UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended March 31, 2018

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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

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

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

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

 

 

 

 

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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

(In Thousands)

 

 

See accompanying notes.

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Foresight Energy LP

Unaudited Condensed Consolidated Statements of Operations

(In Thousands, Except per Unit Data)

 

 

See accompanying notes.

 

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Foresight Energy LP

Unaudited Condensed Consolidated Statement of Partners’ Capital

(In Thousands, Except Unit Data)

 

 

See accompanying notes.

 

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Foresight Energy LP

Unaudited Condensed Consolidated Statements of Cash Flows

(In Thousands)

 

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. Because this transaction was between entities under common control, the contributed assets and liabilities of FELLC were recorded in the combined consolidated financial statements of FELP at FELLC’s historical cost. FELP has been managed by Foresight Energy GP LLC (“FEGP”) subsequent to the IPO.

 

On April 16, 2015, Murray Energy Corporation and its affiliates (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% voting interest in FEGP and all of the outstanding subordinated units of FELP, representing a 50% ownership of the Partnership’s limited partner units outstanding at that time. On March 28, 2017, following the completion of a debt refinancing (the “March 2017 Refinancing Transactions”), Murray Energy exercised its option (the “FEGP Option”) to acquire an additional 46% voting interest in FEGP from Foresight Reserves and a former member of management pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and a former member of management, as amended, thereby increasing Murray Energy’s voting interest in FEGP to 80%. The aggregate exercise price of the FEGP Option was $15 million. Murray Energy’s acquisition of the incremental ownership in FEGP resulted in its obtaining control of FELP. Per Accounting Standards Codification (“ASC”) 805-50-25-4, Murray Energy, as the acquirer of FELP through FEGP, has the option to apply pushdown accounting in the separate financial statements of the acquiree. Murray Energy elected to adopt pushdown accounting in our stand alone financial statements and therefore we have reflected the adjustment of our assets and liabilities to fair value required by pushdown accounting in our consolidated financial statements.

 

Due to the application of pushdown accounting, our condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. The periods prior to the acquisition date are identified as “Predecessor” and the period after the acquisition date is identified as “Successor”. For accounting purposes, management has designated the acquisition date as March 31, 2017 (the “Acquisition Date”), as the operating results and change in financial position for the intervening period was not material.

 

As used hereafter in this report, the terms “Foresight Energy LP,” “FELP,” the “Partnership,” “we,” “us” or like terms, refer to the consolidated results of Foresight Energy LP and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated.

 

The Partnership operates in a single reportable segment and currently owns four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). Mining operations at our Hillsboro complex have been idled since March 2015 due to a combustion event. On April 11, 2018, we announced that our Hillsboro operation will be permanently closed (see Note 13). Our mined coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern United States, as well as overseas markets.

The accompanying condensed consolidated financial statements contain all significant adjustments (consisting of normal recurring accruals) that, in the opinion of management, are necessary to present fairly, the Partnership’s condensed consolidated financial position, results of operations and cash flows for all periods presented. In preparing the condensed consolidated financial statements, management used estimates and assumptions that may affect reported amounts and disclosures. To the extent there are material differences between the estimates and actual results, the impact to the Partnership’s financial condition or results of operations could be material. The unaudited condensed consolidated financial statements do not include footnotes and certain financial information as required annually under U.S. generally accepted accounting principles (“U.S. GAAP”) and, therefore, should be read in conjunction with the annual audited consolidated financial statements for the year ended December 31, 2017 included in our Annual Report on Form 10-K filed with the SEC on March 7, 2018. The results of operations for interim periods are not necessarily indicative of results that can be expected for any future period, including the year ending December 31, 2018. Intercompany transactions are eliminated in consolidation.

 

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2. New Accounting Standards

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

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

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

 

3. Revenue from Contracts with Customers

 

Significant Accounting Policy

 

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

 

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

 

Nature of Goods and Services

 

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

 

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

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

 

Disaggregation of Revenue

The following table disaggregates revenue by domestic and international markets:

 

 

Contract Balances

 

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

 

 

Contract Costs

 

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

 

Other Revenues

 

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

 

 

 

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4. Supplemental Cash Flow Information

 

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

 

 

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

 

 

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

 

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

 

5. Accounts Receivable

 

Accounts receivable consist of the following:

 

 

 

 

 

 

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6. Inventories, Net

Inventories, net consist of the following:

 

 

 

 

 

7. Property, Plant, Equipment and Development, Net

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

 

 

 

8. Long-Term Debt and Capital Lease Obligations

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

 

 

Term Loan due 2022

 

The Term Loan due 2022 bears interest at the borrower’s option of (a) LIBOR (subject to a LIBOR floor of 1.00%) plus 5.75% per annum; or (b) a base rate plus 4.75% per annum. The Term Loan due 2022 also requires us to prepay outstanding borrowings (the

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

 

Second Lien Notes due 2023

 

The Second Lien Notes due 2023 have a maturity date of April 1, 2023 and bear interest at a rate of 11.50% per annum, payable in cash semi-annually on April 1 and October 1.

 

Revolving Credit Facility

 

The Revolving Credit Facility has a total borrowing capacity of $170.0 million and bears interest at the borrower’s option of (a) LIBOR (subject to a floor of zero) plus an applicable margin ranging from 5.25% to 5.50% per annum or (b) a base rate plus an applicable margin ranging from 4.25% to 4.50% per annum. We are required to pay a quarterly commitment fee with respect to the unused portions of our Revolving Credit Facility and customary letter of credit fees.

 

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

 

9. Related-Party Transactions

 

Overview

 

Affiliated entities of FELP principally include: (a) Murray Energy, owner of a 80% interest in our general partner (effective March 28, 2017) and owner of all of the outstanding subordinated limited partner units, (b) Entities owned and controlled by Chris Cline, the former majority owner and former chairman of our general partner and (c) through May 8, 2017, Natural Resource Partners LP (“NRP”) and its affiliates, for which Chris Cline directly and indirectly beneficially owned a 31% and 4% interest in the general and limited partner interests of NRP, respectively. On May 9, 2017, the affiliate owned by Chris Cline sold its holdings in NRP’s general partner.  As a result, NRP and its affiliates were not treated as related parties after May 8, 2017. We routinely engage in transactions in the normal course of business with Murray Energy and its subsidiaries, NRP and its subsidiaries and Foresight Reserves and its affiliates. These transactions include, among others, production royalties, transportation services, administrative arrangements, coal handling and storage services, supply agreements, service agreements, land leases and sale-leaseback financing arrangements. We also acquire mining equipment from subsidiaries of Murray Energy.

 

Murray Investments

 

In April 2015, Foresight Reserves and Murray Energy executed a purchase and sale agreement whereby Murray Energy paid Foresight Reserves $1.37 billion to acquire a 34% voting interest in FEGP, 77.5% of FELP’s incentive distribution rights (“IDRs”) and nearly 50% of the outstanding limited partner units in FELP, including all of the outstanding subordinated units. On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to us in exchange for 9,628,108 common units of FELP. On March 28, 2017, following completion of the March 2017 Refinancing Transactions, Murray Energy exercised its FEGP Option to acquire an additional 46% voting interest in FEGP from Foresight Reserves and a former member of management pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and a former member of management, as amended, thereby increasing Murray Energy’s voting interest in FEGP to 80%. The aggregate exercise price of the FEGP Option was $15 million. FEGP has continued to govern the Partnership subsequent to this transaction. Murray Energy was also a holder of 17,556 of FELP’s outstanding warrants. All outstanding warrants held by Murray Energy were exercised in 2017 and Murray Energy held no outstanding warrants as of March 31, 2018.

 

Following the exercise of the FEGP Option, certain changes to the operating agreement of FEGP went into effect, pursuant to which Murray Energy is entitled to appoint a majority of the board of directors of FEGP (the “Board”). On March 28, 2017, Chris Cline resigned from the Board and from his role as Principal Strategy Advisor. In connection with the departure of Mr. Cline, Robert D. Moore now serves as Chairman of the Board and Mr. Robert Edward Murray became a member of the Board. Mr. Murray currently serves as the Executive Vice President of Marketing and Sales at Murray Energy. All members of the Board, other than Paul Vining, are deemed appointed by Murray Energy and can be removed and replaced by Murray Energy at its sole discretion.

 

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Murray Energy Management Services Agreement

 

In April 2015, a management services agreement (“MSA”) was executed between FEGP and Murray American Coal, Inc. (the ”Manager”), a wholly-owned subsidiary of Murray Energy, pursuant to which the Manager provided certain management and administration services to FELP for a quarterly fee of $3.5 million ($14.0 million on an annual basis), subject to contractual adjustments. To the extent that FELP or FEGP directly incurs costs for any services covered under the MSA, then the Manager’s quarterly fee is reduced accordingly. Also, to the extent that the Manager utilizes outside service providers to perform any of the services under the MSA, then the Manager is responsible for those outside service provider costs. The initial term of the MSA extends through December 31, 2022 and is subject to termination provisions. Upon the exercise of the FEGP Option, FEGP entered into an amended and restated MSA pursuant to which the quarterly fee for the Manager to provide certain management and administration services to FELP was increased to $5.0 million ($20.0 million on an annual basis) and is subject to future contractual escalations and adjustments. After taking into account the contractual escalations and adjustments for direct costs incurred by FELP, the amount of net expense due to the Manager for the three months ended March 31, 2018 and 2017 was $4.0 million and $2.5 million, respectively.

 

Murray Energy Transport Lease and Overriding Royalty Agreements

 

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

 

For the three months ended March 31, 2018 and 2017, we recorded other revenues of $0.7 million and $0.8 million, respectively, under the overriding royalty agreement (the “ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company. The total remaining minimum payments under the ORRA were $29.6 million at March 31, 2018, with unearned income equal to $18.2 million. As of March 31, 2018, the outstanding ORRA financing receivable was $11.4 million, of which $0.2 million was classified as current in the condensed consolidated balance sheet.

 

Other Murray Energy Transactions

 

During the three months ended March 31, 2018 and 2017, we purchased $4.1 million and $2.1 million, respectively, in equipment, supplies and rebuild services from affiliates of Murray Energy.  During the three months ended March 31, 2018 and 2017, we provided $0.1 million and $0.1 million, respectively, in equipment, supplies and rebuild services to affiliates of Murray Energy.

 

From time to time, we purchase and sell coal to Murray Energy and its affiliates to, among other things, meet customer contractual obligations. We also sell coal to Javelin Global Commodities Limited (“Javelin”), an international commodities marketing and trading joint venture owned by Murray Energy, Uniper, and management of Javelin, as our primary outlet for export sales. During the three months ended March 31, 2018 and 2017, we purchased $1.8 million and $8.0 million, respectively of coal from Murray Energy and its affiliates and we sold $85.1 million and $60.7 million, respectively, of coal to Murray Energy and its affiliates, including Javelin.

 

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

 

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

 

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

 

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

 

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

 

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

 

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Reserves Investor Group

 

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

 

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

 

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

Mineral Reserve Leases

 

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

 

Limited Partnership Agreement

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

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

 

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

 

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

Principal location in the condensed consolidated financial statements:

(1) – Coal sales

(2) – Other revenues

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

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(4) – Transportation  

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

(6) – Cost of coal purchased  

(7) – Selling, general and administrative

(8) – Interest expense, net

 

Transactions with NRP and affiliated entities are only included in the table above through April 30, 2017 as a result of NRP no longer being an affiliate subsequent to Chris Cline’s affiliate selling its interest in NRP’s general partner on May 9, 2017.

 

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

 

10. Earnings per Limited Partner Unit

 

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

 

The Partnership’s net loss is allocated to the limited partners, including the holders of the subordinated units, in accordance with the partnership agreement on their respective ownership percentages, after giving effect to any special income or expense allocations and incentive distributions paid to the general partner, if any. The holders of our IDRs have the right to receive increasing percentages of quarterly distributions from operating surplus after certain distribution levels defined in the partnership agreement have been achieved. The general partner has no obligation to make distributions; therefore, undistributed earnings of the Partnership are not allocated to the IDRs. Basic EPU is computed by dividing net earnings attributable to unitholders by the weighted-average number of units outstanding during each period. Diluted EPU reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.

 

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

 

 

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11. Fair Value of Financial Instruments

 

Warrants

In August 2016, FELP issued 516,825 warrants (the “Warrants”) to the unaffiliated owners of previously outstanding debt to purchase an amount of common units. Upon their issuance, the Warrants were recorded as a liability at fair value and remeasured to fair value at each balance sheet date. The resulting non-cash gain or loss on remeasurements was recorded as a non-operating loss in our consolidated statements of operations.

 

As a result of a series of transactions related to the March 2017 Refinancing Transactions, the establishment of a fixed exchange rate for the conversion of the Warrants to a number of common units resulted in the warrant liability being reclassified to partners’ capital, and therefore, were not remeasured at fair value subsequent to the March 2017 Refinancing Transactions. As of March 31, 2018, there are 142,530 Warrants outstanding and exercisable into 13.4 common units of FELP at an exercise price of $0.8531 per common unit.

Long-Term Debt

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

 

12. Contingencies

 

In January 2016, WPP LLC (“WPP”), a subsidiary of NRP, a sent a demand letter to Macoupin claiming it had misapplied the royalty recoupment provision involving a coal mining lease and a rail infrastructure lease, resulting in underpayments of $3.3 million. In April 2016, WPP and HOD LLC (“HOD”), a subsidiary of NRP filed a complaint in the Circuit Court of Macoupin County, Illinois. As of December 31, 2017, WPP claims it is owed $9.5 million. We do not believe that the royalty recoupment provision was misapplied and have continued to apply the recoupment provision consistently with prior periods. While we believe that the language of the agreements and the parties’ course of performance thereunder support Macoupin’s position, should we not prevail, we would be responsible for paying WPP for any recoupment taken that is found to contravene the contractual language. Macoupin has filed a motion to dismiss the Complaint, which is pending.

 

In July 2015, we provided notice to WPP declaring a force majeure event at our Hillsboro mine due to a combustion event. As a result of the force majeure event, as of March 31, 2018, we have not made $83.5 million in minimum deficiency payments to WPP in accordance with the force majeure provisions of the royalty agreement. On November 24, 2015, WPP filed a Complaint in the Circuit Court of Montgomery County, Illinois, against Hillsboro, and WPP has subsequently amended its Complaint. On October 6, 2017, the Circuit Court dismissed many of the claims in the Third Amended Complaint against Hillsboro and the Partnership and other of its subsidiaries. However, WPP was afforded a chance to replead some claims, and WPP’s claim for breach of the royalty agreement will proceed. While we believe this is a force majeure event, as contemplated by the royalty agreement, and that the alleged claims are without merit, should we not prevail, we would be responsible for funding any minimum deficiency payment amounts during the shutdown period to WPP and potentially additional fees and interest of 1% per month. A bench trial to resolve the dispute over Hillsboro’s declaration of force majeure is currently set for October 22, 2018.

 

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

 

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

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We cannot reasonably estimate the ultimate legal and financial liability with respect to all pending litigation matters. However, we believe, based on our examination of such matters, that the ultimate liability will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  

 

Insurance Recoveries

 

We are currently in discussions with our insurance provider in regards to further potential recoveries under our policy related to the combustion event at our Hillsboro operation. From the date of the combustion event through December 31, 2017, we have recognized $46.9 million of insurance recoveries related to the recovery of mitigation costs and business interruption insurance proceeds.  We continue to pursue additional remedies under our insurance policies; however, there can be no assurances that we will receive any further insurance recoveries related to this incident.

 

Performance Bonds

 

We had outstanding surety bonds with third parties of $85.8 million as of March 31, 2018 to secure reclamation and other performance commitments, which are partially secured by $4.5 million of our outstanding letters of credit.

 

13. Subsequent Event

 

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

 

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

 

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

 

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

 

 

 

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

 

Company Overview

 

Foresight Energy LLC (“FELLC”), a perpetual-term Delaware limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves LP (“Foresight Reserves”) owned 99.333% of FELLC and a member of FELLC’s management owned 0.667%. On June 23, 2014, in connection with the initial public offering (“IPO”) of Foresight Energy LP (“FELP,” “we,” “us,” and “our”), Foresight Reserves and a member of FELLC’s management contributed their ownership interests in FELLC to FELP in exchange for common and subordinated units in FELP. FELP has been managed by Foresight Energy GP LLC (“FEGP”) subsequent to the IPO. On April 16, 2015, Murray Energy Corporation (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% voting interest in FEGP and all of the outstanding subordinated units of FELP, representing 50% ownership of the Partnership’s limited partner units outstanding at that time. On March 28, 2017, Murray Energy acquired an additional 46% voting interest in FEGP, thereby increasing Murray Energy’s voting interest in the FEGP to 80%.

 

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

 

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

 

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

 

Pushdown Accounting

 

Murray Energy, as the acquirer of FELP through our general partner, had the option to apply pushdown accounting to our stand alone financial statements and elected to do so, therefore, our consolidated financial statements were adjusted to reflect the preliminary purchase accounting adjustments. Due to the application of pushdown accounting, our condensed consolidated financial statements are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. The periods prior to the acquisition date are identified as “Predecessor” and the period after the acquisition date is identified as “Successor”.  For accounting purposes, management has designated the acquisition date as March 31, 2017 (the “Acquisition Date”), as the operating results and change in financial position for the intervening period is not material.

 

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

 

Key Metrics

 

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

 

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, contract amortization, 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 (loss), operating income, cash flow from operations, or as a measure of profitability or liquidity under U.S. GAAP. The primary limitation associated with the use of Adjusted EBITDA as compared to U.S. GAAP results are (i) it may not be comparable to similarly titled measures used by other companies in our industry, and (ii) it excludes financial information that some consider important in evaluating our performance. We compensate for these limitations by providing a reconciliation of Adjusted EBITDA to U.S. GAAP results to enable users to perform their own analysis of our operating results.

 

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Results of Operations

 

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

 

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

 

 

 

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

 

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

 

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

 

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

 

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Liquidity and Capital Resources

 

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

 

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

 

•                  75% (which percentage will be reduced to 50%, 25% and 0% based on satisfaction of specified net secured leverage ratio tests) of our annual excess cash flow, as defined under the Credit Facilities; 

•                  100% of the net cash proceeds of non-ordinary course asset sales and other dispositions of property, in each case subject to certain exceptions and customary reinvestment rights; 

•                  100% of the net cash proceeds of insurance (other than insurance proceeds relating to the Deer Run mine), in each case subject to certain exceptions and customary reinvestment rights; and 

•                  100% of the net cash proceeds of any issuance or incurrence of debt, other than proceeds from debt permitted under the Credit Facilities.

 

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

 

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

 

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

 

Distributions

 

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

 

Changes in Cash Flows

 

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

 

 

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

 

 

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

 

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

 

Long-Term Debt and Sale-Leaseback Financing Arrangements

 

Summary of March 2017 Refinancing Transactions and Additional Murray Energy Investment

 

On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to FELP in exchange for 9,628,108 common units of FELP. The cash was utilized to redeem, pursuant to an equity claw redemption provision, $54.5 million of the then outstanding Second Lien Senior Secured PIK Notes due 2021 (the “Prior Second Lien Notes”) at a redemption price equal to 110% of the principal thereof, plus accrued and unpaid interest.

 

On March 28, 2017 (the “Closing Date”), FELP, together with its wholly-owned subsidiaries FELLC (the “Borrower”) and Foresight Energy Finance Corporation (the “Co-Issuer” and together with FELLC, the “Issuers” and certain of the Issuers’ subsidiaries, completed the March 2017 Refinancing Transactions, which were a series of transactions to refinance certain previously outstanding indebtedness. The debt issued was as follows:

 

 

The Partnership retired the following indebtedness in the March 2017 Refinancing Transactions:

 

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Description of the Credit Facilities

 

The Term Loan due 2022 was issued at an initial discount of $12.4 million, which is being amortized using the effective interest method over the term of the loan. Amounts outstanding under the Credit Facilities bear interest as follows:

 

•                  in the case of the Term Loan due 2022, at the Borrower’s option, at (a) LIBOR (subject to a floor of 1.00%) plus 5.75% per annum; or (b) a base rate plus 4.75% per annum; and

•                  in the case of borrowings under the Revolving Credit Facility, at the Borrower’s option, at (a) LIBOR (subject to a floor of zero) plus an applicable margin ranging from 5.25% to 5.50% per annum or (b) a base rate plus an applicable margin ranging from 4.25% to 4.50% per annum, in each case, such applicable margins to be determined based on our net first lien secured leverage ratio.

 

In addition to paying interest on the outstanding principal under the Credit Facilities, we are required to pay a quarterly commitment fee with respect to the unused portions of our Revolving Credit Facility and customary letter of credit fees. The Credit Facilities requires scheduled quarterly amortization payments on the Term Loan due 2022 in an aggregate annual amount equal to 1.0% of the original principal amount of the Term Loan due 2022, with the balance to be paid at maturity.

 

The Credit Facilities require us to prepay outstanding borrowings, subject to certain exceptions, as described under “Liquidity and Capital Resources” above. We may also voluntarily repay outstanding loans under the Credit Facilities at any time, without prepayment premium or penalty, except in connection with a repricing transaction in respect of the Term Loan due 2022, in each case subject to customary “breakage” costs with respect to Eurodollar Rate loans. All obligations under the Credit Facilities are guaranteed by FELP on a limited recourse basis (where recourse is limited to its pledge of stock of the Borrower) and are or will be unconditionally guaranteed, jointly and severally, on a senior secured first-priority basis by each of the Borrower’s existing and future direct and indirect, wholly-owned domestic restricted subsidiaries (which do not currently include Hillsboro Energy LLC), subject to certain exceptions.

 

The Credit Facilities require that we comply on a quarterly basis with a maximum net first lien secured leverage ratio of 3.75:1.00, stepping down by 0.25x in each of the first quarters of 2019 and 2021, which financial covenant is solely for the benefit of the lenders under the Revolving Credit Facility. The Credit Facilities also contain certain customary affirmative covenants and events of default, including relating to a change of control.

 

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

 

Description of the Second Lien Notes due 2023

 

On the Closing Date, the Issuers issued $425 million aggregate principal amount of Second Lien Notes due 2023 (the “Notes”) pursuant to an indenture (the “Indenture”), by and among the Issuers, the guarantors party thereto and the trustee. The Notes have a maturity date of April 1, 2023 and bear interest at a rate of 11.50% per annum, payable in cash semi-annually on April 1 and October 1 (commencing on October 1, 2017). The Notes were issued at an initial discount of $3.2 million, which is being amortized using the effective interest method over the term of the notes. The obligations under the Notes are unconditionally guaranteed, jointly and severally, on a senior secured second-priority basis by each of the Issuers’ wholly-owned domestic subsidiaries that guarantee the Credit Facilities (which do not include Hillsboro Energy LLC). The Indenture contains certain usual and customary negative covenants and events of default, including related to a change in control.

 

Prior to April 1, 2020, the Issuers may redeem the Notes in whole or in part at a price equal to 100% of the aggregate principal amount thereof plus accrued and unpaid interest, if any, plus the applicable “make-whole” premium. In addition, prior to April 1, 2020, the Issuers may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 111.50% of the aggregate principal amount of the Notes redeemed with the proceeds from a qualified equity offering, subject to at least 50% of the aggregate principal amount of the Notes remaining outstanding after giving effect to any such redemption. On or after April 1, 2020, the Issuers may redeem the Notes at a price equal to: (i) 105.750% of the aggregate principal amount of the Notes redeemed prior to April 1, 2021; (ii) 102.875% of the aggregate principal amount of the Notes redeemed on or after April 1, 2021 but prior to April 1, 2022; and (iii) 100.000% of the aggregate principal amount of the Notes redeemed thereafter.

 

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Longwall Financing Arrangements and Capital Lease Obligations

 

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

 

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

 

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

 

Sale-Leaseback Financing Arrangements

 

In 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP LLC (“WPP”), a subsidiary of Natural Resource Partners LP (“NRP”), and leased them back. The gross proceeds from this transaction were $143.5 million. As Macoupin has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. The Macoupin financing arrangement has been adjusted to fair value as part of pushdown accounting. The Macoupin financing arrangement had a carrying value of $133.2 million as of March 31, 2018 and an effective interest rate of 14.7%.

 

In 2012, Sugar Camp sold certain rail facility assets to HOD LLC (“HOD”), a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million. As Sugar Camp has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. The Sugar Camp financing arrangement has been adjusted to fair value as part of pushdown accounting. The Sugar Camp financing arrangement had a carrying value of $67.2 million as of March 31, 2018 and an effective interest rate of 8.4%.

 

Off-Balance Sheet Arrangements

 

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

 

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

 

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

 

Related-Party Transactions

 

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

 

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Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

 

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

 

Critical Accounting Policies and Estimates

 

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

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

 

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

 

Commodity Price Risk

 

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

 

Interest Rate Risk

 

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

 

Item 4. Controls and Procedures.

 

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

 

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PART II – OTHER INFORMATION.

Item 1. Legal Proceedings.

 

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

 

Item 1A. Risk Factors.

 

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

 

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

 

None.

 

Item 3. Defaults Upon Senior Securities.

 

None.

 

Item 4. Mine Safety Disclosures.

 

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

 

Item 5. Other Information

 

None.

 

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Item 6. Exhibits

 

 

 

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SIGNATURES

 

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

 

 

 

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