long-Term Debt and Capital Lease Obligations” for additional discussion), the Partnership is disclosing the following additional risks to holders of its Common Units.

Unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.  The Exchange Offer could generate substantial cancellation of indebtedness income that will be allocated and taxable to our unitholders.  The amount of such taxable income cannot be determined with precision currently, but the amount of a unitholder’s resulting tax liability per unit may be substantial in relation to, or potentially exceed the value of, a Common Unit.

Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income regardless of whether the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from that income.   Due to restrictions under our new and amended indebtedness, we have suspended regular distributions and expect to be limited to paying certain tax-related distributions for the foreseeable future.

 The Exchange Offer may result in income and gain to our unitholders at the time the Exchange Offer is effective. Transactions that reduce our existing debt, such as debt exchanges, debt repurchases, or modifications and extinguishment of our existing debt would result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to unitholders as ordinary taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom with respect to each Common Unit may be substantial in relation to, or potentially exceed the value of, the Common Unit.  COD income is treated as an extraordinary item under applicable regulations and our partnership agreement and therefore will be allocated to our unitholders that hold units at the effective time of the Exchange Offer.

The amount of COD income that may be generated by the Exchange Offer cannot be determined with precision currently, because it will depend on a combination of factors, including whether the Exchangeable PIK Notes and Second Lien Notes are “publicly traded,” the trading value of such securities before and after consummation of the Exchange Offer if they are publicly traded,

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potentially the trading value of the 2021 Senior Notes (which are currently trading at a substantial discount to par) if the Exchangeable PIK Notes or Second Lien Notes are not publicly traded, and the fair market value of the right to receive the Warrants.  

Entities taxed as corporations may have net operating losses to offset COD income or may otherwise qualify for an exception to the recognition of COD income, such as the bankruptcy or insolvency exceptions. As long as we are treated as a partnership, however, the exceptions are not available to us and are only available to unitholders if unitholders are personally insolvent. As a result, these exceptions generally would not apply to prevent the taxation of COD income allocated to unitholders. The ultimate tax effect of any such income allocations will depend on the unitholder’s individual tax position, including, for example, the unitholder’s allocable share of any current ordinary losses, if any, that we may generate from the operation of our business or disposition of assets and the availability of any passive losses previously suspended by the unitholder that may offset some portion of the allocable COD income. Unitholders may, however, be allocated substantial amounts of ordinary income subject to taxation, without any ability to offset such allocated income against any capital losses attributable to their ultimate disposition of units. Unitholders, or prospective unitholders, are encouraged to consult their tax advisor with respect to the consequences to them of COD income.

 

The Restructuring Transactions contemplate the potential issuances of additional equity securities by us which would significantly dilute the ownership of our existing unitholders.

 

We may issue a significant amount of additional equity securities to our creditors in connection with the Restructuring Transactions. To the extent we issue substantial additional equity securities, the ownership of our existing unitholders would be diluted and such dilution could be substantial.

Restrictions in the agreements governing our new and amended indebtedness further limit our ability to make distributions to our unitholders.

 

The new agreements and amendments to our existing debt agreements (including the indentures governing the Second Lien Notes and the Exchangeable PIK Notes and amendments to our amended and restated credit agreement and our other debt agreements) provide restricted payments provisions that, in material respects, are even more restrictive than our prior debt agreements.

 

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

 

None.

 

Item 3. Defaults Upon Senior Securities.

 

Defaults under our debt arrangements were cured as part of the Restructuring Transactions, see Part I. “Item 1. Financial Statements –Note 3, Restructuring Transactions.”

 

Item 4. Mine Safety Disclosures.

 

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

 

Item 5. Other Information

 

None.

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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 November 9, 2016.

 

 

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Item 6. Exhibits.

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