Item 1. Business
We mine and market coal from reserves and operations located exclusively in the Illinois Basin. As of December 31, 2015, we have invested over $2.3 billion to construct state-of-the-art, low-cost and highly productive mining operations and related transportation infrastructure. We control over 3 billion tons of proven and probable coal in the state of Illinois, which, in addition to making us one of the largest reserve holders in the United States, provides organic growth opportunities. Our reserves consist principally of three large contiguous blocks of uniform, thick, high heat content (high Btu) thermal coal which is ideal for highly productive longwall operations. Thermal coal is used by power plants and industrial steam boilers to produce electricity or process steam.
We own four mining complexes where we operate four longwall mines and one continuous miner operation. Our four mining complexes can collectively support up to nine longwalls, with a portion of the existing surface infrastructure available to be shared among most of our potential future longwalls. Mining operations at our Hillsboro complex have been idled since March 2015 due to a combustion event.
Our operations are strategically located near multiple rail and river transportation access points giving us cost-competitive transportation options. We have developed infrastructure that provides each of our four mining complexes with multiple transportation outlets including direct and indirect access to five Class I railroads. Our access to competing rail carriers as well as access to truck and barge transport provides us with operating flexibility and minimizes transportation costs. In February 2015, Foresight Reserves L.P. (“Foresight Reserves”) contributed Sitran LLC (“Sitran”), a 25 million ton per year barge-loading river terminal on the Ohio River to us. We also have contractual agreements for 6 million tons per year of export terminal capacity in the Gulf of Mexico and have long-term, fixed price transportation contracts from our mines to these terminals. These logistical arrangements provide transportation cost certainty and the flexibility to direct shipments to markets that provide the highest margin for our coal sales.
We sell a significant portion of our coal under agreements with terms of one year or longer. We market and sell our coal to a diverse customer base, including electric utility and industrial companies in the eastern United States and the international market. We sell the majority of our domestic tonnages to electric utilities with installed pollution control devices. These devices, also known as scrubbers, are designed to eliminate substantially all emissions of sulfur dioxide.
Foresight Energy LP, a Delaware limited partnership formed on January 26, 2012, completed its initial public offering on June 23, 2014 and is listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “FELP.” We are managed and operated by the board of directors and executive officers of our general partner, Foresight Energy GP LLC, which is owned by Foresight Reserves, Murray Energy Corporation (“Murray Energy”), and a former member of management.
Below is a diagram of our organizational and ownership structure as of March 11, 2016:
(1)
The list below details the names of our operating subsidiaries. Certain of our non-corporate operating subsidiaries rely exclusively on affiliated contract mining companies for their operations, which are consolidated as variable interest entities.
- Adena Resources LLC
- Foresight Energy Services LLC
- Sitran LLC
- Akin Energy LLC
- Foresight Receivables LLC
- Tanner Energy LLC
- American Century Minerals LLC
- Hillsboro Energy LLC
- Williamson Energy LLC
- American Century Transport LLC
- Macoupin Energy LLC
- Foresight Coal Sales LLC
- Oeneus LLC d/b/a Savatran LLC
- Foresight Energy Employee Services Corporation
- Seneca Rebuild LLC
(2)
Includes common units held by executive officers and directors (other than Christopher Cline).
Debt Defaults
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 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.
Because of the existence of “change of control” provisions and cross-default or cross-event of default provisions in our other debt agreements, the purchase and sale agreement between Foresight Reserves and Murray Energy also resulted, directly or indirectly, in events of default under Foresight Energy LLC’s credit agreement governing its senior secured credit facilities (the “Credit Agreement”), Foresight Receivables LLC’s receivables securitization program and certain other financing arrangements, including our longwall financing arrangements. The existence of an event of default has prohibited us access to borrowings or other extensions of credit under our Revolving Credit Facility.
On December 18, 2015, we entered into a forbearance agreement (as amended, the “Notes Forbearance Agreement”) with Wilmington Savings Fund Society, FSB, as successor indenture trustee (the “Trustee”), and certain holders of the 2021 Senior Notes who collectively beneficially own or manage in excess of 75% of the aggregate principal amount of the 2021 Senior Notes (the “Consenting Noteholders”). Under the Notes Forbearance Agreement, the Consenting Noteholders and the Trustee agreed to forbear from exercising certain rights and remedies to which they may be entitled in respect of the 2021 Senior Notes or under the Indenture. The Notes Forbearance Agreement currently remains in effect through March 15, 2016, unless extended by the Consenting Noteholders in their sole discretion. There can be no assurances that the Consenting Noteholders will agree to any extension of the Notes Forbearance Agreement or that, if such forbearance agreement is terminated early or otherwise expires or terminates pursuant to its terms, the requisite noteholders under the Indenture will not pursue any and all remedies available to them under the Indenture or otherwise.
On January 27, 2016, we entered into a forbearance agreement in respect of our securitization program (as amended, the “Securitization Forbearance Agreement”), pursuant to which the agent under that facility and the lenders under the securitization program agreed to forbear from exercising certain rights and remedies to which they may be entitled. The Securitization Forbearance Agreement currently remains in effect through March 15, 2016, unless extended by the securitization lenders in their sole discretion. There can be no assurances that the securitization lenders will agree to any extension of the Securitization Forbearance Agreement or that, if such forbearance agreement is terminated early or expires, that the securitization lenders will not pursue any and all remedies available to them. Also under the Securitization Forbearance Agreement, the receivables facility was amended to permanently reduce commitments to $50.0 million in total, and we may borrow up to an amount such that the aggregate amount outstanding plus any adjusted LC participation amount at such time does not exceed the least of (i) $41.0 million, (ii) the borrowing base at such time and (iii) an amount equal to 70% of the outstanding balance of the eligible receivables. Any extensions of credit by the lenders during the forbearance period are in their sole and absolute discretion.
We have not entered into forbearance agreements with the lenders under our Credit Agreement or the lenders under our equipment financing arrangements. Therefore, the lenders under the Credit Agreement and our equipment financing arrangements may exercise any remedies available to them at any time. The remedies available to the lenders under the Credit Agreement include acceleration of the indebtedness owed thereunder and exercising remedies with respect to our collateral securing such indebtedness. There can be no assurances that our creditors will not accelerate the indebtedness under their respective facilities or exercise any rights or remedies to which they are entitled.
On February 16, 2016, we did not pay the accrued interest owed to holders of the 2021 Senior Notes on such day and elected to exercise the 30-day grace period with respect to the interest payment due under the Indenture. The aggregate amount of the interest payment due is $23.6 million. If we do not make the interest payment by the end of the 30-day grace period, an additional event of default will exist under the Indenture. In addition, an event of default will exist under the Credit Agreement, Foresight Receivables LLC’s securitization agreement and the credit agreements governing certain equipment financings of certain of our other subsidiaries.
Our auditor’s opinion in connection with our 2015 financial statements includes an explanatory paragraph regarding the uncertainty of the Partnership’s ability to continue as a “going concern” which will result in an additional default under the terms of the Credit Agreement as well as the 2021 Senior Notes, Foresight Receivables LLC’s securitization agreement and the credit agreements governing certain equipment financings of certain of our other subsidiaries, because these agreements require delivery of financial statements without a going concern explanatory paragraph in the auditor opinion.
We are actively negotiating an out-of-court restructuring with certain holders of the 2021 Senior Notes (the “Consenting Noteholders”), who collectively beneficially own or manage in excess of 75% of the aggregate principal amount of the 2021 Senior Notes, and our other creditors. There can be no assurance that these efforts will result in any agreement.
We have engaged financial and legal advisors to advise us regarding potential alternatives to address the issues described above. We cannot assure you that any restructuring will be possible on acceptable terms, if at all. It may be difficult to come to an agreement that is acceptable to all of our creditors. Our failure to reach an agreement on the terms of a restructuring with our creditors or the failure to extend any forbearance agreement in connection with the related negotiations would have a material adverse effect on our liquidity, financial condition and results of operations.
If an agreement on the terms of an out-of-court restructuring is not reached, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in order to implement a restructuring, or our creditors could force us into an involuntary bankruptcy or liquidation. If a plan of reorganization is implemented in a bankruptcy proceeding, it is likely that holders of claims and interests with respect to, or rights to acquire our equity securities, would be entitled to little or no recovery, and those claims and interests would be canceled for little or no consideration. If that were to occur, we anticipate that all, or substantially all, of the value of all investments in our partnership units will be lost and that our unitholders would lose all or substantially all of their investment. It is also likely that our other stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.
Given the difficult coal market conditions expected for 2016, we believe that there is a reasonable possibility that we may not be able to comply with our financial covenants during 2016. Failure to comply with these financial covenants would be an additional default under the terms of the Credit Agreement and could result in the acceleration of all of our debt obligations. If we are unable to comply with our financial covenants, we would be required to seek one or more amendments or waivers from our lenders. We may not be able to do so on favorable terms, if at all. If we were unable to obtain any required amendments or waivers, our lenders would have the right to exercise remedies specified in the loan agreements, including accelerating the repayment of debt obligations and taking collection action against us. If such acceleration occurred, we currently have insufficient cash to pay the amounts owed and would be forced to seek alternative financing. However, we may not be able to obtain such financing on favorable terms, if at all.
For more information on the specific risks we face due to the above defaults, see Part I. “Item 1A.
Item 2. Properties
Coal Reserves
We believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our current reserve base is one of our strengths. We estimate that we controlled over 3 billion tons, almost entirely through lease, of proven and probable recoverable reserves at December 31, 2015. Our coal reserve estimate is based on a study prepared by a third-party mining and geological consultant using data obtained from our drilling activities and other available geologic data. Our coal reserve estimates are periodically updated to reflect past coal production and other geologic and mining data. Acquisitions or sales of coal properties will also change these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam.
Our coal reserve estimates include reserves that can be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. Further, the economics of our reserves are based on market conditions including contracted pricing, market pricing and overall demand for our coal. Thus, the actual value at which we no longer consider our reserves to be economic varies depending on the length of time in which the specific market conditions are expected to last. We consider our reserves to be economic at a price in excess of our cash costs to mine the coal and our ongoing replacement capital. See Part I. “Item 1A. Risk Factors-Risks Related to Our Business-We face numerous uncertainties in estimating our economically recoverable coal reserves.”
Our mines are subject to private coal leases. Private coal leases normally have a stated term and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a minimum royalty, payable either at the time of execution of the lease or in periodic installments.
All of our recoverable coal reserves are assigned reserves as of December 31, 2015. All of our reserves are considered high sulfur coal, with average sulfur content ranging between 1.71% and 3.33% and high Btu coal, with Btu content ranging between 10,591 and 11,893 Btu per pound. The table below presents our estimated recoverable coal reserves at December 31, 2015.
(1)
In-Place Tons are on a dry basis.
(2)
Clean Recoverable Tons are based on mining recovery, average theoretical preparation plant yield, 94% preparation plant efficiency and product moisture.
Each of the mining companies leases the reserves they mine pursuant to a series of leases with related entities under common ownership, Natural Resources Partners, LP (“NRP”) and its subsidiaries, and other independent third parties in the normal course of business. The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The leases require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (generally five to ten years). Some of
these agreements also require overriding royalty and/or wheelage payments. Under the terms of some mineral reserve mining leases, we are to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and are responsible for the acquisition costs and the assets are to be titled to the lessor.
See Part I. “Item 1. Business” for additional discussion and a map of our major mining facilities and Part III. “Item 13.Certain Relationships and Related Transactions and Director Independence” for a summary of key terms of mineral reserve leases with affiliated parties.
Item 3.
Item 3. Legal Proceedings
See Part II. “Item 8. Financial Statements and Supplementary Data, Note 22-Contingencies” in the notes to our consolidated financial statements in this Annual Report on Form 10-K for a description of certain of our pending legal proceedings, which are incorporated herein by reference. 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 financial position, results of operation or cash flows. As of December 31, 2015, we have $2.3 million accrued, in the aggregate, for various litigation matters.
Item 4.
Item 4. Mine Safety Disclosures
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K for the year ended December 31, 2015.
PART II.
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
The common units representing limited partnership’ interests are listed on the New York Stock Exchange (“NYSE”) under the symbol “FELP” and began trading on June 18, 2014. On March 11, 2016, the closing market price for FELP common units was $2.32 per unit and there were 65,192,646 common units outstanding and 64,954,691 subordinated units outstanding. There were 3,192 record holders of our common units as of December 31, 2015.
The following table sets forth the range of high and low sales prices per common unit and the amount of cash distributions declared and paid with respect to each unit, from the June 18, 2014 initial listing date of our common units to December 31, 2015.
(a)
On October 29, 2015, we declared a quarterly distribution of $0.17 per unit payable on November 25, 2015 to common unitholders, while suspending the distribution on all subordinated units. Chris Cline and one additional common unitholder elected to forego the $0.17 per common unit distribution (and any arrearage rights related to the $0.17 paid distribution) on their collective 21.2 million common units.
All subordinated units are currently held by Murray Energy. The principal difference between our common units and subordinated units is that subordinated unitholders are not entitled to receive a distribution from operating surplus until the holders of common units have received the minimum quarterly distribution (“MQD”) from operating surplus. The MQD is $0.3375 per unit for such quarter plus any cumulative arrearages of previously unpaid MQDs from previous quarters. Subordinated unitholders are not entitled to receive arrearages. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, on the first business day after the Partnership has paid the MQD for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2017 and there are no outstanding arrearages on the common units. Notwithstanding the foregoing, the subordination period will end on the first business day after the Partnership has paid an aggregate amount of at least $2.025 per unit (150.0% of the MQD on an annualized basis) on the outstanding common and subordinated units and the Partnership has paid the related distribution on the incentive distribution rights, for any four-quarter period and there are no outstanding arrearages on the common units.
Cash Distribution Policy
Our partnership agreement provides that our general partner will make a determination as to whether a distribution will be made, but our partnership agreement does not require us to pay distributions at any time or at any amount. Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.
There is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our Revolving Credit Facility and 2021 Senior Notes, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our Revolving Credit Facility after giving effect to such distribution.
The decision by the board of directors of our general partner to reduce the distribution for the third quarter of 2015 and to suspend distributions to all unitholders for the fourth quarter of 2015 was a proactive effort to improve both long-term liquidity and our leverage in this difficult and unpredictable coal market. Also, the current default under our long-term debt arrangements prohibits distributions being made to our unitholders. Please read Part II. “Item 8. Financial Statements and Supplementary Data, Note 3 Debt Defaults and Liquidity” for additional discussion.
Our partnership agreement provides that our general partner make a determination whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or at any amount. To the extent the quarterly distribution is below the MQD, then common unitholders would accrue an arrearage equal to the shortfall amount to the MQD that would carry forward to future quarters and must be paid to common unitholders before any distributions from operating surplus to the subordinated unitholder is made.
Incentive Distribution Rights
Our general partner owns all of the incentive distribution rights (“IDRs”). IDRs represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the MQD and the target distribution levels (described below) have been achieved. Our general partner may transfer these IDRs separately from its general partner interest in us, subject to restrictions in our partnership agreement. Our general partner, as the IDR holder, will have the right, subsequent to the subordination period and subject to distributions exceeding the MQD by at least 150% for four consecutive quarters, to reset the target distribution levels and receive common units.
Percentage Allocation of Distributions from Operating Surplus
The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and the holder of our IDRs based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the IDR holders and the unitholders of any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Common Unit”. The percentage interests shown for our unitholders and the holders of the IDRs for the MQD are also applicable to quarterly distribution amounts that are less than the MQD.
The percentage interests set forth below assumes there are no arrearages on common units.
Equity Compensation Plans
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Part III. “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” contained herein.
Unregistered Sales of Equity Securities
None.
Use of Proceeds from Registered Securities
None.
Issuer Purchases of Equity Securities
None.
Item 6.
Item 6. Selected Financial Data
The following tables set forth the selected historical consolidated financial data of the Partnership for each of the last five years and should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. Please read Part II. “Item 8. Financial Statements and Supplementary Data, Note 1-Organization and Basis of Presentation” for a discussion on the basis of presentation for the consolidated financial statements of the Partnership.
(1)
For the year ended December 31, 2015, $13.5 million was recognized as other operating income related to a settlement with Murray Energy resolving litigation between the Partnership and Murray Energy. For the year ended December 31, 2012, $10.0 million was recognized as other operating income for a legal settlement with a customer on a coal sales contract.
(2)
Includes current portion of long-term debt and capital lease obligations. Total long-term debt and capital lease obligations does not include $143.5 million as of December 31, 2011 and $193.4 million as of December 31, 2015, 2014, 2013 and 2012 of certain sale-leaseback financing obligations that are characterized as financing arrangements due to the involvement of certain of our affiliates in mining the reserves and utilizing the equipment related to the leases.
(3)
Adjusted EBITDA is defined as net (loss) income attributable to controlling interests before interest, income taxes, depreciation, depletion, amortization and accretion. Adjusted EBITDA is also adjusted for equity-based compensation, unrealized gains or losses on derivatives, early debt extinguishment costs and for material nonrecurring or other items which may not reflect the trend of future results. 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), as an indicator of our performance or as an alternative to net cash provided by operating activities as a measure of liquidity. 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 disclosure of the differences between Adjusted EBITDA and U.S. GAAP results, including providing a reconciliation of Adjusted EBITDA to U.S. GAAP results, to enable users to perform their own analysis of our operating results. Below is a reconciliation between net income (loss) attributable to controlling interests and Adjusted EBITDA for the years ended December 31, 2015, 2014, 2013, 2012 and 2011.
(4)
Tons produced and tons sold do not include mines in development. Revenues and costs from mines in development are capitalized as mine development in our consolidated balances sheets.
(5)
Calculated as coal sales divided by tons sold.
(6)
Calculated as coal sales less transportation expense divided by tons sold.
(7)
Calculated as cost of coal produced (excluding depreciation, depletion and amortization) divided by produced tons sold.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis together with Part II. “Item 6. - Selected Financial Data” and our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements about our business, operations and industry that involve risks and uncertainties, such as statements regarding our plans, objectives, expectations and intentions. Our future results and financial condition may differ materially from those we currently anticipate as a result of the factors we describe under “Cautionary Statement Regarding Forward-Looking Statements,” Part I. Item 1A.“Risk Factors” and elsewhere in this Annual Report on Form 10-K. All references to produced tons, sold tons, or cash cost per ton sold refer to clean tons of coal.
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. 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 (“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 presented financial results include the combined financial position, results of operations and cash flow information of FELP and FELLC and its subsidiaries for all periods presented. In this Item 7, 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 currently a continuous miner operation. The Williamson and Hillsboro complexes are each operating with one longwall system and Sugar Camp is operating with two longwall mining systems, the second of which emerged from development on June 1, 2014. Mining operations at our Hillsboro complex have been idle since March 2015 due to a combustion event.
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 generally sell a majority of our coal to customers at delivery points other than our mines, including, but not limited to, river terminals on the Ohio and Mississippi Rivers and at two ports near New Orleans. In February 2015, Foresight Reserves contributed to us the Sitran terminal, a 25 million ton per year barge-loading river terminal on the Ohio River.
Debt Defaults
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 constituted a “change of control” under the Indenture governing our 2021 Senior Note 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. Because of the existence of “change of control” provisions and cross-default or cross-event of default provisions in our other debt agreements, the purchase and sale agreement between Foresight Reserves and Murray Energy also resulted, directly or indirectly, in events of default under each of our other long-term debt and capital lease obligations. As a result of the event of default triggered by the Delaware Court of Chancery memorandum opinion, we have not had access to borrowings or other extensions of credit under our Revolving Credit Facility. On February 16, 2016, we did not pay the $23.6 million of interest owed to holders of the 2021 Senior Notes and elected to exercise the 30-day grace period with respect to the interest payment due under the Indenture. If we do not make the interest payment by the end of the 30-day grace period, an additional event of default will exist under the Indenture. Furthermore, our auditor’s opinion in connection with our 2015 consolidated financial statements includes an explanatory paragraph regarding the uncertainty of the Partnership’s ability to continue as a “going concern” which will result in an additional default under the terms of the Credit Agreement as well as the 2021 Senior Notes, Foresight
Receivables LLC’s securitization agreement and the credit agreements governing certain equipment financings of certain of our other subsidiaries, because these agreements require delivery of financial statements without a going concern explanatory paragraph in the auditor opinion.
We are actively negotiating an out-of-court restructuring with certain holders of the 2021 Senior Notes (the “Consenting Noteholders”), who collectively beneficially own or manage in excess of 75% of the aggregate principal amount of the 2021 Senior Notes, and our other creditors. There can be no assurance that these efforts will result in any agreement. We have entered into forbearance agreements with the Consenting Noteholders to the 2021 Senior Notes and the lenders to our accounts receivable securitization program to forbear from exercising certain rights and remedies to which they may be entitled until March 15, 2016. We have not entered into forbearance agreements with the lenders under our Credit Agreement or the lenders under our other longwall equipment financing arrangements. Therefore, these lenders may exercise any remedies available to them at any time, including the acceleration of the indebtedness owed thereunder and exercising remedies with respect to our collateral securing such indebtedness.
We have engaged financial and legal advisors to advise us regarding potential alternatives to address the issues described above. There can be no assurance that any restructuring will be possible on acceptable terms, if at all. It may be difficult to come to an agreement that is acceptable to all of our creditors. Our failure to reach an agreement on the terms of a restructuring with our creditors or the failure to extend any forbearance agreement in connection with the related negotiations would have a material adverse effect on our liquidity, financial condition and results of operations, including requiring us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in order to implement a restructuring plan.
Given the difficult coal market conditions expected for 2016, we believe that there is a reasonable possibility that we may not be able to comply with our financial covenants during 2016. Failure to comply would be an additional default under the terms of the Credit Agreement and could result in the acceleration of all of our debt obligations. If we are unable to comply with our financial covenants, we would be required to seek one or more amendments or waivers from our lenders. We may not be able to do so on favorable terms, if at all. If we were unable to obtain any required amendments or waivers, our lenders would have the right to exercise remedies specified in the loan agreements, including accelerating the repayment of debt obligations and taking collection action against us. If such acceleration occurred, we currently have insufficient cash to pay the amounts owed and would be forced to seek alternative financing. However, we may not be able to obtain such financing on favorable terms, if at all.
For more information on the specific risks we face due to the above defaults, see Part I. “Item 1A. Risk Factors” of this report.
Factors That Affect Our Results
Coal Sales. Our average coal sales realization per ton in the near-term may decrease as we replace expiring favorably priced supply contracts with new supply contracts at contractually negotiated market prices. In recent years, domestic coal prices have weakened due to reduced demand from coal-fired plants and international prices have also declined significantly as a result of excess supply in the marketplace. We expect this low-price environment to continue throughout 2016 but we anticipate the lower coal prices will be partially offset by lower transportation costs due to an increased mix of domestic sales.
Demand for coal can increase due to unusually hot or cold weather as consumers use more electricity to air condition or heat their homes. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as blizzards or floods, can affect our ability to mine and ship our coal and our customers’ ability to take delivery of coal.
Cost of Coal Sales (Excluding Depreciation, Depletion and Amortization). Our cost of coal sales (excluding depreciation, depletion and amortization) includes, but is not limited to, labor and benefits, supplies, repairs, utilities, insurance, equipment rental, mine lease costs (royalties), property and subsidence costs, production taxes, belting, coal preparation and direct mine overhead. Each of these cost components has its own drivers, which can include the cost and availability of labor, changes in health care and insurance regulations and costs, the cost of consumable items or inputs in to our supplies, changes in regulations impacting our industry, and/or our staffing levels. In addition, geology can unfavorably impact our costs by requiring incremental roof control support and higher water handling and equipment maintenance expenses. Certain of our royalties are dependent directly upon the price at which we sell our coal and our cost to transport the coal to our customers, in addition to having minimum payment requirements.
Regulatory Environment. A variety of actions taken by regulatory agencies, including, but not limited to, climate change regulation, challenges to the issuance or renewal of our permits to operate and regulations governing the operations of our mines, could substantially increase compliance costs for us and our customers, reduce general demand for coal, or interrupt operations at one or more of our mining complexes.
Transportation. We generally sell our coal to customers at three distinct delivery points; either at our mines, at river terminals on the Ohio and Mississippi Rivers, or at two export terminals near New Orleans. Except for those sales that occur at our mine, we generally bear the transportation cost and risk to and through these terminals and we therefore do not report coal sales and transportation revenue separately in our consolidated statements of operations. Also, because we are responsible for the cost of
transporting our coal to these various delivery points, we also bear the risk that our transportation expense will increase over time. Where possible, we enter into long-term transportation and throughput agreements to secure capacity and price certainty. These agreements generally require throughput of minimum annual volumes. Failure to meet the minimum annual volume requirements can result in higher transportation costs to us on a per ton basis. The primary reason for making our minimum annual volume commitments was to secure long-term access to international markets. To the extent coal pricing to international markets does not substantially improve from current pricing levels, we expect our sales volumes to international markets to continue to decline thereby resulting in higher charges for shortfalls on minimum contractual throughput volume requirements.
Our transportation costs also correlate to the distance required to transport our coal to the buyers. As a result, the transport of our coal to domestic buyers has lower associated costs than the transport of our coal to international buyers. International sales incur higher transportation costs because the delivery requires us to transport coal first by rail to a seaborne export terminal and then load the coal onto the buyers’ ships. In certain circumstances, the cost of transporting our coal to international buyers can be twice the cost of transporting our coal to domestic buyers.
Selling, general and administrative. Selling, general and administrative expense consists of our general corporate overhead expenses, including, but not limited to, management and administrative labor, corporate occupancy expenses, office expenses, and professional fees. Prior to Murray Energy’s investment in the Partnership, all selling, general and administrative costs were variable based on actual costs incurred. 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 provides 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. We expect that the MSA will result in lower selling, general and administrative costs to the Partnership.
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.
Adjusted EBITDA is defined 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, unrealized gains or losses on derivatives, cumulative unrealized gains and losses from prior periods which were realized during the current period, early debt extinguishment costs, transition and reorganization costs and material nonrecurring or other items which may not reflect the trend of results. 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 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 Year Ended December 31, 2015 to Year Ended December 31, 2014
Coal Sales. The following table summarizes coal sales information during the years ended December 31, 2015 and 2014.
Coal sales decreased $130.2 million from the prior year due to a decline in coal sales realization per ton sold of $5.71. The decline in coal sales realization per ton was due to a decline in realization per ton on both our domestic and international sales driven by weak coal market conditions as well as a lower mix of international shipments. Increased domestic shipments during the current year offset the 1.3 million ton decrease in sales volumes to international markets from the prior year. The decline in tons sold to the international market resulted in a corresponding decline in transportation expense during the current year, therefore, the netback to mine realization per ton sold decreased to a lesser extent than the coal sales realization per ton sold.
Other Revenues. Other revenues of $5.7 million recorded for the year ended December 31, 2015 were primarily comprised of overriding royalty and lease revenues earned on the financing agreements entered into with affiliates of Murray Energy in April 2015.
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 years ended December 31, 2015 and 2014.
The increase in cost of coal produced during the current period was driven by a $2.87 per ton increase in cash cost per ton sold. The impact of the Hillsboro mine combustion event and increased costs at our Williamson and Sugar Camp operations primarily accounted for the increase in the cash cost per ton sold. The direct costs incurred during 2015 from our efforts to extinguish the fire at our Hillsboro mine was $20.2 million and the indirect impact of incurring salary and overhead costs at this mine without any corresponding production was $10.6 million. The higher cash cost per ton sold at our Williamson and Sugar Camp operations was driven by higher repairs, maintenance and longwall costs during the current year. Partially offsetting the higher costs discussed above was an $8.4 million favorable adjustment related to a refund from our utility provider during 2015.
Transportation. Transportation expense declined $49.4 million, or $2.21 per ton sold, from the prior year period due to a 19.4% decline in international sales as well as lower charges during the current year period for shortfalls against contractual minimum volumes as a result of a favorable contractual amendment to reduce the required minimum volumes through Convent Marine Terminal (“CMT”), the export terminal owned by an affiliate prior to September 2015.
Depreciation, Depletion and Amortization. The increase in depreciation, depletion and amortization expense of $25.6 million from the prior year was primarily due to the reduction of coal inventory during the current year and the second longwall at our Sugar Camp complex coming out of development in June 2014.
Long-lived Asset Impairments. During the years ended December 31, 2015 and 2014, we recorded an impairment charge of $11.6 million and $34.7 million, respectively, related to certain Hillsboro prepaid royalties for which we determined recoupment was improbable. Also, during the year ended December 31, 2015, we recorded a charge to write-off the remaining $1.0 million in deferred longwall costs related to Hillsboro’s current longwall panel, which is being abandoned as a result of the mine fire.
Transition and Reorganization Costs. Transition and reorganization costs were $21.4 million for the year ended December 31, 2015. As part of the Murray Energy transaction, Foresight 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 duplicate selling, general and administrative costs. The costs for the current period are primarily comprised of retention compensation to certain employees during the transition period and termination benefits to employees whose positions were replaced by Murray Energy employees under the MSA. Included in these retention costs were $5.9 million of retention and transition salaries paid by FELP, $10.0 million of retention and severance 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 $1.2 million of legal and various other one-time charges related to the Murray Energy transaction.
Gain on Commodity Derivative Contracts. We recorded a gain on our commodity derivative contracts of $45.7 million for the year ended December 31, 2015 compared to a $76.3 million gain for the year ended December 31, 2014. The API 2 coal index forward price curve declined significantly during both fiscal year 2015 and 2014, resulting in the large derivative gains. For the year ended December 31, 2015, we realized net gains of $61.2 million on commodity derivative contracts, of which $19.1 million were for coal derivative contracts settled prior to their contractual maturities.
Other Operating Income, Net. Other operating income, net increased $10.6 million from the prior year period primarily due to a $13.5 million favorable legal settlement with Murray Energy during the first quarter of 2015 (see Part II. “Item 8. Financial Statements - Note 22 Contingencies” of this Annual Report on Form 10-K).
Interest Expense, Net. Interest expense, net for the year ended December 31, 2015 increased $4.3 million from the prior year period due primarily to higher interest charges on our Macoupin sale-leaseback obligation and lower interest charges capitalized in 2015. For the year ended December 31, 2015, we capitalized $1.9 million in interest expense as compared to $5.2 million during the prior year. The decrease in capitalized interest was due to capital spending on the development of Sugar Camp’s second longwall mine along with the acquisition of an additional set of longwall shields during 2014.
Debt Restructuring Costs. The $3.9 million of debt restructuring costs incurred during the year ended December 31, 2015 represents legal and other advisor fees incurred as a result of the unfavorable ruling under the 2021 Senior Note bondholder lawsuit, including the negotiations with all of our creditors as a result of the default and the evaluation of our alternatives with respect to the restructuring of our indebtedness.
Adjusted EBITDA. Adjusted EBITDA declined $71.2 million from the prior year due to lower netback to mine realizations per ton sold and the higher cash cost per ton sold during the year ended December 31, 2015. Partially offsetting the above was $42.0 million of incremental realized gains on commodity derivative contracts and a favorable $13.5 million legal settlement with Murray Energy during 2015. The table below reconciles net (loss) income attributable to controlling interests to Adjusted EBITDA for the years ended December 31, 2015 and 2014.
(1)
Equity-based compensation of $4.3 million was recorded in transition and reorganization costs in the consolidated statement of operations for the year ended December 31, 2015.
For a discussion on Adjusted EBITDA, please read Part II. “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Key Metrics.”
Comparison of Year Ended December 31, 2014 to Year Ended December 31, 2013
Coal Sales. The following table summarizes coal sales information for the years ended December 31, 2014 and 2013.
Coal sales increased $152.0 million from the prior year due primarily to record sales volumes, which resulted in $178.0 million of additional coal sales. This increase was offset by a $1.17 per ton, or 2.3%, decrease in coal sales realization per ton. The increase in sales volumes was driven by higher production due to the start-up of the second longwall at our Sugar Camp complex in June 2014. The decline in coal sales realization compared to the prior year was due to a lower mix of international shipments, as well as a small decline in realization per ton on both our domestic and international sales.
Cost of Coal Produced (Excluding Depreciation, Depletion and Amortization). The following table summarizes cost of coal produced (excluding depreciation, depletion and amortization) information for years ended December 31, 2014 and 2013.
Cost of coal produced (excluding depreciation, depletion and amortization) increased $89.0 million, or 24.7% for the year ended December 31, 2014, primarily due to higher sales volumes, which resulted in $60.0 million in higher costs, as well as a $1.34 per ton increase in the cash cost per ton sold due to increased production costs at our Sugar Camp and Hillsboro operations. Our cash cost per ton sold at Sugar Camp was higher due to the introduction of additional continuous miner development units as well as higher roof control, water handling and other longwall-related costs. The increased costs at our Hillsboro mine were primarily a result of an underground fire which halted production for nearly a month and resulted in direct incremental costs of $2.6 million. Additionally, Hillsboro incurred higher subsidence, longwall and roof control costs during the year ended December 31, 2014.
Cost of Coal Purchased. Cost of coal purchased for the year ended December 31, 2014 was $18.2 million, compared to $2.2 million during the year ended December 31, 2013. We purchased coal from third parties during the current year in an effort to optimize margins between our domestic and export sales. The cost per ton to purchase coal is typically higher than our cost per ton to produce coal.
Transportation. Our cost of transportation for the year ended December 31, 2014 increased $24.5 million primarily due to higher sales volumes offset by a $0.55 per ton decrease in the average cost of transportation. The decline in transportation cost per ton was due to a lower percentage of our sales going to international markets during the year offset by higher charges for shortfalls on minimum contractual throughput volume requirements and an increase in the cash cost of transporting coal through CMT.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expense for the year ended December 31, 2014 increased $7.6 million, or 4.7%. The increase is primarily due to additional equipment added at our second longwall mining operation at our Sugar Camp complex, with the start-up of production on June 1, 2014, and $6.5 million of incremental amortization expense to accelerate amortization on certain Hillsboro development assets due to a change in the mine plan.
Long-lived Asset Impairments. During the year ended December 31, 2014, we recorded a $34.7 million impairment charge related to certain Hillsboro prepaid royalties which we determined recoupment was improbable based on the remaining period available for recoupment and current coal market conditions.
Selling, General and Administrative. Our selling, general and administrative expense of $33.7 million for the year ended December 31, 2014 increased $1.4 million due to $3.2 million in equity-based compensation expense recorded during the year offset by lower travel-related expenses in 2014.
Gain on Commodity Derivative Contracts. We recorded a gain on our coal derivative contracts of $76.3 million for the year ended December 31, 2014 compared to a $2.4 million gain for the year ended December 31, 2013. The increase was due to the significant decline in the API 2 coal index forward curve throughout 2014. Of the $76.3 million gain recorded, $57.1 million represented an unrealized gain and $19.2 million represented a realized gain.
Loss on Early Extinguishment of Debt. The $5.0 million loss on the early extinguishment of debt recognized during the year ended December 31, 2014 was due primarily to the write-off of $2.8 million of debt issuance costs and $1.9 million in unamortized debt discount as a result of the early repayment of $210.0 million of principal on our term loan. The $77.8 million loss recognized
during the year ended December 31, 2013 was associated with the early redemption of the 2017 Senior Notes and the write-off of certain unamortized debt issuance costs.
Interest Expense, Net. Interest expense, net for the year ended December 31, 2014 decreased $2.9 million due to a lower effective interest rate on our senior notes resulting from the August 2013 debt refinancing, lower interest expense on our sale-leaseback obligations, incremental interest capitalized in 2014, and lower amortization on debt issuance costs due to the August 2013 debt refinancing transactions. Offsetting the above decreases was incremental interest costs on the term loan issued in August 2013. For the year ended December 31, 2014, we capitalized $5.2 million in interest expense compared to $3.6 million during the prior year. The increase in capitalized interest was due to capital spending on the development of Sugar Camp’s second longwall mine along with the acquisition of an additional set of longwall shields during 2014.
Adjusted EBITDA. Adjusted EBITDA increased $46.1 million, or 12.7%, to $409.6 million for the year ended December 31, 2014 due primarily to higher sales volumes compared to the prior year, offset by lower coal sales realizations and higher production costs during 2014. The table below reconciles net income attributable to controlling interests to Adjusted EBITDA for the years ended December 31, 2014 and 2013.
For a discussion on Adjusted EBITDA, please read Part II. “Item 7. 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). Historically, our cash flows from operations and available capacity under our Revolving Credit Facility supported our cash requirements. The existence of an event of default has prohibited us access to borrowings or other extensions of credit under our Revolving Credit Facility. While management is focused on the preservation of our liquidity, our not having access to borrowings or other extensions of credit under our Revolving Credit Facility is having an adverse effect on our liquidity. As of December 31, 2015, we had $17.5 million of cash on hand and, as of February 29, 2016, we had approximately $21.9 million of cash on hand. We did not pay the $23.6 million of interest owed to holders of the 2021 Senior Notes on February 16, 2016 and elected to exercise the 30-day grace period with respect to the interest payment due under the Indenture. If we do not make the interest payment by the end of the 30-day grace period, an additional event of default will exist under the Indenture. Also, the loss we incurred during the current fiscal year has had a significant negative impact on the extent to which we currently comply with the financial debt covenants under our Credit Agreement, which are calculated on the rolling prior four quarters financial results. Our covenants required a consolidated interest coverage ratio of greater than 2.00x and a consolidated net senior secured leverage ratio of less than 2.75x as of December 31, 2015. As of December 31, 2015, our consolidated interest coverage ratio and consolidated net senior secured leverage ratio were 3.00x and 2.50x, respectively.
Given the difficult coal market conditions and the impact of the Hillsboro mine fire, we believe that there is a reasonable possibility that we may not be able to comply with our financial covenants during 2016. Failure to comply constitutes a default under the terms of the Credit Agreement and could result in the acceleration of all of our debt obligations. If we are unable to comply with our financial covenants, we would be required to seek one or more amendments or waivers from our lenders. We may not be able to do so on favorable terms, if at all. If we were unable to obtain any required amendments or waivers, our lenders would have the right to exercise remedies specified in the loan agreements, including accelerating the repayment of debt obligations and taking collection
action against us. If such acceleration occurred, we currently have insufficient cash to pay the amounts owed and would be forced to seek alternative financing. However, we may not be able to obtain such financing on favorable terms, if at all.
Since inception, we have made significant investments in capital expenditures to develop our four mining complexes and related transportation infrastructure which were funded with debt and cash generated from operations. 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. Development of the second longwall at our Sugar Camp complex was substantially completed with the start-up of the longwall on June 1, 2014. As a result, expansion capital expenditures declined significantly in 2015. 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 partnership agreement provides that our general partner make a determination as whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or at any amount. To the extent the quarterly distribution is below the minimum quarterly distribution (“MQD”) of $0.3375 per unit, as defined in the partnership agreement, then common unitholders would accrue an arrearage equal to the shortfall amount to the MQD that would carry forward to future quarters and must be paid to common unitholders before any distributions from operating surplus to the subordinated unitholder is made.
In February, May, and August of 2015, we paid quarterly cash distributions of $0.36, $0.37 and $0.38 per unit, respectively, to all limited partner unitholders. In November 2015, we paid a distribution of $0.17 per unit to common unitholders, while suspending the distribution to the subordinated unitholder. Chris Cline and one additional common unitholder elected to forego the $0.17 per common unit distribution on their collective 21.2 million common units. The decision by the board of directors of our general partner to reduce the distribution for the third quarter of 2015 and suspend distributions for the fourth quarter of 2015 was a proactive effort to improve both long-term liquidity and our leverage in this difficult and unpredictable coal market. Also, the current default under our long-term debt arrangements prohibits distributions being made to our unitholders.
The following is a summary of cash provided by or used in each of the indicated types of activities during the years ended December 31, 2015, 2014, and 2013.
Net cash provided by operating activities declined $40.4 million to $200.4 million for the year ended December 31, 2015 primarily due to lower net income, excluding non-cash items, during the current year. The impact of lower earnings during the current year was offset partially by favorable variances in working capital accounts from the prior year, including $40.0 million in cash proceeds from the settlement of derivative contracts during 2015 and a $41.8 million favorable variance in inventory as Hillsboro’s coal stockpiles have been depleted due to the mine fire and we cut coal production in December 2015 to preserve our liquidity and drawdown the excess coal inventory at our other mine sites.
Net cash used in investing activities was $138.8 million for the year ended December 31, 2015, compared to $224.6 million for the year ended December 31, 2014. The decline in net cash used in investing activities was primarily due to a $144.7 million reduction in capital expenditures as a result of the second longwall mine at our Sugar Camp complex emerging from development in June 2014 as well as the receipt of $19.1 million in proceeds during the current year from the settlement of certain outstanding coal derivative contracts. The cash receipts on these contracts were recorded as an investing activity given they were settled prior to the economically hedged sale transaction occurring. Offsetting the items above was a $75.0 million investment in the Murray Energy transport lease and overriding royalty agreements (see Part II. “Item 8. Financial Statements - Note 15. Related-Party Transactions” of this Annual Report on Form 10-K).
Net cash used in financing activities was $70.6 million for the year ended December 31, 2015, compared to $14.5 million used in financing activities for the year ended December 31, 2014. During the year ended December 31, 2015, we received net proceeds from our A/R securitization program of $41.0 million, increased our borrowings under our Revolving Credit Facility by $33.0 million and received proceeds from incremental term loan borrowings of $59.3 million. Also, during the current year period, we repaid $44.4 million under our longwall financing and capital lease arrangements, repaid $2.6 million in short-term insurance financing, paid $2.8 million in debt issuance costs and paid $152.4 million in distributions to our limited partners and noncontrolling interests. The increased borrowings during the current year period were due in part to the $75.0 million invested in the Murray Energy transport lease and overriding royalty agreements.
Net cash provided by operating activities increased $59.8 million from the year ended December 31, 2013 to $240.8 million for the year ended December 31, 2014. The increase in cash provided by operating activities was primarily due to the usage of $72.1 million of cash in the prior year for the early extinguishment of the 2017 Senior Notes and a $46.1 million increase in Adjusted EBITDA during 2014, offset partially by unfavorable net changes in our working capital accounts primarily due to higher inventory and receivables at December 31, 2014 due to our growth in sales and production from the prior year.
Net cash used in investing activities was $224.6 million for the year ended December 31, 2014, compared to $209.5 million for the year ended December 31, 2013. During 2014, we invested $229.7 million in property, plant, equipment and development. Significant capital expenditures were made in 2014 for the second longwall mine at our Sugar Camp Complex, including the purchase of an additional set of longwall shields, the construction of two water treatment plants at our Sugar Camp Complex, and refuse expansion at Hillsboro. We also settled certain outstanding coal derivative contracts during the year ended December 31, 2014 prior to the economically hedged sale transaction occurring; therefore, we recorded $7.3 million of cash proceeds as an investing activity.
Net cash used in financing activities was $14.5 million for the year ended December 31, 2014. During 2014, we received proceeds from our IPO of $322.7 million, net of $27.1 million in underwriter fees and other costs and fees associated with the IPO. Net proceeds from the IPO were used to repay $210.0 million of term loan principal and pay a $115.0 million special distribution to Foresight Reserves and a member of management. We also increased our borrowings under our Revolving Credit Facility by $60.5 million and incurred $24.3 million of incremental indebtedness related to purchase of a new set of longwall shields. In addition, during the year ended December 31, 2014, we repaid $35.0 million of principal under our longwall financing and capital lease arrangements, repaid an additional $1.1 million of term loan principal and paid $59.4 million in additional cash distributions ($49.2 million of which were quarterly distributions to limited partner unitholders subsequent to our IPO).
Long-Term Debt and Sale-Leaseback Financing Arrangements
2021 Senior Notes
On August 23, 2013, FELLC issued $600.0 million of 7.875% senior notes due August 15, 2021 (the “2021 Senior Notes”) and redeemed the outstanding 2017 senior notes. The 2021 Senior Notes are guaranteed on a senior unsecured basis by the Partnership and all of its domestic operating subsidiaries, other than Foresight Energy Finance Corporation, co-issuer of the notes. Interest is due semiannually on February 15 and August 15 of each year. The 2021 Senior Notes were issued at an initial discount of $4.3 million, which is being amortized using the effective interest method over the term of the notes.
As discussed above under “Debt Defaults”, 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 constituted a “change of control” under the Indenture governing 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 (see Note 3). On February 16, 2016, we did not pay the accrued interest owed to holders of the 2021 Senior Notes on such day and elected to exercise the 30-day grace period with respect to the interest payment due under the Indenture. The aggregate amount of the interest payment due is approximately $23.6 million. If we do not make the interest payment by the end of the 30-day grace period, an additional event of default will exist under the Indenture. We are actively negotiating an out-of-court restructuring with certain holders of the 2021 Senior Notes and our other creditors. For more information on the specific risks we face due to the above defaults, see Part I. “Item 1A. Risk Factors” of this report.
Revolving Credit Facility and Term Loan
In August 2010, FELLC entered into a $285.0 million revolving credit facility (the “Revolving Credit Facility”), which was amended in December 2011 to increase the capacity to $400.0 million. In August 2013, FELLC executed the second amendment to its credit agreement (the “Credit Agreement”) to increase the borrowing capacity under the Revolving Credit Facility from $400.0 million to $500.0 million and extend the maturity date to August 23, 2018. In May 2015, FELLC entered into the Incremental Amendment
No. 1 to the Credit Agreement which increased lender commitments under the Revolving Credit Facility by $50.0 million to $550.0 million. The Revolving Credit Facility is guaranteed by the Partnership and all of its domestic operating subsidiaries except Foresight Energy Finance Corporation. Interest on borrowings under the amended Revolving Credit Facility is based, at our election, on the London Interbank Offered Rate (“LIBOR”) plus an applicable margin or at a defined prime rate plus an applicable margin. The applicable margin is determined based on our consolidated net leverage ratio, as defined in the Credit Agreement. The weighted-average effective interest rate on borrowings under the Revolving Credit Facility as of December 31, 2015 was 3.6%. We are also required to pay a 0.5% commitment fee for unutilized capacity. At December 31, 2015, we had borrowings of $352.5 million outstanding under the Revolving Credit Facility and $6.5 million outstanding in letters of credit.
The Credit Agreement was also amended on August 23, 2013 to incorporate the issuance of a $450.0 million senior secured term loan (the “Term Loan”). The Term Loan required quarterly principal payments of approximately $1.1 million, which commenced on December 31, 2013. In June 2014, we repaid $210.0 million of principal with proceeds from the IPO, which was applied against the prospective scheduled quarterly principal payments. In May 2015, FELLC entered into the Incremental Amendment No. 1 to the Credit Agreement, which in addition to increasing our capacity under the Revolving Credit Facility, allowed for the borrowing of $60.0 million of additional Term Loan principal. No scheduled principal payments are due until the Term Loan matures on August 23, 2020, at which point all remaining unpaid principal is due. The Term Loan bears interest at LIBOR plus 4.5%, subject to a 1% LIBOR floor. As of December 31, 2015, the interest rate on the Term Loan was 5.5% and the principal balance outstanding, excluding the unamortized debt discount of $2.2 million, was $297.8 million.
Because of the existence of change of control provisions and cross-default provisions in the Credit Agreement, the unfavorable Delaware Court of Chancery opinion and consequently the default under the 2021 Senior Notes Indenture discussed above also resulted in events of default under the Credit Agreement. As a result, we have not had access to borrowings or other extensions of credit under our Revolving Credit Facility We have not entered into forbearance agreements with the lenders under our Credit Agreement therefore they may exercise any remedies available to them, including acceleration of the indebtedness owed to them and exercising remedies with respect to our collateral securing such indebtedness.
In January 2016, we received notice from the administrative agent to the Credit Agreement that prospective borrowings under the Credit Agreement would be subject to the default interest, as defined in the Credit Agreement, which will result in a 2% increase to the borrowing rate.
The Revolving Credit Facility is subject to customary debt covenants, including a consolidated interest coverage ratio and a consolidated net senior secured leverage ratio. As of December 31, 2015, our consolidated interest coverage ratio and consolidated net senior secured leverage ratio were 3.00x and 2.50x, respectively. Our covenants required a consolidated interest coverage ratio of greater than 2.00x and a consolidated net senior secured leverage ratio of less than 2.75x as of December 31, 2015. In addition, both the Credit Agreement and 2021 Senior Notes carry limitations on restricted payments, which may impact the timing and amount of cash distributions.
Trade A/R Securitization
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.
On January 27, 2016, we entered into a forbearance agreement in respect of our securitization program (as amended, the “Securitization Forbearance Agreement”), pursuant to which the agent under that facility and the lenders under the securitization program agreed to forbear from exercising certain rights and remedies to which they may be entitled. The Securitization Forbearance Agreement currently remains in effect through March 15, 2016, unless extended by the securitization lenders in their sole discretion. There can be no assurances that the securitization lenders will agree to any extension of the Securitization Forbearance Agreement or that if such forbearance agreement is terminated early or expires, that the securitization lenders will not pursue any and all remedies available to them. Also under the Forbearance Agreement, the receivables facility was amended to permanently reduce commitments to $50.0 million in total, and the Borrower may borrow up to an amount such that the aggregate amount outstanding plus any adjusted LC participation amount at such time does not exceed the least of (i) $41.0 million, (ii) the borrowing base at such time and (iii) an amount equal to 70% of the outstanding balance of the eligible receivables. Any extensions of credit under this agreement during the forbearance period are at the sole and absolute discretion of the lenders.
As of December 31, 2015, we had borrowings outstanding of $41.0 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. These capital lease obligations bear interest at 5.762% and 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 December 31, 2015, $45.7 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. These capital lease obligations bear interest ranging from 5.4% to 6.3%, and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2015, $17.1 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 17 equal semiannual payments through September 30, 2020. The outstanding balance as of December 31, 2015 was $51.6 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 17 equal semiannual payments through June 30, 2020. The outstanding balance as of December 31, 2015 was $50.4 million.
The guaranty agreements with the lender under both the 5.555% and 5.78% longwall financing arrangements contain certain financial covenants consistent with those of our Revolving Credit Facility.
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 December 31, 2015, the outstanding balance of the sale-leaseback financing arrangement was $143.5 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 December 31, 2015, the outstanding balance of the sale-leaseback financing arrangement was $50.0 million and the effective interest rate was 13.2%.
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 December 31, 2015, we had $6.5 million of letters of credit outstanding.
We had outstanding surety bonds with third parties of $79.2 million as of December 31, 2015 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.
Contractual Obligations
The following is a summary of our significant future contractual obligations as of December 31, 2015, by year:
(1)
Includes our Revolving Credit Facility, 2021 Senior Notes, Term Loan and the 5.555% and 5.78% longwall financing arrangements. The above table reflects the maturity as ‘Less than 1 year’ on all debt because the Partnership is in default under all of its debt arrangements and therefore the outstanding principal owed under these debt arrangements may be accelerated by the lenders. In addition, no interest expense is incorporated into the future contractual obligation amounts given the uncertainty surrounding the timing of principal repayment and the appropriate applicable interest rates given the default status on these instruments.
(2)
Represents the minimum annual payments required under our Macoupin and Sugar Camp sale-leaseback financing arrangements.
(3)
The above table reflects the maturity as ‘Less than 1 year’ on all debt because the Partnership is in default under all of its debt arrangements and therefore the outstanding principal owed under these debt arrangements may be accelerated by the lenders. In addition, no interest expense is incorporated into the future contractual obligation amounts given the uncertainty surrounding the timing of principal repayment and the appropriate applicable interest rates given the default status on these instruments.
(4)
Principally includes our various take-or-pay arrangements associated with rail and terminal facility commitments for the delivery of coal.
(5)
Comprised of the future minimum cash payments due under our various coal reserve lease and royalty obligations.
(6)
We have open purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements are not material and typically allow for cancellation or return without penalty. The commitments in the table above relate only to committed capital purchases as of December 31, 2015. The contractual table above does not include our obligations under the MSA with Murray Energy, please read Part II. “Item 8. Financial Statements and Supplementary Data, Note 15-Related-Party Transactions” for a discussion on the terms of this contractual arrangement.
(7)
The contractual obligation table does not include asset retirement obligations. Asset retirement obligations result primarily from statutory, rather than contractual obligations and the ultimate timing and amount of the obligations are an estimate. As of December 31, 2015, we have $43.3 million recorded in our consolidated balance sheet for asset retirement obligations.
We lease certain surface rights, mineral reserves, mining, transportation, and other equipment under various lease agreements with related entities under common ownership, NRP and its subsidiaries, and other independent third parties in the normal course of business. The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The leases require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (generally five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Under the terms of some mineral reserve mining leases, we are to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and are responsible for the acquisition costs and the assets are to be titled to the lessor. Transportation throughput agreements generally require a per ton fee amount for coal transported and contain certain escalation clauses and/or renegotiation clauses. For certain transportation assets, we are responsible for operations, repairs, and maintenance and for keeping transportation facilities in good working order. Surface rights, mining, and other equipment leases require monthly payments based upon the specified agreements. Certain of these leases provide options for the purchase of the property at various times during the life of the lease, generally at its then fair market value. We also lease rail cars, certain office space and equipment under leases with varying expiration dates.
See Part III. “Item 13. Certain Relationships and Related Transactions and Director Independence” for a discussion of the above leases and agreement with affiliated parties.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with U.S. GAAP, which requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. We base these estimates on historical experience and on various other assumptions that we consider reasonable under the circumstances. On an ongoing basis we evaluate our estimates. Actual results may differ from these estimates. Of these significant accounting policies, we believe the following may involve a higher degree of judgment or complexity.
Sale-Leaseback Financing Arrangements. In the first quarter of 2009, Macoupin sold certain of its coal reserves to WPP, and leased them back. The gross proceeds from this transaction were $143.5 million, and were used for capital expenditures relating to the rehabilitation of the Macoupin mine and for other capital items. Similarly, in the first quarter of 2012, Sugar Camp sold certain rail facilities to HOD, and leased them back. The gross proceeds from this transaction were $50.0 million, and were used for capital expenditures, to pay down our revolving credit facility and for general corporate purposes. In both transactions, because we had continuing involvement in the assets sold, the transactions were treated as sale-leaseback financing arrangements.
Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in future expected amounts and timing of payments based on the mine plans and also, for the Macoupin sale-leaseback only, the future expected sales price of its coal. Payments are applied first against accrued interest and any excess is then applied against the outstanding principal. Revisions to the mine plans, which occur periodically as changes are made to estimates of the quantity and the timing of tons to be mined, will impact the effective interest rate. We account for such changes by adjusting in the current period, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied). The implied effective interest rate was 13.9% as of December 31, 2015 and 2014 on the Macoupin sale-leaseback financing arrangement and 13.2% and 13.9% for the Sugar Camp sale-leaseback financing arrangement as of December 31, 2015 and 2014, respectively. If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant.
Prepaid Royalties. Prepaid royalties consist of recoupable minimum royalty payments under various lease agreements. As of December 31, 2015 and 2014, we had recorded on the consolidated balance sheets $75.7 million and $68.3 million, respectively, of prepaid royalties, net of reserves. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, assessing mine production plans, sales commitments, current and forecasted future coal market conditions, and remaining years available for recoupment. The contractual recoupment periods are generally five to ten years from the payment date. During the years ended December 31, 2015 and 2014, we recorded an impairment charge of $11.6 million and $34.7 million, respectively, to reserve against contractual prepaid royalties between Hillsboro and WPP. We recorded the impairment charge given that recoupment of certain prior minimum royalty payments was determined improbable given the remaining time available under the five-year recoupment periods, the current idling of the mine as a result of the mine fire, and our expected demand for Hillsboro coal based on current and forecasted near-term market conditions, which are impacted by natural gas prices, weather, economic conditions and the regulatory environment.
Asset Retirement Obligations. Our asset retirement obligations (“ARO”) consist of estimated spending related to reclaiming surface land and support facilities at our mines in accordance with federal and state reclamation laws as required by each mining permit. Obligations are incurred at the time mine development commences or when construction begins in the case of support facilities, refuse areas and slurry ponds.
The liability is determined using discounted cash flow techniques and is reduced to its present value at the end of each period. We estimate our ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash cost for a third party to perform the required work. Spending estimates are escalated for inflation, and market risk premium, and then discounted at the credit-adjusted, risk-free rate. The credit-adjusted, risk-free interest rates were 9.8%, 6.6%, and 8.8% at December 31, 2015, 2014, and 2013, respectively. We record an ARO asset associated with the discounted liability for final reclamation and mine closure. Accretion on the ARO begins at the time the liability is incurred. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying amount of the related long-lived asset. The ARO asset for equipment, structures, buildings, and mine development is amortized over its expected life on a units-of-production basis. The ARO liability is then accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in
estimated costs, or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate.
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing of reclamation activities and revisions to cost estimates, the occurrence of new liabilities from additional disturbances and productivity assumptions. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled. At December 31, 2015, our consolidated balance sheet reflected asset retirement obligations of $43.3 million, including amounts classified as a current liability. We estimate the aggregate undiscounted cost of final mine closures, at 2015 costs, to be approximately $85.6 million as of December 31, 2015.
Variable Interest Entities (“VIEs”). We employ contractors to provide labor for our mines and coal processing facilities. In accordance with US GAAP, our consolidated financial statements include entities considered variable interest entities (“VIEs”) for which we are the primary beneficiary. These entities are deemed to be our affiliates and generally own no equipment, real property or other intangible assets and each holds a contract, and in some instances an operator assignment, to provide contract labor services solely to FELP subsidiaries.
VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses, or (c) right to receive expected residual returns. VIEs must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIEs economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.
To determine a VIE’s primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE’s economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, and must therefore consolidate the entity, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests held by us and other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers, to clarify the principles used to recognize revenue. The initial effective date for ASU 2014-09 was scheduled for annual and interim periods beginning after December 15, 2016. In July 2015, the FASB delayed the effective date until annual and interim periods beginning after December 31, 2017. We are in the process of evaluating the effects, if any, the adoption of this guidance will have on our consolidated financial statements.
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which requires management of the entity to evaluate whether there is substantial doubt about the entity’s ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, with early adoption permitted. The impact of this standard will be dependent on the Partnership's financial condition and expected operating outlook at the time of adoption.
In February 2015, the FASB issued 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. ASU 2015-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented. Early adoption is permitted. We are currently evaluating the effect of adopting ASU 2015-02.
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. ASU 2015-06 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied
retrospectively to each period presented. At this time, we do not expect that ASU 2015-06 will have a significant effect on our 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, effective for fiscal years and interim periods beginning after December 15, 2015, that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Retrospective application is required and early adoption is permitted. The adoption of ASU 2015-03 only impacts balance sheet classification; therefore, it will not have a significant effect on our consolidated financial statements or related disclosures.
In July 2015, the FASB issued ASU 2015-11, Inventory: Simplifying the Measurement of Inventory, which simplifies the measurement of inventories valued under most methods. Under this new guidance, inventories valued under these methods would be valued at the lower of cost and net realizable value, with net realizable value defined as the estimated selling price less reasonable costs to sell the inventory. The new guidance is effective prospectively for fiscal periods starting after December 15, 2016 and early adoption is permitted. We do not expect the adoption of ASU 2015-11 to have a significant effect on our consolidated financial statements or related disclosures.
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.
Item 7A.
Item 7A. 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, interest rate risk and credit 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 December 31, 2015, we had the following contracted minimum sales commitments for the years ending December 31, 2016 and 2017:
As of December 31, 2015, we have 1.1 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 $4.9 million change in the fair value of these 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 December 31, 2015, we have 1.0 million gallons of diesel fuel hedged for 2016. A 10% change in the price of diesel fuel would result in a $0.3 million change in the fair value of these derivative contracts.
Interest Rate Risk
We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2015, of our $1,450.4 million in long-term debt and capital lease obligations outstanding, $691.3 million of outstanding borrowings have interest rates that fluctuate based on changes in market interest rates. A one percentage point increase in the interest rates related to variable interest borrowings would result in an annualized increase in interest expense of approximately $5.2 million.
Credit Risk
We have credit risk associated with our customers and counterparties in our coal sales agreements, financing arrangements and commodity hedge contracts, including with our affiliates. We have procedures in place to assist in determining the creditworthiness and credit limits for such customers and counterparties. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established. At December 31, 2015, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.
Item 8.
Item 8. Financial Statements and Supplementary Data
EY Audit Opinion
Report of Independent Registered Public Accounting Firm
The Board of Directors of Foresight Energy GP LLC and
Unitholders of Foresight Energy LP
We have audited the accompanying consolidated balance sheets of Foresight Energy LP (the “Partnership”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, partners’ capital (deficit), and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Foresight Energy LP at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
The accompanying consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Partnership is in default of certain provisions of its long-term debt and capital lease obligations, resulting in a working capital deficit as of December 31, 2015. These conditions raise substantial doubt about the Partnership’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Foresight Energy LP’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 15, 2016, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
St. Louis, Missouri
March 15, 2016
Foresight Energy LP
Consolidated Balance Sheets
Foresight Energy LP
Consolidated Statements of Operations
Foresight Energy LP
Consolidated Statements of Partners’ Capital (Deficit)
Foresight Energy LP
Consolidated Statements of Cash Flows
Foresight Energy LP
Notes to Consolidated Financial Statements
1. Organization 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 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.
During the first quarter of 2015 (the “Contribution Date”), Foresight Reserves and a member of management contributed (through their incentive distribution rights) their 100% equity interest in Sitran LLC (“Sitran”), Adena Resources LLC (“Adena”), Hillsboro Transport LLC (“Hillsboro Transport”) and Akin Energy LLC (“Akin Energy”) to FELP for no consideration (collectively, the “Contributed Companies”) (see Note 18). Because Sitran, Akin Energy and FELP were under common control, FELP’s historical results prior to the Contribution Date have been recast to combine the financial position and results of operations of Sitran and Akin Energy. Hillsboro Transport and Adena were consolidated as variable interest entities (“VIEs”) prior to the Contribution Date (see Note 16); therefore, the contribution did not result in a change in reporting entity. The equity values of Sitran and Akin Energy prior to the Contribution Date are included in predecessor equity in the statement of partners’ capital (deficit), and on the Contribution Date, the net book values of these entities were reclassified from predecessor equity to limited partners’ capital. Similarly, the equity values of Hillsboro Transport and Adena were reclassified from noncontrolling interests to limited partners’ capital on the Contribution Date. The controlling interest net income of the Contributed Companies prior to the Contribution Date and the controlling interest net income of FELLC prior to the IPO are included in net income attributable to predecessor equity in the consolidated statements of operations.
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 (see Note 15).
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, the Contributed Companies, and FELLC and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated. The information presented in this Annual Report on Form 10-K contains, for all periods presented, the combined consolidated financial results of Foresight Energy LP, the Contributed Companies, FELLC, and VIEs for which FELLC or its subsidiaries are the primary beneficiary.
The Partnership operates in a single reportable segment and currently operates 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 June 1, 2014, the second longwall system at our Sugar Camp complex transitioned from the development stage to the production stage and from that date forward was recognized in our results of operations. 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, the Contributed Companies, and FELP and its consolidated subsidiaries, are eliminated in consolidation.
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and loss during the reporting period. Actual results could differ from those estimates.
Revenue Recognition
Once mines are in production, coal sales include sales to customers of coal produced and, from time to time, the re-sale of coal purchased from third parties or to one of our affiliates. The Partnership recognizes sales at the time legal title and risk of loss pass to the customer at contracted amounts that are fixed or determinable. 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. Quality and weight adjustments are recorded as necessary based on contract specifications as a reduction or increase to coal sales and accounts receivable.
Transportation Expenses
Costs related to the handling and transporting of coal to the point of sale are included in coal inventory in the consolidated balance sheets. Upon the recognition of the sale, these costs are included in transportation expenses in the consolidated statements of operations.
Cash and Cash Equivalents
The Partnership considers cash deposits with original maturities of less than three months to be cash and cash equivalents. Cash and cash equivalents are stated at cost, which approximates fair value.
Allowance for Doubtful Accounts
The Partnership evaluates the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables and disputed amounts. Historically, credit losses have been insignificant. At December 31, 2015 and 2014, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.
Inventories
Inventories are valued at the lower of average cost or market. Parts and supplies inventory consists of spare parts for equipment and supplies used in the mining process. Raw coal represents coal stockpiles that require processing through a preparation plant prior to shipment to a customer. Clean coal represents coal stockpiles that will be sold in its current condition. Coal inventory costs include labor, equipment costs, supplies, transportation costs incurred prior to the transfer of title to customers, depreciation, depletion, amortization and direct mine operating overhead.
Deferred Longwall Costs
The Partnership defers the direct costs associated with longwall moves, including longwall set-up costs, supplies and refurbishment costs of longwall equipment. These deferred costs are expensed on a units-of-production basis into cost of coal produced (excluding depreciation, amortization and depreciation) over the panel benefited by these costs, which has historically approximated one year.
Prepaid Royalties
Prepaid royalties consist of recoupable minimum royalty payments due under various lease agreements entered into by the Partnership. Prepaid royalties expected to be recouped within one year are classified as current assets in the Partnership’s consolidated balance sheets. The Partnership continually evaluates its ability to recoup prepaid royalty balances, which includes, among other factors, assessing mine production plans, sales commitments, future coal market conditions and remaining years available for recoupment. The contractual recoupment periods on the prepaid royalty balances generally range from five to ten years from the date the minimum royalty was paid.
Property, Plant, Equipment and Development, Net
Property, plant and equipment are recorded at cost. Costs that extend the useful lives or increase the productivity of the assets are capitalized, while normal repairs and maintenance that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Asset retirement obligations for the various assets have been recorded as components of the specific assets to which they relate. Interest costs applicable to major additions are capitalized during the construction period. Interest costs capitalized into property, plant, equipment and development, net for the years ended December 31, 2015, 2014, and 2013, were $1.9 million, $5.2 million, and $3.6 million, respectively. Property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Machinery and equipment under capital lease agreements are amortized using the straight-line method over the useful lives of the assets given that, in each case, ownership transfers at the end of the lease terms. The cost of acquiring land (subsidence) rights and mineral rights is amortized using the units-of-production method over the mineral reserves
benefited by the costs. The estimated useful lives of machinery and equipment, buildings and structures and other categories are as follows:
Machinery and equipment
3-20 years
Buildings and structures
3-40 years
Other
3-20 years
Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the mineral reserves benefited by the development. Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred. During the development phase, the Partnership establishes access to the mineral reserves and makes other preparations for commercial production. Development costs principally include clearing land, building roads, sinking shafts, driving slopes and developing refuse areas, ventilation and transportation passageways at the mines. Development costs also include the build-out of the Partnership’s transportation infrastructure. Costs incurred during the development phase are capitalized and proceeds from the incidental sale of coal during development are recorded as a reduction of the related mine development costs. For reporting in the statements of cash flows, cash expended in the investment in mining rights, equipment and development during the development phase is reported net of capitalized coal sales.
Impairment of Depreciable Assets
The Partnership records impairment losses on depreciable assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded on depreciable assets during the years ended December 31, 2015, 2014 and 2013.
Debt Issuance Costs
The Partnership capitalizes costs incurred in connection with the issuance of debt and the establishment of credit facilities and capital leasing arrangements. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the effective interest method. Amortization expense of $6.0 million, $6.1 million and $7.7 million is included in interest expense for the years ended December 31, 2015, 2014, and 2013, respectively. As of December 31, 2015 and 2014, unamortized debt issuance costs were $21.4 million and $24.6 million, respectively. As of December 31, 2015, all unamortized debt issuance costs were recorded as current assets as a result of all long-term debt being in default and therefore presented as a current liability in the consolidated balance sheet (see Note 3).
Sale-Leaseback Financing Arrangements
The Partnership is party to two arrangements in which it sold assets to an affiliate and immediately leased those assets back from the affiliates. Because the Partnership has continued involvement in the assets sold, the proceeds received on the sale of the assets were recorded as long-term financing arrangements (liabilities) in our consolidated balance sheets. Under both of these arrangements, the Partnership pays a fixed minimum payment, as well as contingent payments for volumes in excess of the contractual minimum payments. Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in expected amounts and timing of future payments based on the mine plans. Payments are first applied against accrued interest and any excess is applied against the outstanding principal. The Partnership accounts for such changes by adjusting in the current period, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied). If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant.
Asset Retirement Obligations
The Partnership’s asset retirement obligations (“ARO”) consist primarily of spending estimates related to reclaiming surface land, refuse areas, slurry ponds and support facilities at the Partnership’s underground mines in accordance with federal and state reclamation laws as required by each mining permit. These obligations are typically incurred at the time development of a mine commences for underground mines or when construction begins for support facilities, refuse areas and slurry ponds. The Partnership estimates its ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and a market risk premium and then discounted at a credit-adjusted, risk-free rate. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value and the capitalized cost is amortized over the useful life of the related asset on a units-of-production basis. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate.
Derivative Financial Instruments
The Partnership utilizes derivative financial instruments principally to manage exposures to coal price and, to a lesser extent, diesel fuel prices. The Partnership records the fair value of each instrument as either an asset or liability in the consolidated balance sheets and the change in fair value of each instrument is recorded in the consolidated statements of operations.
Coal contracts provide for the physical purchase or sale of coal in quantities expected to be used or sold by the Partnership over a reasonable period in the normal course of business, and are not recognized on the consolidated balance sheets.
Fair Value
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs. A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value.
The hierarchy, as defined below, gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs.
Level 1 is defined as observable inputs, such as quoted prices in active markets for identical assets.
Level 2 is defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 is defined as unobservable inputs in which little or no market data exists, therefore, requiring an entity to develop its own assumptions.
The carrying value of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments.
Variable Interest Entities (VIEs)
VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. VIEs must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIEs economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.
To determine a VIE's primary beneficiary, the Partnership performs a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether the Partnership is the primary beneficiary of a VIE, the Partnership performs a qualitative analysis that considers the design of the VIE, the nature of the Partnership’s involvement and the variable interests held by other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary. The income attributable to consolidated variable interest entities is recorded as net income attributable to noncontrolling interests in the consolidated statements of operations.
Income Taxes
We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. While Section 7704(a) of the tax code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the mining, transportation and marketing of minerals and natural resources, such as coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.
We currently meet the Qualifying Income Exception and expect to continue to qualify prospectively for this exception. As such, each of our unitholders will take into account their respective share of our items of income, gain, loss and deduction in computing their federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment basis depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting methods, which are partially dependent upon the unitholder’s tax position, differs from the accounting methods followed in our consolidated financial statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership is not available to us.
Our tax counsel provided an opinion at the time of the IPO that FELP will be treated as a partnership. However, as is customary, no ruling has been or will be requested from the Internal Revenue Service (“IRS”) regarding our classification as a partnership for federal income tax purposes.
FELLC, its subsidiaries and controlled entities were established as limited liability companies, and thus for federal and, if applicable, state and local income tax purposes, are treated as pass-through entities. Therefore, no provision for income taxes was included in the consolidated financial statements.
Supplemental Cash Flow Information
The following is supplemental information to the statements of cash flows:
Newly Adopted Accounting Standards
In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 changes the requirements for reporting discontinued operations by updating the criteria for determining discontinued operations and modifies the disclosure requirements of both discontinued operations and certain other disposals not defined as discontinued operations. ASU 2014-08 was adopted during the first quarter of 2015 and did not have an effect on our consolidated financial statements.
New Accounting Standards Issued and Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, to clarify the principles used to recognize revenue. The initial effective date for ASU 2014-09 was scheduled for annual and interim periods beginning after December 15, 2016. In July 2015, the FASB delayed the effective date until annual and interim periods beginning after December 31, 2017. We are in the process of evaluating the effects, if any, the adoption of this guidance will have on our consolidated financial statements.
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which requires management of the entity to evaluate whether there is substantial doubt about the entity’s ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, with early adoption
permitted. The impact of this standard will be dependent on the Partnership's financial condition and expected operating outlook at the time of adoption.
In February 2015, the FASB issued 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. ASU 2015-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented. Early adoption is permitted. We are currently evaluating the effect of adopting ASU 2015-02.
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. ASU 2015-06 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented. At this time, we do not expect that ASU 2015-06 will have a significant effect on our 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, effective for fiscal years and interim periods beginning after December 15, 2015, that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Retrospective application is required and early adoption is permitted. The adoption of ASU 2015-03 only impacts balance sheet classification; therefore, it will not have a significant effect on our consolidated financial statements or related disclosures.
In July 2015, the FASB issued ASU 2015-11, Inventory: Simplifying the Measurement of Inventory, which simplifies the measurement of inventories valued under most methods. Under this new guidance, inventories valued under these methods would be valued at the lower of cost and net realizable value, with net realizable value defined as the estimated selling price less reasonable costs to sell the inventory. The new guidance is effective prospectively for fiscal periods starting after December 15, 2016 and early adoption is permitted. We do not expect the adoption of ASU 2015-11 to have a significant effect on our consolidated financial statements or related disclosures.
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.
3. Debt Defaults and Liquidity
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 15) 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.
Because of the existence of “change of control” provisions and cross-default or cross-event of default provisions in our other debt agreements, the purchase and sale agreement between Foresight Reserves and Murray Energy also resulted, directly or indirectly, in events of default under Foresight Energy LLC’s credit agreement governing its senior secured credit facilities (the “Credit Agreement”), Foresight Receivables LLC’s receivables securitization program and certain other financing arrangements, including our longwall financing arrangements. The existence of an event of default has prohibited us access to borrowings or other extensions of credit under our Revolving Credit Facility.
On December 18, 2015, we entered into a forbearance agreement (as amended, the “Notes Forbearance Agreement”) with Wilmington Savings Fund Society, FSB, as successor indenture trustee (the “Trustee”), and the Consenting Noteholders (defined below). Under the Notes Forbearance Agreement, the Consenting Noteholders and the Trustee agreed to forbear from exercising certain rights and
remedies to which they may be entitled in respect of the 2021 Senior Notes or under the Indenture. The Notes Forbearance Agreement currently remains in effect through March 15, 2016, unless extended by the Consenting Noteholders in their sole discretion. There can be no assurances that the Consenting Noteholders will agree to any extension of the Notes Forbearance Agreement or that if such forbearance agreement is terminated early or otherwise expires or terminates pursuant to its terms, that the requisite noteholders under the Indenture will not pursue any and all remedies available to them under the Indenture or otherwise.
On January 27, 2016, we entered into a forbearance agreement in respect of our securitization program (as amended, the “Securitization Forbearance Agreement”), pursuant to which the agent under that facility and the lenders under the securitization program agreed to forbear from exercising certain rights and remedies to which they may be entitled. The Securitization Forbearance Agreement currently remains in effect through March 15, 2016, unless extended by the securitization lenders in their sole discretion. There can be no assurances that the securitization lenders will agree to any extension of the Securitization Forbearance Agreement or that if such forbearance agreement is terminated early or expires, that the securitization lenders will not pursue any and all remedies available to them. Also under the Securitization Forbearance Agreement, the receivables facility was amended to permanently reduce commitments to $50.0 million in total, and we may borrow up to an amount such that the aggregate amount outstanding plus any adjusted LC participation amount at such time does not exceed the least of (i) $41.0 million, (ii) the borrowing base at such time and (iii) an amount equal to 70% of the outstanding balance of the eligible receivables. Any extensions of credit by the lenders during the forbearance period are in their sole and absolute discretion.
We have not entered into forbearance agreements with the lenders under our Credit Agreement or the lenders under our equipment financing arrangements. Therefore, the lenders under the Credit Agreement and our equipment financing arrangements may exercise any remedies available to them at any time. The remedies available to the lenders under the Credit Agreement include acceleration of the indebtedness owed thereunder and exercising remedies with respect to our collateral securing such indebtedness. There can be no assurances that our creditors will not accelerate the indebtedness under their respective facilities or exercise any rights or remedies to which they are entitled.
On February 16, 2016, we did not pay the accrued interest owed to holders of the 2021 Senior Notes on such day and elected to exercise the 30-day grace period with respect to the interest payment due under the Indenture. The aggregate amount of the interest payment due is $23.6 million. If we do not make the interest payment by the end of the 30-day grace period, an additional event of default will exist under the Indenture. In addition, an event of default will exist under the Credit Agreement, Foresight Receivables LLC’s securitization agreement and the credit agreements governing certain equipment financings of certain of our other subsidiaries.
Our auditor’s opinion in connection with our 2015 consolidated financial statements includes a “going concern” uncertainty explanatory paragraph which will result in an additional default under the terms of the Credit Agreement as well as the 2021 Senior Notes, Foresight Receivables LLC’s securitization agreement and the credit agreements governing certain equipment financings of certain of our other subsidiaries, because these agreements require delivery of financial statements without a “going concern” explanatory paragraph in the auditor opinion.
Based on the facts and circumstances discussed above, we classified all of this debt as current liabilities in our consolidated balance sheet as of December 31, 2015, which has created a substantial working capital deficiency.
We are actively negotiating an out-of-court restructuring with certain holders of the 2021 Senior Notes (the “Consenting Noteholders”), who collectively beneficially own or manage in excess of 75% of the aggregate principal amount of the 2021 Senior Notes, and our other creditors. There can be no assurance that these efforts will result in any agreement.
We have engaged financial and legal advisors to advise us regarding potential alternatives to address the issues described above. We cannot assure you that any restructuring will be possible on acceptable terms, if at all. It may be difficult to come to an agreement that is acceptable to all of our creditors. Our failure to reach an agreement on the terms of a restructuring with our creditors or the failure to extend any forbearance agreement in connection with the related negotiations would have a material adverse effect on our liquidity, financial condition and results of operations. During the year ended December 31, 2015, we incurred legal and financial advisors fees of $3.9 million related to the above issues which have been recorded as debt restructuring fees in the consolidated statement of operations. We expect financial and legal advisor fees to continue to be substantial until such time as the above issues are remedied, if at all.
If an agreement on the terms of an out-of-court restructuring is not reached, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in order to implement a restructuring, or our creditors could force us into an involuntary bankruptcy or liquidation. If a plan of reorganization is implemented in a bankruptcy proceeding, it is likely that holders of claims and interests with respect to, or rights to acquire our equity securities, would likely be entitled to little or no recovery, and those claims and interests would likely be canceled for little or no consideration. If that were to occur, we anticipate that all, or substantially all, of the value of all investments in our partnership units will be lost and that our unitholders would lose all or
substantially all of their investment. It is also likely that our other stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.
Our primary cash requirements include, but are not limited to, working capital needs, capital expenditures, and debt service costs (interest and principal). Historically, our cash flows from operations and available capacity under our Revolving Credit Facility supported our cash requirements. However, our not having access to borrowings or other extensions of credit under our Revolving Credit Facility is having an adverse effect on our liquidity. Also, the loss incurred by the Partnership during the current fiscal year has had a significant negative impact on the extent to which we currently comply with the financial debt covenants under our Credit Agreement, which are calculated on the rolling prior four quarters financial results. Our Credit Agreement requires that we maintain a consolidated interest coverage ratio of greater than 2.00x and a consolidated net senior secured leverage ratio of less than 2.75x.
Given the difficult coal market conditions expected for 2016, we believe that there is a reasonable possibility that we may not be able to comply with our financial covenants during 2016. Failure to comply with these financial covenants would be an additional default under the terms of the Credit Agreement and could result in the acceleration of all of our debt obligations. If we are unable to comply with our financial covenants, we would be required to seek one or more amendments or waivers from our lenders. We may not be able to do so on favorable terms, if at all. If we were unable to obtain any required amendments or waivers, our lenders would have the right to exercise remedies specified in the loan agreements, including accelerating the repayment of debt obligations and taking collection action against us. If such acceleration occurred, we currently have insufficient cash to pay the amounts owed and would be forced to seek alternative financing. However, we may not be able to obtain such financing on favorable terms, if at all.
The conditions and circumstances above raise substantial doubt about the Partnership’s ability to continue as a going concern, including the current default under all of the Partnership’s long-term debt and capital lease obligations as well as the Partnership’s prospective ability to comply with its existing financial debt covenants. The financial statements do not include any adjustments relating to the recoverability and classification of assets carrying amounts or the amount of and classification of liabilities that may result should the Partnership be unable to continue as a going concern.
4. Transition and Reorganization Costs
Transition and reorganization costs were $21.4 million for the year ended December 31, 2015. In connection with Murray Energy acquiring a noncontrolling ownership interest in the Partnership and its general partner (see Note 15), we entered into a management services agreement (“MSA”) with Murray American Coal Inc., an affiliate of 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 duplicate selling, general and administrative expenses. The costs are primarily comprised of retention compensation of $20.3 million to certain employees during the transition period and termination benefits to employees whose positions were replaced during the current period by Murray Energy employees under the MSA. Included in these retention costs were $5.9 million of retention and transition salaries paid by FELP, $10.0 million of retention and severance costs by Foresight Reserves which were recorded as capital contributions (an additional $1.3 million was paid and deferred and will be expensed over the required remaining retention period), $4.3 million of equity-based compensation for the accelerated vesting of certain equity awards, and the remaining $1.2 million was legal and various other one-time charges related to the Murray Energy transaction.
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 December 31, 2015 and 2014, we had outstanding coal derivative swap contracts to fix the selling price on 1.1 million tons and 3.4 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 and expected sales 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 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 December 31, 2015, we had swap agreements outstanding for 2016 to hedge the variable cash flows related to 1.0 million gallons 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.
The following is a summary of the unrealized and realized gains recorded on commodity derivative contracts for the years ended December 31, 2015, 2014 and 2013:
We received $19.1 million, $7.3 million and $1.0 million in proceeds during the years ended December 31, 2015, 2014 and 2013, respectively, 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 consists of the following:
7. Inventories
Inventories consist of the following:
8. Property, Plant, Equipment and Development, Net
Property, plant, equipment and development, net consist of the following:
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:
As discussed in Note 3 and further below, we are in default under all of our long-term debt and capital lease obligations as of December 31, 2015, and therefore, all outstanding long-term debt and capital lease obligations are reflected as a current liability in the consolidated balance sheet.
2021 Senior Notes
In August 2013, FELLC issued $600.0 million of 7.875% senior notes due August 15, 2021. The proceeds from the issuance were used to redeem $600.0 million of outstanding 9.625% senior notes due in 2017 (the “2017 Senior Notes”) through a tender offer. We recorded a $77.3 million loss on the early extinguishment of debt during the year ended December 31, 2013 for the $72.1 million in tender costs to redeem the 2017 Senior Notes and to write-off $5.2 million in unamortized debt issuance costs. The tender costs were recorded as an operating activity in the consolidated statement of cash flows. The 2021 Senior Notes are guaranteed on a senior unsecured basis by the Partnership and all of its domestic operating subsidiaries, other than Foresight Energy Finance Corporation, co-issuer of the notes. The interest on the 2021 Senior Notes is due semiannually on February 15 and August 15 of each year. The 2021 Senior Notes were issued at an initial discount of $4.3 million, which is being amortized using the effective interest method over the term of the notes.
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 constituted a “change of control” under the Indenture governing 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 (see Note 3). On February 16, 2016, we did not pay the accrued interest owed to holders of the 2021 Senior Notes on such day and elected to exercise the 30-day grace period with respect to the interest payment due under the Indenture. The aggregate amount of the interest payment due is $23.6 million. If we do not make the interest payment by the end of the 30-day grace period, an additional event of default will exist under the Indenture. We are actively negotiating an out-of-court restructuring with certain holders of the 2021 Senior Notes and our other creditors.
Prior to August 15, 2016, we may redeem some or all of the 2021 Senior Notes at a redemption price equal to the sum of the principal amount of the 2021 Senior Notes to be redeemed, plus accrued and unpaid interest, plus the applicable make-whole premium. After August 15, 2016, we may redeem all or a part of the 2021 Senior Notes at the redemption prices (expressed as a percentage of principal) set forth below plus accrued and unpaid interest, if redeemed during the 12-month period commencing on August 15 of the years indicated below:
Year
Percentage
105.91%
103.94%
101.97%
2019 and thereafter
100.00%
As of December 31, 2015 and 2014, Chris Cline, the Cline Trust Company, LLC and another director of the Partnership’s general partner had independently acquired and owned, in aggregate, $58.5 million and $12.0 million, respectively, of the outstanding notional principal on the Partnership’s 2021 Senior Notes (see Note 15).
Revolving Credit Facility
In August 2013, FELLC executed the second amendment to its credit agreement to increase the borrowing capacity under its senior secured revolving credit facility (the “Revolving Credit Facility”) from $400.0 million to $500.0 million and extend the maturity date to August 23, 2018. The amendment resulted in the write-off of $0.4 million in unamortized debt issuance costs due to certain lenders changing their commitment level under the credit agreement. In May 2015, we entered into the Incremental Amendment No. 1 to the Credit Agreement, which increased lender commitments under the Revolving Credit Facility by $50.0 million to $550.0 million. Borrowings under the Revolving Credit Facility bear interest at a rate equal to, at the Partnership’s option, (1) British Bankers’ Association (as published by Reuters) LIBOR plus an applicable margin ranging from 2.50% to 3.50% or (2) a base rate plus an applicable margin ranging from 1.50% to 2.50%, in each case, determined in accordance with the Partnership’s consolidated net leverage ratio. The Partnership is also required to pay a 0.5% commitment fee to the lenders under the Revolving Credit Facility for unutilized commitments.
Because of the existence of change of control provisions and cross-default provisions in the Credit Agreement, the unfavorable Delaware Court of Chancery opinion and consequently the default under the Indenture discussed above also resulted in events of default under the Credit Agreement. As a result, we have not had access to borrowings or other extensions of credit under our Revolving Credit Facility, which is having an adverse effect on our liquidity. We have not entered into forbearance agreements with the lenders under our Credit Agreement therefore they may exercise any remedies available to them, including acceleration of the indebtedness owed to them and exercising remedies with respect to our collateral securing such indebtedness.
The weighted-average interest rate on borrowings under the Revolving Credit Facility as of December 31, 2015 was 3.6%. At December 31, 2015, we had $6.5 million outstanding in letters of credit. In January 2016, we received notice from the administrative agent to the Credit Agreement that prospective borrowings under the Credit Agreement would be subject to the default interest rate, as defined in the Credit Agreement, which will result in a 2% increase to the borrowing rate.
Under the Credit Agreement, we are subject to customary debt covenants, including a consolidated interest coverage ratio and a consolidated senior secured leverage ratio. We were in compliance with our financial debt covenants as of December 31, 2015.
Term Loan
In August 2013, the Credit Agreement was also amended for the issuance of a $450.0 million senior secured term B loan (the “Term Loan”). The Term Loan was issued at an original issuance discount of $4.5 million which is being amortized over the term of the loan. In June 2014, we used proceeds from the IPO to repay $210.0 million in principal outstanding under the Term Loan. This prepayment resulted in the write-off of $2.8 million in unamortized debt issuance costs and $1.9 million of unamortized debt discount. The prepayment of principal was applied to prospective scheduled quarterly principal payments as set forth in the Credit Agreement such that no further scheduled contractual payments are due until the Term Loan matures on August 23, 2020. In May 2015, we entered into the Incremental Amendment No. 1 to the Credit Agreement which provided $60.0 million of incremental Term Loan borrowings. The Term Loan bears interest at LIBOR plus 4.5%, subject to a 1.0% LIBOR floor. As of December 31, 2015, the interest rate on the Term Loan was 5.5%. In January 2016, we received notice from the administrative agent to the Credit Agreement that prospective borrowings under the Credit Agreement would be subject to the default interest rate, as defined in the Credit Agreement, which will result in a 2% increase to the borrowing rate.
Longwall Financing Arrangements and Capital Lease Obligations
In January 2010, FELLC entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing arrangement is collateralized by the longwall mine 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 17 equal semiannual payments through June 30, 2020. The outstanding balance as of December 31, 2015 was $50.4 million. The guaranty agreement between FELLC and the lender under this financing arrangement has financial covenants that are identical to those of the Credit Agreement.
In May 2010, FELLC entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing arrangement is collateralized by the longwall mine 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 17 equal semiannual payments through September 30, 2020. The outstanding balance as of December 31, 2015 was $51.6 million. The guaranty agreement between FELLC and the lender under this financing arrangement has financial covenants that are identical to those of the Credit Agreement.
In March 2012, FELLC entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment during the third quarter of 2012, this interim longwall finance agreement was converted into six individual leases with maturities of four and five years beginning on September 1, 2012. These leases contain a bargain purchase option at the end of the lease term and are accounted for as capital lease obligations. These capital lease obligations bear interest ranging from 5.4% to 6.3%, and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2015, $17.1 million was outstanding under these capital lease obligations.
In November 2014, the Partnership entered into a sale-leaseback financing arrangement with a financial institution under which it sold a set of longwall shields and related equipment to a financial institution 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. These capital lease obligations bear interest at 5.762% and 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 December 31, 2015, $45.7 million was outstanding under these capital lease obligations.
Trade Accounts Receivable 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.
On January 27, 2016, we entered into a Securitization Forbearance Agreement pursuant to which the agent under that facility and the lenders under the securitization program agreed to forbear from exercising certain rights and remedies to which they may be entitled. The Securitization Forbearance Agreement currently remains in effect through March 15, 2016, unless extended by the securitization lenders in their sole discretion. There can be no assurances that the securitization lenders will agree to any extension of the Securitization Forbearance Agreement or that if such forbearance agreement is terminated early or expires, that the securitization lenders will not pursue any and all remedies available to them. Also under the Securitization Forbearance Agreement, the receivables facility was amended to permanently reduce commitments to $50.0 million in total, and we may borrow up to an amount such that the aggregate amount outstanding plus any adjusted LC participation amount at such time does not exceed the least of (i) $41.0 million, (ii) the borrowing base at such time and (iii) an amount equal to 70% of the outstanding balance of the eligible receivables. Any extensions of credit by the lenders during the forbearance period are at the sole and absolute discretion of the lenders.
As of December 31, 2015, we had borrowings outstanding of $41.0 million under the Securitization Program.
Maturity Tables
The following summarizes the contractual principal maturities of long-term debt (excluding unamortized aggregate discounts of $5.5 million) and capital lease obligations as of December 31, 2015:
The above table reflects the fact that the Partnership is in default under all of its debt arrangements and therefore the outstanding principal owed under these debt arrangements is callable by the lenders at their sole discretion.
11. Sale-Leaseback Financing Arrangements
Macoupin Energy Sale-Leaseback Financing Arrangement
In January 2009, Macoupin entered into a sales agreement with WPP, LLC (“WPP”) and HOD, LLC (“HOD”) (subsidiaries of Natural Resource Partners LP (“NRP”)) to sell certain mineral reserves and rail facility assets (the “Macoupin Sales Arrangement”). NRP is an affiliate of the Partnership (see Note 15). Macoupin received $143.5 million in cash in exchange for certain mineral reserve and transportation assets. Simultaneous with the closing, Macoupin entered into a lease with WPP for mining the mineral reserves (the “Mineral Reserves Lease”) and with HOD for the use of the rail loadout and rail loop (the “Macoupin Rail Loadout Lease” and the “Rail Loop Lease,” respectively). The Mineral Reserves Lease is a 20-year noncancelable lease that contains renewal elections for six additional five-year terms. The Macoupin Rail Loadout Lease and the Rail Loop Lease are 99 year noncancelable leases. Under the Mineral Reserves Lease, Macoupin makes monthly payments equal to the greater of $5.40 per ton or 8.00% of the sales price, plus $0.60 per ton for each ton of coal sold from the leased mineral reserves, subject to a minimum royalty of $4.0 million per quarter through December 31, 2028. After the initial 20-year term, the annual minimum royalty is $10,000 per year. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty under the Mineral Reserves Lease and tonnage fees paid under the Macoupin Rail Loadout and Rail Loop Leases discussed below exceed $4.0 million, Macoupin may generally recoup any unrecouped quarterly payments made during the preceding 20 quarters on a first paid, first recouped basis. The Macoupin Rail Loadout Lease and Rail Loop Lease require an aggregate payment of $3.00 ($1.50 for the rail loop facility and $1.50 for the rail load-out facility) for each ton of coal loaded through the facility for the first 30 years, up to 3.4 million tons per year. After the initial 30-year term, Macoupin would pay an annual rental payment of $20,000 per year for usage of the rail loadout and rail loop. The Macoupin Sales Arrangement, Mineral Reserves Lease, Macoupin Rail Loadout Lease and Rail Loop Lease are collectively accounted for as a financing arrangement (the “Macoupin Sale-Leaseback”). This financing arrangement is recourse to Macoupin and not recourse to Foresight Energy LP or any of its other subsidiaries. We are currently in dispute with WPP in regards to the application of the recoupment provision within the Mineral Reserves Lease (see Note 22).
At December 31, 2015 and 2014, the amount outstanding under the Macoupin Sale-Leaseback was $143.5 million. The effective interest rate on the financing obligation was 13.9% as of December 31, 2015 and 2014. Interest expense was $18.8 million, $16.3 million and $19.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015 and 2014, interest of $0.5 million and $3.0 million, respectively, was accrued in the consolidated balance sheets for the Macoupin Sale-Leaseback.
Sugar Camp Energy Sale-Leaseback Financing Arrangement
In March 2012, Sugar Camp entered into a sales agreement with HOD for which it received a total of $50.0 million in cash in exchange for certain rail loadout assets (“Sugar Camp Sales Agreement”). Simultaneous with the closing, Sugar Camp entered into a lease transaction with HOD for the use of the rail loadout (the “Sugar Camp Rail Loadout Lease”). The Sugar Camp Rail Loadout Lease is a 20-year noncancelable lease that contains renewal elections for 16 additional five-year terms. Under the Sugar Camp Rail Loadout Lease, Sugar Camp will pay a monthly royalty of $1.10 per ton for every ton of coal mined from specified reserves and loaded through the rail loadout. The royalty is subject to adjustment based on the time it takes for Sugar Camp to complete each longwall move. The royalty payments are subject to a minimum payment amount of $1.3 million per quarter for the first twenty years the lease is in effect. After the initial 20-year term, Sugar Camp would pay an annual rental payment of $10,000 per year. To the extent the minimum payment exceeds amounts owed based on actual coal loaded, the excess is recoupable within two years of payment.
The Sugar Camp Sales Agreement and Sugar Camp Rail Loadout Lease are collectively accounted for as a financing arrangement (the “Sugar Camp Sale-Leaseback”). This financing arrangement is recourse to Sugar Camp and Foresight Energy LP has a limited declining commercial guaranty which began at $15 million and decreases with each minimum payment made by Sugar Camp. At December 31, 2015 and 2014, the amount outstanding under the Sugar Camp Sale-Leaseback was $50.0 million. The effective interest rate on the financing, which is derived from the timing and tons of coal to be mined as set forth in the current mine plan and the related cash payments, was 13.2% and 13.9% at December 31, 2015 and 2014, respectively. Interest expense recorded on the Sugar Camp Sale-Leaseback was $5.4 million, $6.4 million and $7.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015 and 2014, interest of $1.6 million and $2.5 million, respectively, was accrued in the consolidated balance sheets for the Sugar Camp Sale-Leaseback.
Maturity Tables
The following summarizes the maturities of expected principal payments, based on current mine plans, on the Partnership’s sale-leaseback financing arrangements, and accrued interest at December 31, 2015:
The aggregate amounts of remaining minimum lease payments on the Partnership’s sale-leaseback financing arrangements are $289.3 million. Minimum payments from 2016 through 2020 are as follows:
12. Contractual Arrangements and Operating Leases
The Partnership leases certain surface rights, mineral reserves, mining, transportation and other equipment under various lease agreements with related entities under common control, other affiliated entities and independent third parties in the normal course of business.
The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The lease agreements typically require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (typically five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Under the terms of certain mineral reserve leases, the Partnership is to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and is responsible for the acquisition costs and the assets are to be titled to the lessor. Transportation throughput agreements generally require a per ton fee amount for coal transported and contain certain escalation clauses and/or renegotiation clauses. For certain transportation assets, the Partnership is responsible for operations, repairs, and maintenance and for keeping the transportation facilities in good working order. Surface rights, mining, and other equipment leases require monthly payments based upon the specified agreements. Certain of these leases provide options for the purchase of the property at various times during the life of the lease, generally at its then-fair market value. The Partnership also leases certain office space, rail cars and equipment under leases with varying expiration dates.
The following table presents future minimum payments, by year, required under contractual royalty and throughput arrangements with related entities and third parties as of December 31, 2015:
The following presents future minimum lease payments, by year, required under noncancelable operating leases with initial terms greater than one year, as of December 31, 2015:
Total rental expense from operating leases for the years ended December 31, 2015, 2014, and 2013 was $14.3 million, $16.1 million, and $17.0 million, respectively. Included in rental expense is $9.0 million, $9.9 million, and $9.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, of contingent rental payments to Williamson Transport, a subsidiary of NRP, for the rail loadout facility at Williamson Energy. We pay contingent rental fees, net of a fixed per ton amount received for maintaining the facility, on each ton of coal passed through the rail loadout facility.
13. Asset Retirement Obligations
The change in the carrying amount of asset retirement obligations was as follows:
The credit-adjusted, risk-free interest rates used in determining the asset retirement obligations were 9.8%, 6.6% and 8.8% at December 31, 2015, 2014, and 2013, respectively.
14. Coal Workers’ Pneumoconiosis and Workers’ Compensation
Certain of our consolidated affiliates are responsible under Illinois statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease (“CWP”). In addition, state statutes dictate that we provide income replacement and medical treatment for work-related traumatic injury claims, including survivor benefits for employment related deaths. Effective July1, 2014, we terminated our guaranteed cost program in favor of a high deductible insurance program.
Our liability for CWP benefits was estimated by an independent actuary based on assumptions regarding medical costs, allocated loss adjustment expense, claim development patterns and interest rates. For the years ended December 31, 2015 and 2014, we recorded CWP expense of $1.4 million and $1.5 million, respectively, and have a CWP liability of $3.0 million and $1.5 million recorded in other long-term liabilities in the consolidated balance sheets as of December 31, 2015 and 2014, respectively.
Our liability for workers compensation benefits was determined by a third-party administrator based on actual claims incurred and the expected development of those claims. For the years ended December 31, 2015 and 2014, we recorded workers’ compensation claim expense of $3.0 million and $1.4 million, respectively, and have a workers’ compensation liability of $2.2 million and $1.1 million recorded in accrued expenses and other current liabilities in the consolidated balance sheets as of December 31, 2015 and 2014, respectively.
15. Related-Party Transactions
The chairman of our general partner’s board of directors and the controlling member of Foresight Reserves, Chris Cline, directly and indirectly beneficially owns a 31% and 4% interest in the general and limited partner interests of NRP, respectively. Additionally, Donald R. Holcomb, who serves as a director on NRP’s board, is the member for the Cline Trust Company LLC, which owns 20.3 million of the Partnership’s common limited partner units. We routinely engage in transactions in the normal course of business with NRP and its subsidiaries and Foresight Reserves and its affiliates. These transactions have included production royalties, transportation services, administrative arrangements, coal handling and storage services, 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). We also acquire, from time to time, mining equipment from Foresight Reserves and affiliated entities.
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 nearly 50% of the outstanding limited partner units in FELP, including all of the outstanding subordinated units. FEGP will continue to govern the Partnership subsequent to this transaction. As part of the transaction, Murray Energy obtained an option, subject to certain conditions described below, to purchase an additional 46% of the voting interests in FEGP for $25 million during a five-year period. Murray Energy’s ability to exercise the option is conditioned upon (i) the exercise of the call option with respect to Colt LLC, a wholly-owned subsidiary of Foresight Reserves and (ii) the refinancing of the FELP 2021 Senior Notes and FELP’s existing credit facilities on terms reasonably acceptable to Foresight Reserves, or any other transaction (whether by amendment, waiver or a consent solicitation) that would have the effect of eliminating the “change of control” provisions of the FELP 2021 Senior Notes and FELP’s existing credit facilities with respect to the exercise of the option.
Murray Management Services Agreement
On April 16, 2015, the MSA was executed between FEGP and Murray American Coal, Inc. (the “Manager”), a wholly-owned subsidiary of Murray Energy, 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 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. After taking into account the contractual adjustments for direct costs incurred by FELP, the amount of net expense due to the Manager for the year ended December 31, 2015 was $4.7 million.
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 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 $98.7 million at December 31, 2015, with unearned income equal to $37.7 million. The unearned income will be reflected as other revenue over the lease term using the effective interest method. Any amounts in excess of the contractual minimums will be recorded as other revenue when earned. As of December 31, 2015, the outstanding Transport Lease financing receivable was $61.0 million, of which $2.5 million was classified as current in the 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 $34.1 million at December 31, 2015, with unearned income equal to $22.3 million. As of December 31, 2015, the outstanding ORRA financing receivable was $11.8 million, of which $0.2 million was classified as current in the consolidated balance sheet.
Other Murray Transactions
During the year ended December 31, 2015, we purchased $3.3 million in equipment, supplies and rebuild services from affiliates of Murray Energy. During the year ended December 31, 2015, our affiliate Coalfield Construction provided $0.2 million in equipment, supplies and rebuild services to affiliates of Murray Energy.
During the year ended December 31, 2015, we purchased $17.4 million in coal from Murray Energy and its affiliates to meet quality specifications under certain customer contracts and we sold $23.1 million of coal to Murray Energy and its affiliates, including Javelin Global Commodities Limited (“Javelin”). Javelin is an international commodities marketing and trading joint venture owned by Murray Energy and E.ON Global Commodities SE.
During the year ended December 31, 2015, 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 $11.0 million. These usage fees were billed to Murray Energy, resulting in no impact to our consolidated statement of operations. The usage of the railway line with this third-party rail company by Murray Energy counts towards the minimum annual throughput volumes with the third-party rail company, thereby reducing the Partnership’s exposure to contractual liquidated damage charges. Similarly, during the year ended December 31, 2015, we incurred $0.2 million of transportation fees incurred for shipments under one of Murray Energy’s third-party transloading contracts.
During the year ended December 31, 2015, we earned $0.3 million in other revenues for Murray Energy’s usage of our Sitran terminal.
2021 Senior Notes
On August 23, 2013, Cline Resource and Development Company (“CRDC”) acquired $16.5 million of outstanding principal amounts of our 2021 Senior Notes (the “Original Purchase”). During September and October 2013, CRDC sold the Original Purchase primarily to affiliates, including $8.0 million to Chris Cline, $4.0 million to an entity controlled by John F. Dickinson, a director of our general partner’s board of directors until December 31, 2015, and $3.7 million to two former executives of the Partnership. Additional amounts were acquired independently in 2015 by Chris Cline and The Cline Trust Company LLC, as discussed below.
As of December 31, 2015 and 2014, Chris Cline owned $44.5 million and $8.0 million, respectively, of the outstanding principal on our 2021 Senior Notes. Chris Cline acquired $8.0 million in principal of the Original Purchase and during the year ended December 31, 2015, acquired an additional $36.5 million in principal from third parties in open market transactions. During the years ended December 31, 2015, 2014, and 2013, $1.9 million, $0.6 million and $0 million, respectively, of interest on the 2021 Senior Notes was paid to Chris Cline. As of December 31, 2015 and 2014, $1.3 million and $0.2 million, respectively, of interest on the 2021 Senior Notes was accrued to the benefit of Chris Cline.
The entity controlled by Mr. Dickinson owned $4.0 million of the outstanding principal on our 2021 Senior Notes as of December 31, 2015 and 2014, all of which was acquired from the Original Purchase. During the years ended December 31, 2015 and 2014, $0.3 million of interest on the 2021 Senior Notes was paid to Mr. Dickinson. As of December 31, 2015 and 2014, $0.1 million of interest on the 2021 Senor Notes was accrued to the benefit of the entity controlled by Mr. Dickinson.
As of December 31, 2015, The Cline Trust Company LLC owned $10.0 million in principal of our 2021 Senior Notes, all of which was acquired during the year ended December 31, 2015. During the year ended December 31 2015, no interest had been paid to The Cline Trust Company LLC. As of December 31, 2015, $0.3 million of interest on the 2021 Senior Notes was accrued to the benefit of The Cline Trust Company LLC.
Also, Michael Beyer, the former chief executive officer of FELP, who resigned in May 2015, and Drexel Short, a former executive of our predecessor, who retired in March 2014, acquired $3.2 million and $0.5 million, respectively, from the Original Purchase. Mr. Beyer disposed of his 2021 Senior Notes in September of 2015. These former executives were no longer affiliates of the Partnership subsequent to their termination dates. For each of the years ended December 31, 2015 and 2014, $0.3 million of interest was paid to Mr. Beyer and Mr. Short, collectively, while they were affiliates of the Partnership.
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 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 10 years following the date on which any such royalty is paid.
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 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 $16.2 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 22).
As of December 31, 2015 and 2014, we have established a $46.3 million and $34.7 million reserve, respectively, against a contractual prepaid royalty between Hillsboro and WPP given that the recoupment of certain prior minimum royalty payments was improbable given the remaining recoupment period available and forecasted demand for Hillsboro coal based on current and forecasted near-term market conditions. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, assessing mine production plans, sales commitments, current and forecasted future coal market conditions, and remaining years available for recoupment.
Transloading Agreements
Convent Marine Terminal Amendment
In August 2011, an affiliated company owned by Foresight Reserves acquired the IC RailMarine Terminal in Convent, Louisiana. This terminal, commonly referred to as the Convent Marine Terminal (“CMT”), is owned by Raven Energy LLC (“Raven”), an entity once controlled and beneficially owned by Christopher Cline. The terminal is designed to ship and receive commodities via rail, river barge and ocean vessel. We have a material handling agreement contract for throughput at the terminal under which we pay fees based on the tonnages of coal we move through the terminal, subject to minimum annual take-or-pay volume commitments. Effective May 1, 2015, the Partnership amended its material handling agreement with Raven to reduce the minimum annual throughput volume at CMT to 5.0 million tons and to extend the duration of the contract by one year to 2022. In August 2015, The Cline Group sold Raven to an entity under which it does not have significant influence; therefore the business activities with Raven are no longer considered affiliate transactions subsequent to the sale date.
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. No amounts were incurred by the general partner or reimbursed under the partnership agreement from the IPO date to December 31, 2015.
Other
In August 2013, FELLC entered into an equipment repair and rebuild agreement with Seneca Rebuild LLC (“Seneca Rebuild”), an affiliated entity owned indirectly by Chris Cline. The agreement called for Seneca Rebuild to be the primary provider of repair and rebuild services for mining machinery and equipment for our mines. Effective April 1, 2014, FELLC reached an agreement to acquire Seneca Rebuild for $3.8 million, net of cash acquired. Because FELLC and Seneca Rebuild were under common control, the assets and liabilities of Seneca Rebuild were recorded by FELLC at carrying value on the acquisition date. Seneca Rebuild’s net assets on the acquisition date consisted principally of property, plant and equipment. The $0.3 million paid over the excess of the carrying value of the net assets of Seneca Rebuild on the acquisition date was recorded as a deemed distribution. Given the immateriality of this acquisition, the financial results of Seneca Rebuild are reflected prospectively in the consolidated financial statements of the Partnership.
Williamson leases property from Williamson Transport, an affiliate of NRP, under two surface leases with initial terms through October 15, 2031 and an option to extend the leases in five-year increments until all the coal leased from an NRP affiliate is mined on Williamson’s premises. Williamson Transport has the option to put the land to Williamson for its fair market value as determined by an independent appraiser at any time during the lease term. Additionally, under a separate lease with an initial term through March 12, 2018, Williamson pays $5,000 per year for use of the premises and a fee, currently at $1.83 per ton, for each ton of coal produced at Williamson that is loaded through the Williamson rail loadout facility. Williamson Transport may elect to renew or extend the sublease for successive five-year periods. If Williamson Transport elects not to renew the sublease, Williamson has the option to buy the Williamson rail loadout facility for its fair market value as determined by an independent appraiser. Williamson receives a fee of $0.25 per ton from Williamson Transport for each ton of coal that is loaded through the Williamson rail loadout facility in exchange for operating the load out.
We are party to two surface leases in relation to the coal preparation plant and rail loadout facility at Williamson with New River Royalty, a subsidiary of Foresight Reserves. The primary terms of the leases expire on October 15, 2021, but may be extended by New River Royalty for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases. Additionally, New River Royalty may require Williamson to purchase any portion of either of the leased properties at any time while the leases are in effect for $3,000 an acre. Williamson Transport has the option to purchase any property optioned under the leases if Williamson does not perform its purchase obligation within fifteen days of receiving notice of its purchase obligation.
We may arrange air travel on an individual flight basis with affiliated entities controlled by Chris Cline. These expenses are incurred hourly (at estimated cost), by flight, and are initially paid by the affiliated entities and then reimbursed by us. We also from time to time utilize other assets controlled by Chris Cline and reimburse the affiliated entities on a time-incurred basis.
In January 2007, Chris Cline, Foresight Reserves, Adena Minerals LLC and their respective affiliates (collectively, “Adena Entities”) and NRP executed a restricted business contribution agreement. The restricted business contribution agreement obligates the Adena Entities and their affiliates to offer NRP any business owned, operated or invested in by the Adena Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in identified transportation infrastructure relating to certain future mine developments by the Adena Entities in Illinois. NRP’s acquisition of certain coal reserves and infrastructure assets related to our Macoupin, Hillsboro and Sugar Camp mining complexes, discussed above and in Note 11, were deals consummated under the restricted business contribution agreement with the Adena Entities. The Adena Entities are required to offer and could consummate additional deals under the restricted business contribution agreement in the future.
During the years ended December 31, 2015, 2014 and 2013, we purchased $14.5 million, $18.1 million and $14.7 million, respectively, in mining supplies from an affiliated joint venture under a supply agreement entered into in May 2013 (see Note 16).
We received monthly fees from Foresight Reserves in exchange for performing bookkeeping and other administrative functions for certain of its subsidiaries.
The following table presents the affiliate amounts included in our consolidated balance sheets:
(1) - Includes amounts due to/from a joint venture partially owned by an affiliate of The Cline Group - see Note 16.
(2) - Includes amounts due from Javelin, a joint venture partially owned by Murray Energy.
(3) - Prepaid royalties with NRP and affiliated entities is presented net of a $46,306 and $34,700 reserve as of December 31, 2015 and 2014, respectively.
A summary of expenses/income incurred with affiliated entities is as follows for the years ended December 31, 2015, 2014 and 2013:
Principal location in the 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
(8) - Other operating income, net
The contractual commitment tables for operating leases and royalty agreements with affiliated parties are disclosed in Note 12. The contractual commitment tables for sales-leaseback arrangements with affiliated parties are disclosed in Note 11.
16. Variable Interest Entities (VIEs)
Our consolidated financial statements include VIEs for which the Partnership or one of its subsidiaries is the primary beneficiary. Among those VIEs consolidated by the Partnership and its subsidiaries are 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; and LD Labor Company LLC (collectively, the “Contractor VIEs”). Each of the Contractor VIEs holds 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 receives 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 are therefore VIEs. The Partnership was determined to be the primary beneficiary of each of these entities given it controls these entities under a contractual cost-plus arrangement. During the years ended December 31, 2015, 2014 and 2013, in aggregate, the Contractor VIEs earned income of $0.5 million, $0.5 million and $0.4 million, respectively, under the contractual arrangements with the Partnership which was classified as net income attributable to noncontrolling interests in the consolidated statements of operations.
On August 23, 2013, FELLC effected a reorganization pursuant to which certain transportation assets were distributed to its members (the “2013 Reorganization”) (see Note 18). Among the assets distributed were Adena and Hillsboro Transport. Subsequent to the 2013 Reorganization, both of these entities were identified as VIEs and continued to be consolidated by FELLC. As such, the aggregate net book values of Adena and Hillsboro Transport of $10.1 million on the distribution date was reclassified from predecessor members’ equity to noncontrolling interest equity on the 2013 Reorganization date. During the years ended December 31, 2015, 2014 and 2013, Adena and Hillsboro Transport as VIEs earned income, in aggregate, of $0.3 million, $3.4 million and $1.8 million, respectively, which was classified as net income attributable to noncontrolling interests in the consolidated statements of operations.
During the first quarter of 2015, Adena and Hillsboro Transport were contributed to us by Foresight Reserves and a member of management (see Note 18) and are therefore no longer consolidated as VIEs. The aggregate net book values of Adena and Hillsboro Transport of $9.9 million was reclassified from noncontrolling interest equity to limited partners’ capital on the contribution dates.
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 our general assets.
The total consolidated VIE assets and liabilities reflected in the Partnership’s consolidated balance sheets are as follows:
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 equity holders 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.
17. Fair Value of Financial Instruments
The tables below set 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. During the years ended December 31, 2015, 2014 and 2013, there were no assets or liabilities that were transferred between Level 1 and Level 2.
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 consolidated balance sheets as of December 31, 2015 and 2014, are as follows:
The following is a reconciliation of the beginning and ending balances for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2014 and 2013:
The liability award represents a phantom equity award (“Liability Award”) to a retired executive for which the value was determined based on the fair value, as defined in the agreement, of Foresight Reserves as of the employee’s retirement date and was adjusted for distributions made to Foresight Reserves’ members. This Liability Award fully vested in 2010 and was granted principally for services performed to develop the Partnership’s longwall mines. Prior to March 31, 2014, the Liability Award was Level 3 in the fair value hierarchy given Foresight Reserves was a private company; therefore, there was no liquid market to determine the fair value of Foresight Reserves’ equity. The fair value of the Liability Award was determined using a discounted cash flow model and corroborated with recent equity transactions at Foresight Reserves. Effective March 31, 2014, the Liability Award amount was negotiated between the Partnership and the employee to be $12.4 million; therefore, the value of this liability was contracted and therefore no longer a Level 3 liability. As of December 31, 2015, $0.4 million of the unpaid balance is recorded in accrued expenses and other current liabilities for required payments over the next year, and the remaining $3.4 million is recorded in other long-term liabilities, which will be paid out ratably through 2024. The note payable to the retired executive currently bears interest at 3.5%.
Long-Term Debt
The fair value of long-term debt as of December 31, 2015 and 2014 was $1,244.3 million and $1,279.7 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. Partners’ Capital
Common and Subordinated Units
All subordinated units are currently held by Murray Energy. The principal difference between our common units and subordinated units is that subordinated unitholders are not entitled to receive a distribution from operating surplus until the holders of common units have received the minimum quarterly distribution (“MQD”) from operating surplus. The MQD is $0.3375 per unit for such quarter plus any cumulative arrearages of previously unpaid MQDs from previous quarters. Also, subordinated unitholders are not entitled to receive arrearages. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, on the first business day after the Partnership has paid the MQD for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2017 and there are no outstanding arrearages on the common units. Notwithstanding the foregoing, the subordination period will end on the first business day after the Partnership has paid an aggregate amount of at least $2.025 per unit (150.0% of the MQD on an annualized basis) on the outstanding common and subordinated units and the Partnership has paid the related distribution on the incentive distribution rights, for any four-quarter period ending on or after March 31, 2015 and there are no outstanding arrearages on the common units. Our partnership agreement provides that our general partner will make a determination as to whether a distribution will be made, but our partnership agreement does not require us to pay distributions at any time or at any amount. Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.
Incentive Distribution Rights (“IDRs”)
Our IDRs are held by Murray Energy, Chris Cline and a former member of management. IDRs represent the right to receive an increasing percentage of quarterly distributions from operating surplus after the MQD and the target distribution levels (described below) have been achieved. Our general partner may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. The IDR holders will have the right, subsequent to the subordination period and subject to distributions exceeding the MQD by at least 150% for four consecutive quarters, to reset the target distribution levels and receive common units.
Allocation of Net Income (Loss)
Our partnership agreement contains provisions for the allocation of net income and loss to the unitholders and the general partner. For purposes of maintaining partner capital accounts, the partnership agreement generally specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interest.
Percentage Allocation of Distributions from Operating Surplus
The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our IDRs based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the IDR holders and the unitholders of any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Common Unit”. The percentage interests shown for our unitholders and the IDR holders for the MQD are also applicable to quarterly distribution amounts that are less than the MQD.
The percentage interests set forth below excludes the impact of arrearages which would first be due to common unitholders before the IDR holders would receive a distribution.
Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders and general partner will receive.
Equity Contributions and Distributions
The follow table summarizes the quarterly distribution paid per limited partner unit (except as noted) during the years ended December 31, 2015 and 2014:
(a)
- In November 2015, we paid a quarterly distribution of $0.17 per unit payable to common unitholders, while suspending the distribution on all subordinated units. Chris Cline and one additional common unitholder elected to forego the $0.17 per common unit distribution on their collective 21.2 million common units.
Simultaneously with the closing of a debt refinancing on August 23, 2013, FELLC underwent the 2013 Reorganization pursuant to which it distributed to its members 100% of its ownership interest in Sitran, a barge terminal on the Ohio River, Adena, an entity that provides certain water and other miscellaneous rights to FELP’s mines, and Hillsboro Transport, Hillsboro’s coal loadout facility. FELLC recorded a non-cash distribution totaling $62.0 million in August 2013 to reflect these distributions to its members. In May 2014, based upon the terms of the 2013 Reorganization, FELLC also distributed to its members approximately 1,900 acres of surface land not needed for current or currently projected future operations and $0.1 million in cash. The carrying value of the distributed land was $12.2 million.
During the first quarter of 2015 (the “Contribution Date”), Foresight Reserves and a member of management contributed back to FELP, for no consideration, 100% of the equity of Sitran, Adena and Hillsboro Transport. In addition, Foresight Reserves and a member of management contributed, for no consideration, Akin Energy LLC, an entity holding certain permits and development costs for a natural gas power generation facility. Because Sitran and Akin Energy were under common control, the Partnership’s historical financial statements have been retrospectively adjusted to combine their financial position at historical cost and their results of operations. The equity values of Sitran and Akin Energy prior to the Contribution Date are included in predecessor equity in the statement of partners’ capital (deficit). Hillsboro Transport and Adena were previously consolidated by the Partnership as VIEs; therefore the contribution did not result in a change in reporting entity (see Note 16). On the Contribution Date, the net book values of the Contributed Companies were reclassified from either predecessor equity or noncontrolling interest, as applicable, to limited partners’ capital in the statement of partners’ capital (pro rata between the common and subordinated units based on the number of units held by the contributing parties on the Contribution Date). The aggregate net book value of the Contributed Companies on the Contribution Date was $60.6 million.
During the year ended December 31, 2015, Foresight Reserves incurred $11.3 million of one-time employee compensation costs classified as transition and reorganization costs for which it will not seek reimbursement from the Partnership. The noncash contribution from Foresight Reserves increased the Partnership’s limited partners’ capital accounts. Of the $11.3 million contribution amount, $1.3 million was deferred as a prepaid expense and will be amortized over the required remaining retention period in 2016.
On June 23, 2014, in connection with the IPO, Foresight Reserves and a member of management each contributed their membership interests in FELLC to the Partnership in exchange for common and subordinated units of FELP. As a result, the members’ deficit balance of $104.9 million at the time of the transfer was allocated, pro rata based on units outstanding, to common and subordinated unitholder capital accounts.
In connection with the acquisition of Seneca Rebuild on April 1, 2014, a deemed distribution in the amount of $0.3 million was recorded to reflect the excess of the purchase price paid by FELLC over the carrying value of the net assets acquired.
Noncontrolling Interests
Noncontrolling interests’ equity and net income attributable to noncontrolling interests result from the consolidation of variable interest entities for which the Partnership has no equity interests (see Note 16).
19. Equity-Based Compensation
Long-Term Incentive Plan
The Partnership has adopted a Long-Term Incentive Plan ("LTIP" or the “Plan”) for employees, directors, officers and certain key third-parties (collectively, the "Participants"). The Plan allows for the issuance of equity-based compensation in the form of phantom units, unit awards, unit options, unit appreciation rights, restricted units, other unit-based awards, distribution equivalent rights, performance awards, and substitute awards to Participants. The LTIP awards granted thus far are phantom units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive FELP common units. The Board of Directors of the Partnership authorized 7.0 million common units to be granted under the LTIP, with 6.2 million units available for grant as of December 31, 2015. Grant levels and vesting requirements are recommended by the Partnership's chief executive officer, subject to the review and approval by the board of directors.
Long-Term Incentive Compensation Awards
In June 2014, upon the closing of the IPO, pre-existing cash-based compensation liability awards were converted to equity awards which are to be settled in FELP common units after meeting certain vesting requirements. As a result, on June 23, 2014, $0.6 million was reclassified from accrued expenses and other current liabilities to partners' capital for the conversion of the pre-existing cash-based awards to 154,027 phantom units to be issued under the LTIP. No additional compensation expense was recorded as a result of the modification of these awards. These modified awards are time-based unit awards and generally vest, subject to continued employment, ratably over three-year periods from the award date (with accelerated vesting in certain instances). Compensation expense for these awards is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. Upon vesting, the Partnership issues authorized and unissued shares of the Partnership's common units to the recipient. As of December 31, 2015, 15,392 phantom units of these long-term incentive compensation awards were non-vested.
LTIP Awards
During the years ended December 31, 2015 and 2014, the Partnership granted 1,838,099 and 595,075 phantom units, respectively, to employees under the LTIP. Of the phantom unit LTIP awards granted during the years ended December 31, 2015 and 2014, 431,750 and 72,500, respectively, were vested immediately on the grant date. This includes an equity award granted to the former chief executive officer of the Partnership in February 2015 of 215,954 common units and 215,796 subordinated units which fully-vested on the grant date. The remaining awards are considered time-based unit awards and generally cliff-vest, subject to continued employment, over the required service period (with accelerated vesting under certain instances). The require service periods vary but are generally three-year periods. Compensation expense for these awards is recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. Upon vesting, the Partnership will issue authorized and unissued shares of the Partnership’s common units to the recipient. As of December 31, 2015, 1,666,466 phantom units granted to employees under the LTIP were non-vested.
Director Awards
During the years ended December 31, 2015 and 2014, the Partnership granted 35,324 and 7,919 phantom units, respectively, to non-employee directors under the LTIP. These awards are considered time-based unit awards and vest ratably over a three-year period (with accelerated vesting in certain instances). Compensation expense for these awards is recognized on a straight-line basis over the requisite service period. As of December 31, 2015, 29,483 phantom units granted to nonemployee directors under the LTIP were non-vested.
Summary
For the year ended December 31, 2015 and 2014, our equity-based compensation expense was $13.7 million and $5.0 million, respectively, net of estimated forfeitures. During the year ended December 31, 2014, $0.3 million of equity-based compensation was capitalized into mine development costs. During the years ended December 31, 2015 and 2014, the Partnership’s equity-based compensation is recorded in the consolidated statements of operations as follows:
As of December 31, 2015, the total unrecognized compensation expense for phantom unit awards that are expected to vest was $6.4 million. This expense is expected to be recognized over a weighted-average period of 0.6 years. The intrinsic value of the non-vested LTIP awards was $6.0 million as of December 31, 2015. All non-vested phantom units include tandem distribution incentive 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 $0.6 million accrued for this liability as of December 31, 2015. Any distributions accrued to a Participants’ 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 years ended December 31, 2015 and 2014 is as follows:
During the years ended December 31, 2015 and 2014, the Partnership settled 75,522 and 53,745, respectively, of vested equity awards in cash to satisfy the individual statutory minimum tax obligations of the LTIP participants.
20. Earnings per Limited Partner Unit
Limited partners’ interest in net income attributable to the Partnership and basic and diluted earnings per unit reflect net (loss) income attributable to the Partnership subsequent to the June 23, 2014 closing date of the IPO. We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in Accounting Standards Codification (“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 (loss) income is allocated to the limited partners, including the holders 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 partnership agreement contractually limits distributions to available cash as determined by our general partner; therefore, undistributed earnings of the Partnership are not allocated to the IDR holder. There were no allocations of earnings to participating securities during the periods presented below. Basic EPU is computed by dividing net earnings attributable to unitholders by the weighted-average number of units outstanding during each period. However, because our IPO was completed on June 23, 2014, the units outstanding from the IPO date are utilized for the period presented. Basic common units outstanding includes the 2,625,000 overallotment units offered to the underwriters, which were issued to Foresight Reserves and a member of management in July 2014, as of the IPO date. Diluted EPU reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.
The following table illustrates the Partnership’s calculation of net income (loss) per common and subordinated unit for the period indicated:
(1)
- Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the years ended December 31, 2015 and 2014, approximately 1.7 million and 0.6 million, respectively, phantom units were anti-dilutive, and therefore were excluded from the diluted EPU calculation.
21. Risk Concentrations
Sales and Credit Risk
The Partnership determines creditworthiness for trade customers based on an evaluation of the customer’s financial condition. Credit losses have historically been minimal. The aggregate outstanding trade receivable balance as of December 31, 2015 from customers representing greater than 10% of our total sales was $24.8 million. Also, as of December 31, 2015, the Partnership has outstanding accounts receivable and financing receivables with Murray Energy and its affiliates of $19.0 million and $72.8 million, respectively (see Note 15).
For the years ended December 31, 2015, 2014 and 2013, the following customers (aggregated at the parent company level) exceeded 10% of total coal sales:
(A) - Less than 10% of total coal sales for this period.
During the years ended December 31, 2015, 2014 and 2013, export tons (inclusive of tons sold from mines under development) represented 24%, 30% and 33% of tons sold, respectively. Tons exported into Europe during the years ended December 31, 2015, 2014 and 2013 represented approximately 22%, 26% and 23%, respectively, of total tons sold during those years (inclusive of tons sold from mines under development). No other international geographic regions exceeded 10% of tons sold during the years ended December 31, 2015, 2014 and 2013. Our domestic coal sales are principally to electric utility companies in the eastern United States with installed pollution control devices.
Transportation
The Partnership depends on rail, barge, and export terminal systems to deliver coal to its customers. Disruption of these services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Partnership’s ability to supply coal to its customers, resulting in decreased shipments. As such, the Partnership has sought to diversify transportation options and has entered into long-term contracts with transportation providers to ensure transportation is available to transport its coal.
22. Contingencies
In May 2015, the trustee for the holders of our 2021 Senior Notes filed suit in the Delaware Court of Chancery against the issuers and guarantors of the 2021 Senior Notes (collectively, the “FE Defendants”) alleging that Murray Energy’s acquisition of a 34% interest in FEGP and of an option to purchase an additional 46% interest in FEGP triggered a change of control of the 2021 Senior Notes pursuant to its Indenture, thereby requiring the FE Defendants to make an offer to purchase the 2021 Senior Notes at 101% of the principal amount tendered plus any accrued and unpaid interest thereon. In July 2015, the FE Defendants answered the trustee’s complaint and filed a motion for judgment on the pleadings. In August 2015, the trustee filed a cross-motion for judgment on the pleadings. In November 2015, after the completion of briefing on the parties’ cross-motions for judgment on the pleadings, the Delaware Court of Chancery heard oral argument on the cross-motions. On December 4, 2015, the Delaware Court of Chancery issued a memorandum opinion granting the trustee’s motion for judgment on the pleadings and denying the FE Defendants’ motion for judgment on the pleadings. In its memorandum opinion, the Delaware Court of Chancery ruled, in part, that Murray Energy’s acquisition constituted a change of control under the terms of the Indenture, and that the FE Defendants had breached the Indenture by not making an offer to purchase the 2021 Senior Notes. The Delaware Court of Chancery thereafter denied the FE Defendants’ motion for reargument. On January 7, 2016, at the parties’ joint request, the Delaware Court of Chancery entered an order staying further proceedings until January 18, 2016. Through subsequent orders, the stay has been extended through March 15, 2016. As a result of the Delaware Court of Chancery’s memorandum opinion, we are in default of the Indenture as well as all of our other long-term debt and capital lease obligations because of either a similar change of control provision or cross-default provisions within these agreements. See Note 3 for additional discussion on the ramifications of this memorandum opinion.
In January 2016, certain plaintiffs filed suit against us 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, should our position not prevail, we would be responsible for funding back pay and lost wages of approximately $2.0 million.
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. We do not believe that royalty recoupment provision was misapplied. While we believe that the language of the agreements, as well as the course of performance thereunder, support Macoupin’s position, should our position not prevail, we would be responsible for paying WPP for any recoupment taken that is found to contravene the language of the agreements.
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, which has required the stoppage of mining operations since March 2015. As a result of the force majeure event, we have not made $16.2 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 is a breach of the royalty agreement and (iii) it 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. While we believe this is a force majeure event, as contemplated by the royalty agreement, and that the fraud claim is 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 March 2015, we entered into a settlement agreement with Murray Energy resolving litigation between the Partnership and Murray Energy for an aggregate amount of $14.0 million. Of the $14.0 million settlement amount, $10.0 million was due and payable to us immediately and the remainder is due in increments of $1.0 million over each of the next four years. We recorded the $13.5 million net present value of the settlement amount to other operating income, net in the consolidated statement of operations during the year ended December 31, 2015.
In January 2014, the Illinois Environmental Protection Agency (the “IEPA”) issued Sugar Camp a violation notice regarding construction of an underground injection well without issuance of an appropriate permit (“January Notice”). Sugar Camp is working with the IEPA to finalize its permit application, which has been in process since May 2013. The IEPA determined not to enter into a
compliance commitment agreement with respect to the January Notice and referred the January Notice to the Illinois Attorney General for enforcement. While Sugar Camp believes this referral may result in the assessment of a penalty, we believe any such penalty would be immaterial.
Sugar Camp continues to work with the IEPA to identify and permit a sustainable solution for the future disposal of water at the mine in compliance with its permits. Sugar Camp has spent $34.1 million on water treatment infrastructure to prospectively comply with its permits.
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. Hillsboro intends to continue its defense of the issuance of the permit in the Circuit Court proceeding.
FELLC acquired the Shay No. 1 Mine at Macoupin (“Shay Mine”) in 2009. Prior to this acquisition, in 2003, ExxonMobil Coal USA, Inc. (“Exxon”), the prior owner of the Shay Mine, enrolled the mine in the IEPA’s Site Remediation Program (“SRP”) to address some concerns regarding groundwater contamination from the refuse areas. In 2011, Macoupin proposed, and the IEPA accepted, a compliance commitment agreement (“CCA”) with remediation steps designed to respond to the groundwater contamination concerns. Further, in May 2013, Macoupin submitted a corrective action plan (“CAP”) with groundwater modeling to the IEPA to address the long-term compliance and corrective measures planned for the cleanup of groundwater contamination issues. In June 2013, the IEPA referred the CCA to the Illinois Attorney General’s Office for enforcement on the basis that the compliance period for the CCA extended for too long of a period for the IEPA to monitor. The CAP has been approved by the IEPA. On July 24, 2015, the Illinois Attorney General’s Office filed a formal complaint against Macoupin in Macoupin County Circuit Court to effectuate a settlement and entry of a negotiated consent order. On September 14, 2015, the Circuit Court approved the settlement and entered the consent order. Macoupin has begun to effectuate the CAP and has made all the required civil penalty payments of $0.1 million to the IEPA and $0.2 million in environmental project payments. As of December 31, 2015, we have recorded an asset retirement obligation of $6.8 million as the costs relate to ongoing mining operations at Macoupin. However, there can be no assurance that the ultimate costs will not exceed this amount.
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 December 31, 2015, we have $2.3 million accrued, in aggregate, for various litigation matters.
Performance Bonds
We had outstanding surety bonds with third parties of $79.2 million as of December 31, 2015 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.
23. Employee Benefit Plans
The Partnership offers safe harbor 401(k) plans (the “Plans”) for all employees who are eligible to participate. Employees are immediately eligible to participate upon becoming a full-time employee with the Partnership and its subsidiaries and affiliates. The Plans allow for the deferral of all or part of a participant’s compensation, as defined by the Plans, up to the current limits provided by the Internal Revenue Service. The safe harbor matching feature calls for the Partnership to contribute 100% of the first 3% of compensation a participant contributes, and 50% of the next 2% of compensation contributed by the participant. Partnership contributions under the Plans for the years ended December 31, 2015, 2014, and 2013 were $3.3 million, $3.1 million, and $2.5 million, respectively.
24. Selected Quarterly Financial Information
A summary of the unaudited quarterly results for the years ended December 31, 2015 and 2014 is presented below:
(1)
Calculated based on net (loss) income attributable to limited partners and limited partner units outstanding, as applicable, subsequent to the IPO on June 23, 2014.
In the first quarter of 2015, $13.5 million was recognized as other operating income for a settlement agreement with Murray Energy resolving litigation between the Partnership and Murray Energy.
In the second, third and fourth quarters of 2015, we recorded transition and reorganization costs of $12.3 million, $5.0 million and $4.1 million, respectively, to reorganize certain corporate administrative functions to optimize synergies between the Partnership and Murray Energy (see Note 4).
In the fourth quarter of 2015, we recorded long-lived asset impairment charges of $12.6 million to impair $11.6 million of Hillsboro prepaid royalties with an affiliate (see Note 15) and to write-off $1.0 million of deferred longwall costs at Hillsboro which are being abandoned as a result of the mine fire.
In the second quarter of 2014, we recorded an early extinguishment of debt loss of $5.0 million due to the early repayment of $210.0 million of principal under our Term Loan (see Note 10).
In the fourth quarter of 2014, we recorded a charge of $34.7 million to impair certain Hillsboro prepaid royalties with an affiliate (see Note 15).
25. Subsequent Events
Subsequent events described in Notes 3, 10, and 22.
Hillsboro Mine
On March 26, 2015, as a result of a mine fire, health and safety readings in excess of actionable levels (requiring mine management to evacuate the mine) were detected at Hillsboro. All underground employees were safely evacuated. The Mine Safety and Health Administration (“MSHA”) approved reentry into the mine on May 6, 2015 to complete an evaluation of the affected area and the longwall. The continuing health and safety risks posed by the spontaneous combustion event required us to evacuate the mine shortly after reentry. In July 2015, MSHA approved restoration of power to a portion of the mine to allow our personnel re-entry into the mine to evaluate the ventilation and longwall mining systems, to address any needed rehabilitation to the underground facilities to allow us to operate the longwall in the current panel until we reach a point in the panel where the longwall equipment can be safely recovered. The continued risks posed by the spontaneous combustion event required us to evacuate the mine again in August 2015. On October 14, 2015, personnel reentered the mine and began the construction of underground ventilation control stoppings intended to assist in adjusting ventilation within the mine and to allow personnel to complete the current longwall move. To date, our efforts to
extinguish the combustion event have been primarily directed at sealing specific areas within the mine and filling them with extinguishing agents and inert gases. Thus far, these efforts have been unsuccessful at demonstrating that the combustion event is permanently extinguished. On March 1, 2016, we asked MSHA for permission to take the next step of temporarily sealing the entire mine to reduce or eliminate oxygen flow paths into the mine. We are uncertain as to when production will resume at this operation but we will continue to work closely with MSHA and the Illinois Office of Mines and Minerals Mine Safety and Training Division to ensure the safety of our employees throughout the process and to explore alternatives to safely resolving this issue.
Item 9.
Item 9. Changes in and Disagreements With Accountant on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. 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 of December 31, 2015. 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 design and operation as of such date. 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.
Changes in Internal Control over Financing Reporting
There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2015 that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
Attestation Report of the Registered Public Accounting Firm
The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2015 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report that is included herein.
Management’s Assessment of Internal Control Over Financial Reporting
Management of FELP is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(t) under the Securities Exchange Act of 1934. Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2015, with the participation of our chief executive officer and principal financial officer, based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on this assessment, management concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2015.
Report of Independent Registered Public Accounting Firm
The Board of Directors of Foresight Energy GP LLC and
Unitholders of Foresight Energy LP
We have audited Foresight Energy LP’s (the “Partnership”) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Foresight Energy LP’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Foresight Energy LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Foresight Energy LP as of December 31, 2015 and 2014, and the related consolidated statements of operations, partners’ capital (deficit), and cash flows for each of the three years in the period ended December 31, 2015, of Foresight Energy LP and our report dated March 15, 2016 expressed an unqualified opinion thereon that included an explanatory paragraph regarding Foresight Energy LP’s ability to continue as a going concern.
/s/ Ernst & Young LLP
St. Louis, Missouri
March 15, 2016
Item 9B.
Item 9B. Other Information
None.
PART III.
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance of the Managing General Partner
Management of Foresight Energy LP
We are managed and operated by the board of directors and executive officers of our general partner, Foresight Energy GP LLC, which is jointly owned by Foresight Reserves and Murray Energy. In accordance with the governing documents of Foresight Energy GP LLC, Foresight Reserves and Murray Energy have the right to appoint all members of the board of directors of our general partner, including those directors meeting the independence standards established by the NYSE. The directors are appointed by Foresight Reserves and Murray Energy in proportion to their respective voting interests in our general partner: Foresight Reserves’ voting interest is approximately 66% and Murray Energy’s voting interest is approximately 34%. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.
The board of directors of our general partner has six directors, three of whom are independent as defined under the standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded limited partnership, like us, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act.
Christopher Cline and Robert D. Moore allocate their time between managing our business and affairs and the business and affairs of Foresight Reserves and Murray Energy, respectively. The amount of time that they devote to our business and the business of the other companies varies in any given period based on a variety of factors. We expect that they will continue to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. However, their duties to their other obligations may prevent them from devoting sufficient time to our business and affairs.
Neither our general partner nor Foresight Reserves receives any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner for all expenses it incurs and payments it makes on our behalf. A wholly-owned subsidiary of Murray Energy provides certain management and administration services to the Partnership for a quarterly fee, which is 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.
Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates.
The following table shows information for the executive officers and directors of our general partner as of March 11, 2016. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers (other than Robert D. Moore) serve at the discretion of the board of directors. Under the organizational documents of our general partner, any renewal or replacement of Robert D. Moore as Chief Executive Officer requires the consent of Murray Energy. There are no family relationships among any of our directors or executive officers. Some of our directors also serve as executive officers of Foresight Reserves.
Christopher Cline is the Chairman of our general partner’s board of directors and Principal Strategy Advisor, positions he has held since our inception in 2012. Mr. Cline has more than 30 years of experience in the coal industry. After attending Marshall University, he developed and operated over 25 coal mining, processing and transportation facilities in the Appalachian region and the Illinois Basin, including some of the most productive longwall mining operations in the country. During the past five years, Mr. Cline has focused his efforts primarily on developing Foresight Energy. The experience and qualifications that led to the conclusion that Mr. Cline should serve as a Director include his formation and leadership of the Partnership since its inception, significant and broad experience in the coal industry, and his proven business acumen.
Robert D. Moore is a member of the Board of Directors and President and Chief Executive Officer of our general partner. Mr. Moore has more than 20 years of experience in management, operations, finance, accounting, and acquisitions in the United States coal industry. He has been our President and Chief Executive Officer, and a member of our Board of Directors, since May 2015. Mr. Moore also serves as Murray Energy Corporation’s Executive Vice President, Chief Operating Officer, and Chief Financial Officer, a position he has held since August 2012, and he is a member of Murray Energy’s Board of Directors. Mr. Moore has served as Murray Energy Corporation’s Executive Vice President and Chief Financial Officer since September 2007. Mr. Moore was integral in Murray Energy’s $3.05 billion acquisition of Consolidation Coal Company, from CONSOL Energy Inc., in December 2013. From 1993 to 2007, Mr. Moore held a number of financial and other senior management positions within Murray Energy. Mr. Moore received his Bachelor of Science degree from The Ohio State University in Accounting and Finance, his Certified Public Accountant certification from the State of Ohio, and his Master of Business Administration from The Ohio State University. The experience and qualifications that led to the conclusion that Mr. Moore should serve as a member of the Board of Directors of our general partner include his extensive knowledge of the coal industry and his financial expertise.
G. Nicholas Casey is an independent member of the Board of Directors of our general partner and a member of the Audit Committee. Mr. Casey was appointed to the Board of Directors on September 9, 2015. Mr. Casey is currently a member of Lewis Glasser Casey & Rollins, PLLC, attorneys at law, where he served as managing member from 2008 to 2015. He is also a member of LGCR Government Solutions LLC, where he served as managing member from 2008 to 2014. Additionally, Mr. Casey serves as Treasurer of the American Bar Association and as a member of its Board of Governors. He also serves on the Board of Directors of Security National Trust, Inc. Mr. Casey received an undergraduate degree in accounting from the University of Kentucky and a law degree from West Virginia University College of Law. The experience and qualifications that led to the conclusion that Mr. Casey should serve as a Director include his extensive experience in accounting, business development, financing, real estate and management matters.
Bennett K. Hatfield is an independent member of the Board of Directors of our general partner and a member of the Audit Committee. He was appointed to the Board of Directors on June 8, 2015. Mr. Hatfield served as President and Chief Executive Officer of Patriot Coal Corporation from October 2012 to April 2015; President and Chief Operating Officer from May 2012 to October 2012; and Executive Vice President and Chief Operating Officer from September 2011 to May 2012. Prior to that, Mr. Hatfield served as President, CEO and a Director of International Coal Group, from 2005 until June 2011 when it was acquired. Mr. Hatfield previously served as President, Eastern Operations of Arch Coal, Inc., from March 2003 until March 2005, and Executive Vice President and Chief Commercial Officer of Coastal Coal Company, from December 2001 through February 2003. Mr. Hatfield joined Massey Energy Company in 1979, where he served in a number of management roles, most recently as Executive Vice President and Chief Operating Officer, from June 1998 through December 2001. The experience and qualifications that led to the conclusion that Mr. Hatfield should serve as a member of the Board of Directors of our general partner include his extensive knowledge of the coal industry and his financial expertise.
Daniel S. Hermann is an independent member of the Board of Directors of our general partner and also serves as Chairman of the Audit Committee. He was appointed to the Board of Directors in September 2014. Mr. Hermann is the retired Chief Executive Officer of AmeriQual Group, LLC, a food packaging company and leading supplier of field rations to the United States Department of Defense. Prior to joining AmeriQual, he spent 23 years with Black Beauty Coal Company, where he held various titles, including President and Chief Executive Officer and Chief Financial Officer. During his tenure at Black Beauty, Mr. Hermann was part of a
successful team that grew the company into the largest coal producer in the Illinois Basin. In 2003, Black Beauty was acquired by Peabody Energy and Mr. Hermann spent the next two years as Group Executive for Peabody’s Midwest Division. Mr. Hermann is currently on the Board of Directors of Deaconess Health Systems and serves as a member of the Finance and Compensation Committees. He also serves as a Director of Fifth Third Bank Southern Indiana. Mr. Hermann holds a Bachelor of Science degree from Indiana State University in Evansville and is a certified public accountant. The experience and qualifications that led to the conclusion that Mr. Hermann should serve as a member of the Board of Directors of our general partner and as Chairman of the Audit Committee include his extensive knowledge of the coal industry and his financial expertise.
Paul H. Vining is a member of the Board of Directors of our general partner. He was appointed to the Board of Directors on January 1, 2016. Mr. Vining is currently the CEO of The Cline Group LLC, as well as President of Foresight Reserves LP and CEO of Cutlass Collieries LLC, the international development arm of The Cline Group. Mr. Vining previously served as president of Alpha Natural Resources (“Alpha”) from April 2012 until January 2015, which filed for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in August 2015. Prior to that, he served as executive vice president and chief operating officer of Alpha from May 2011 until April 2012. Mr. Vining served as chief executive officer of White Oak Resources from October 2010 until April 2011. He served as president and chief operating officer of Patriot Coal Corporation from July 2008 until September 2010, which filed for reorganization under Chapter 11 of the Bankruptcy Code in July 2012. Mr. Vining has over 35 years of experience in the coal business which in addition to the above includes being the chief executive officer of Magnum Coal Company, the top executive sales and trading positions for both Arch Coal and Peabody Energy, and key sales and commercial roles at AGIPCOAL USA, Island Creek Coal Company and A. T. Massey Coal Company. Mr. Vining earned his Bachelor of Science in Chemistry from the College of William and Mary as well as his Bachelor of Science in Mineral Engineering and Master of Science in Extractive Metallurgy from Columbia University’s Henry Krumb School of Mines. The experience and qualifications that led to the conclusion that Mr. Vining should serve as a member of the Board of Directors of our general partner include his extensive knowledge of the coal industry and his financial expertise.
Rashda M. Buttar is the Senior Vice President-General Counsel & Corporate Secretary of our general partner. Before joining the Partnership in September 2011, Ms. Buttar served as Vice President, Associate General Counsel and Corporate Secretary of Patriot Coal Corporation from 2007 to August 2011. Prior to joining Patriot Coal Corporation, Ms. Buttar served as the Assistant General Counsel and Assistant Corporate Secretary of TALX Corporation from 2003 to 2007. Ms. Buttar received her Juris Doctor from Saint Louis University School of Law and her undergraduate degree in Russian and Eastern European Studies and Political Science from Saint Louis University.
James T. Murphy is the Principal Financial Officer and Chief Accounting Officer of our general partner. Mr. Murphy has served is this capacity for our General Partner since June 2015. Mr. Murphy served as Controller of the General Partner of Foresight Energy LLC (the predecessor of the Partnership) from 2011 to 2015, and as VP & Controller of the General Partner or Foresight Energy LLC from December 2014 to June 2015. Mr. Murphy served as the Assistant Controller of Arch Coal Inc. from 2008 to 2011. Mr. Murphy is a certified public accountant and holds a Bachelor of Science in Business Administration from University of Missouri St. Louis.
Director Independence
Our board has determined that Messrs. Casey, Hatfield and Hermann are independent as defined by the rules of the NYSE and under Rule 10A-3 promulgated under the Exchange Act.
Non-management Director Meetings
Our non-management directors meet in an executive session at each regularly scheduled Board of Directors meeting. The role of presiding director at each such meeting is rotated amount the non-management directors.
Communications with the Board of Directors
Interested parties may contact the chairpersons of any of our board committees, our board’s independent directors as a group or our full board in writing by mail to Foresight Energy LP, One Metropolitan Square, 211 North Broadway, Suite 2600, St. Louis, MO 63102, Attention: Corporate Secretary. All such communications will be delivered to the director or directors to whom they are addressed.
Committees of the Board of Directors
The board of directors of our general partner has an audit committee and a conflicts committee. We do not currently have a compensation committee, but rather the board of directors of our general partner approves equity grants to directors and employees.
Audit Committee
We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. Messrs. Casey, Hatfield and Hermann currently serve on our audit committee. The board of directors of our general partner has determined that Mr. Hermann qualifies as an “audit committee financial expert,” as such term is defined under SEC rules.
The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee and our management.
Conflicts Committee
The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Foresight Reserves and Murray Energy, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. The independent members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is adverse to the interest of the partnership. Any matters approved by the conflicts committee are conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
Corporate Governance
The board of directors of our general partner has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance. The board of directors of our general partner has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to all employees and officers of Foresight Energy LP and Foresight Energy GP LLC, including its principal executive officer, principal financial and accounting officer, and members of the board.
Available Information
We file annual, quarterly and current reports, and amendments to those reports, and other information with the Securities and Exchange Commission (“SEC”). You may access and read our filings without charge through the SEC's website, at www.sec.gov. You may also read and copy any document we file at the SEC's public reference room located at 100 F Street, N.E., Room 1580, and Washington, D.C. 20549. Please call the SEC at 1-800- SEC-0330 for further information on the public reference room.
We also make the documents listed above, including our Corporate Governance Guidelines and Code, available without charge under the Investors Relations tab of our website, www.foresight.com, Our annual, quarterly and current reports, and amendments to those reports, and other information filed with the SEC, are posted to the website as soon as practicable after we file or furnish them with the SEC. The information on our website is not part of this Annual Report on Form 10-K.
Item 11.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Overview of Compensation Program
The board of directors of our general partner (the “Board”) is responsible for establishing and implementing our compensation programs. The Board seeks to ensure that the total compensation paid to our executive officers is fair, reasonable, and competitive. This compensation discussion and analysis (“CD&A”) provides information about our compensation objectives and policies for 2015 for our principal executive officer, our principal financial officer and our other most highly compensated executive officers and is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. This CD&A provides a general description of our compensation programs and specific information about its various components.
Throughout this discussion, the following individuals are referred to collectively as the “Named Executive Officers” and are included in the Summary Compensation Table:
·
Robert D. Moore, President - Chief Executive Officer;
·
James T. Murphy, Vice President & Chief Accounting Officer;
·
Rashda M. Buttar, Senior Vice President -General Counsel & Corporate Secretary;
·
Michael J. Beyer, President-Former Chief Executive Officer (through May 31, 2015);
·
Oscar A. Martinez, Senior Vice President-Former Chief Financial Officer (through November 12, 2015); and
·
Christopher N. Moravec, Executive Vice President-Former Chief Commercial Officer (through June 12, 2015).
Compensation Philosophy and Objectives
We believe our success depends on the continued contributions of our Named Executive Officers. While we do not maintain a formal compensation philosophy, our executive compensation programs are designed for the purpose of attracting, motivating and retaining experienced and qualified executive officers with compensation that recognizes individual merit and overall business results. Our compensation programs are also intended to support the attainment of our strategic objectives by tying the interests of our Named Executive Officers to those of our unitholders through operational and financial performance goals and equity based compensation.
The principal elements of our executive compensation programs for the 2015 year were base salary and annual cash incentives and the employee benefit arrangements made available to our full-time employees generally. The employee benefit arrangements provided to our Named Executive Officers consist of life and health insurance benefits, a qualified safe harbor 401(k) savings plan and paid vacation and holidays. While equity compensation awards were granted to certain Named Executive Officers during the first quarter of 2015, the awards related to services provided by those officers during the 2014 year. We do not consider equity compensation awards to be a principal element of the 2015 compensation program.
Compensation Practices and Procedures
Role of the Board of Directors
We do not have a compensation committee. All compensation decisions with respect to our Named Executive Officers are made by the Board. In establishing and implementing our compensation programs, the responsibility of the Board included:
·
Reviewing base salary and incentive compensation levels as recommended by our President & Chief Executive Officer; and
·
Administering our equity based compensation plans, including selecting to whom grants under any such plans are made and determining the terms and type of any such grant.
Role of Principal Strategy Advisor in Compensation Decisions
As a Director and our Principal Strategy Advisor, Mr. Cline is closely involved in evaluating our overall executive compensation programs. Mr. Cline’s specific role in determining compensation is to make recommendations to the other members of the Board on general compensation matters with respect to applicable Named Executive Officers. In making such recommendations, Mr. Cline takes into account his general business knowledge and experience and his specific knowledge of the market in which we compete for talent.
Role of President and Chief Executive Officer in Compensation Decisions
In the role of President and Chief Executive Officer, both Messrs. Beyer and Moore assisted in determining executive compensation by making recommendations to the other members of the Board on compensation decisions for officers other than themselves based upon their assessment of the individual performance of each executive officer and our overall performance. In addition, in recommending specific levels or components of compensation, Messrs. Beyer and Moore, like Mr. Cline, took into account their general business knowledge and experience and specific knowledge of the market in which we compete for talent.
Role of Compensation Consultant
During 2015, we did not retain the services of a compensation consultant or conduct benchmarking or specific market review of our compensation levels or practices. Instead, our compensation levels and practices are established by the Board based upon the recommendations of our Principal Strategy Advisor and our then-current President and Chief Executive Officer.
Components of the Compensation Program
For the year ended December 31, 2015, the principal components of compensation for the Named Executive Officers were base salary and annual cash incentives. Equity awards granted in the first quarter of 2015 related to services provided to us in the 2014 year and we have determined not to grant equity awards with respect to services provided in the 2015 year.
Base Salary
We established the base salary for each Named Executive Officer based on consideration of many factors, including the individual’s performance and experience, the pay of others on the executive team and our Board’s assessment of the market in which we compete for talent. The base salary compensation is intended to provide security and a reliable, but not excessive, source of income to our Named Executive Officers. Our Board periodically reviews the base salaries of our Named Executive Officers and has the discretion to make adjustments based upon any factor it deems relevant, including those described above. Salaries paid to each of our Named Executive Officers for the 2015 year are reflected in the Summary Compensation Table.
Our Board did not make base salary decisions for Mr. Moore in 2015, as his compensation is not paid directly by us. Although Mr. Moore provides employment services to both Murray Energy Corporation and to us, he also has many overlapping roles and duties due to the close relationship that we maintain with Murray Energy Corporation following their investment in us. We will pay a predetermined annual fee to Murray Energy Corporation for Mr. Moore’s services. While there is not a specific allocation to us with respect to Mr. Moore’s services, we have determined that it would be appropriate to allocate a portion of the total compensation that he receives from Murray Energy Corporation to us within the Summary Compensation Table below. The allocated amount was determined by looking at the time that Mr. Moore spends at each of the respective companies as well as the time spend in his duties that may overlap and benefit both companies. It was determined that allocating $250,000 of Mr. Moore’s compensation to us was a reasonable estimate of the portion of the payment that we make to Murray Energy Corporation for Mr. Moore’s services.
Annual Cash Incentives
We provide each of our Named Executive Officers with an opportunity to earn an annual cash incentive. Following the completion of each year, the Board determines the amount of each Named Executive Officer’s annual cash incentive for such year, if any, based upon their subjective determination of such individual’s respective individual contributions to the Partnership, to successful mining operations and to our overall performance during the year, in the area for which they are responsible. Such annual cash incentives to our Named Executive Officers are discretionary and therefore not based upon any pre-established performance metrics or targeted to any specific level of compensation.
For 2015, the Board determined the annual cash incentive for our current Named Executive Officers to be as follows. Our Named Executive Officers that were not employed by us at the end of the year did not receive an annual bonus award with respect to the 2015 year.
Retention Bonuses
With respect to the 2015 year, certain Named Executive Officers also received transaction-related retention bonuses. Ms. Buttar and Messrs. Moravec, Murphy and Martinez received a retention bonus in connection with our transaction with Murray Energy Corporation. The retention bonus consisted of a cash amount of $175,000 for Ms. Buttar, $200,000 for Mr. Martinez, $425,000 for Mr. Murphy and $137,500 for Mr. Moravec, as well as the accelerated vesting of any unvested equity compensation awards held by the executives at the time of payment. The retention bonus agreements provided that the retention bonus would become paid (or settled, as applicable) to the executives in the event that they remained continuously employed with us from March 2015 to either June 2015 or September 2015. The retention bonus would also have become payable to the executives if they were involuntarily terminated prior to the end of the retention period, which was defined as a termination of employment other than a resignation by the executive, a termination due to death or disability, or a termination by us for cause. Each of the applicable Named Executive Officers remained employed through their respective retention period and received the retention bonus during 2015.
Equity Compensation Awards
In connection with our initial public offering, we established a long-term incentive plan which permits the Board to grant a variety of different types of equity compensation awards. The equity compensation awards granted to certain Named Executive Officers in February or March 2015 for 2014 service were in the form of unit awards that vested immediately or phantom units, which were designed with a time-based vesting schedule. In connection with the transaction with Murray Energy Corporation, all outstanding equity compensation awards became vested and settled during 2015.
Retirement and Other Benefits
Our Named Executive Officers are entitled to participate in group health, term life, and similar benefit plans available to all of our employees on the same terms as such employees. During 2015, Foresight Energy Services LLC maintained a plan intended to provide benefits under section 401(k) of the Code pursuant to which eligible employees are permitted to contribute portions of their compensation into a tax-qualified retirement account (the “401(k) Plan”). For 2015, the plan provided safe harbor matching contributions equal to 100% of the first 3% of eligible compensation contributed by a participant to his or her account and 50% of the next 2% of eligible compensation contributed. Each of the Named Executive Officers participated in the 401(k) Plan during the 2015 year and received company contributions into their accounts, as noted within the Summary Compensation Table below.
Perquisites
The Partnership may provide a limited amount of perquisites and personal benefits to the current Named Executive Officers. With respect to the Named Executive Officers that are no longer employed by us, we previously provided certain housing and car allowances, and assisted with the payment of country club dues for business purposes. Amounts that related to these perquisites for the former executives are provided within the Summary Compensation Table below. On a going-forward basis we do not intend to provide the Named Executive Officers with benefits that are materially different than those provided to our employees generally.
Employment Agreements, Severance Benefits
We did not generally maintain any employment agreements or severance plans which covered our Named Executive Officers during the 2015 year. The 2015 retention bonus agreements that we maintained with Ms. Buttar and Mr. Murphy did provide for the acceleration of outstanding equity awards and a cash bonus payment in the event that they were involuntarily terminated during an applicable retention period, but the 2015 retention bonus agreements were settled during the 2015 year.
Tax and Accounting Implications
Deductibility of Executive Compensation
We are a limited partnership and not a corporation for U.S. federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for federal income tax purposes.
Accounting for Equity-Based Compensation
We granted equity compensation awards in previous years. For our unit-based compensation arrangements, we recorded compensation expense over the vesting period of the awards, as discussed further in Part II. “Item 8, Financial Statements and Supplementary Data, Note 19 - Equity-Based Compensation” in this Annual Report on Form 10-K.
Risk Assessment Related to our Compensation Structure.
We believe our compensation programs for our Named Executive Officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We also believe our compensation programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We believe we have allocated our compensation among base salary and short and long-term compensation programs in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for the Named Executive Officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of an operating segment. We have historically granted phantom units rather than unit options for equity awards because restricted units retain value even in a depressed market.
Anti-Hedging Policies
Our insider trading policy prohibits our directors and executive officers from engaging in any hedging or similar practices designed to offset a decrease in the price of our units.
Report of Board of Directors
We do not have a compensation committee. Our Board has reviewed and discussed the Compensation Discussion and Analysis with management and, based on such review and discussions approved the Compensation Discussion and Analysis included herein.
Executive Compensation
The following table summarizes the compensation we paid during the years ended December 31, 2015, 2014 and 2013, as applicable, to our Named Executive Officers.
Summary Compensation Table
(1)
We do not pay a base salary directly to Mr. Moore. Amounts reflected within the “Salary” column for Mr. Moore reflect the portion of his compensation that was determined appropriate to allocate to us pursuant to the services agreement that we maintain with Murray Energy Corporation. Further descriptions of the service agreement and our methodology for determining Mr. Moore’s allocated salary costs are described within the Compensation Discussion and Analysis above.
(2)
Amounts included within the Bonus column reflect annual incentive bonuses as well as retention bonuses paid by us during the 2015 year. Mr. Martinez also received a bonus separate from our annual incentive awards and his severance in the amount of $250,000. With respect to Mr. Moravec, Ms. Buttar and Mr. Murphy, the amounts also include a separate retention bonus paid solely by one of our sponsors, Foresight Reserves LP.
(3)
Unit award amounts reflect the aggregate grant date fair value of unit and phantom unit awards granted during the periods presented calculated in accordance with Accounting Standards Codification 718, disregarding forfeitures. See Note 19 to our consolidated financial statements for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards.
(4)
“All Other Compensation” for 2015 consisted of the following: (i) for Mr. Beyer: his country club membership dues that we paid on his behalf totaled $23,000, $11,633 for annual life insurance premiums paid on a life insurance policy for his benefit and matching contributions made to the 401(k) Plan on his behalf; (ii) for Mr. Martinez: $250,000 for a severance bonus and $10,594 for annual life insurance premiums paid on a life insurance policy for his benefit and matching contributions made to the 401(k) Plan on his behalf; (iii) for Mr. Moravec: a housing allowance of $28,500, a car allowance of $12,498, and $11,761 annual life insurance premiums paid on a life insurance policy for his benefit and matching contributions made to the 401(k)
Plan on his behalf; (iv) for Ms. Buttar: $10,995 for annual life insurance premiums paid on a life insurance policy for her benefit and matching contributions made to the 401(k) Plan on her behalf, and (v) for Mr. Murphy: $9,323 for annual life insurance premiums paid on a life insurance policy for his benefit and matching contributions made to the 401(k) Plan on his behalf.
Grants of Plan-Based Awards
The following table sets forth, for each Named Executive Officer, information about grants of plan-based awards made during the year ended December 31, 2015. We did not grant any option or non-equity incentive plan compensation during 2015.
(1)
This column reflects the number of unit awards and phantom unit awards granted to each Named Executive Officer under our Long-Term Incentive Plan during 2015. All phantom unit awards reflected in the table above received accelerated vesting in connection with the Murray Energy, therefore they are no longer outstanding as of the end of the 2015 year.
(2)
Reflects the aggregate grant date fair value of unit and phantom unit awards granted during the periods presented calculated in accordance with ASC 718, disregarding forfeitures. See Part II. “Item 8, Financial Statements and Supplementary Data,” Note 19. Equity-Based Compensation” in this Annual Report on Form 10-K for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards.
Our executive compensation policies and practices, pursuant to which the compensation set forth in the Summary Compensation Table and the Grants of Plan-Based Awards Table was paid or awarded, are described above in the section titled "Executive Compensation-Compensation Discussion and Analysis.”
Employment Agreements
We do not maintain any employment agreements with our Named Executive Officers.
Salary and Cash Bonus in Proportion to Total Compensation
The following table sets forth the percentage of each Named Executive Officer’s total compensation for the year ended December 31, 2015 that was paid in the form of base salary and bonus (including annual cash incentive awards and discretionary amounts, if any). Mr. Moore has not been included due to the fact that we do not directly pay his compensation.
Outstanding Equity Awards at Fiscal Year-End
None of the Named Executive Officers held outstanding equity compensation awards as of December 31, 2015.
Option Exercises and Units Vested
The following table reflects the lapse of restrictions, during the year ended December 31, 2015, on phantom unit awards held by our Named Executive Officers. No Named Executive Officer held option awards during 2015.
(1)
Value realized with respect to the unit awards is based upon the closing price of our common units on the NYSE on the date of vesting.
Pension and Nonqualified Deferred Compensation Benefits
None of our Named Executive Officers participate in any defined benefit pension or nonqualified deferred compensation plans.
Potential Payments upon Termination or Change in Control
Generally, none of our Named Executive Officers are parties to any plans or agreements which provide for benefits in connection with termination of employment or upon a change of control.
Director Compensation
The compensation of the directors of our general partner is set by the Board. Messrs. Cline, Moore and Vining received no director compensation. The directors who are eligible to receive compensation for their services to our Board will receive $125,000 in cash as an annual retainer fee, as well as a $15,000 retainer for services to our audit committee. The eligible directors will also receive an annual phantom unit award in the amount of $75,000 which will be designed to vest pro-rata over a three year period.
(1)The values set forth reflect awards of phantom units and are based on the grant date fair value of the awards computed in accordance with FASB ASC 718 (disregarding the impact of estimated forfeitures related to service-based vesting conditions). The grant date fair value is computed based upon the closing price of Foresight Energy LP's common units on the date of grant. As of December 31, 2015, Mr. Harrison, Mr. Hermann, Mr. Hatfield and Mr. Casey had unvested unit awards of 0 units, 14,443 units, 5,133 units and 9,907 units, respectively.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth certain information as of March 11, 2016, regarding the beneficial ownership of common and subordinated units held by (a) each director of our managing general partner, (b) each executive officer of our managing general partner, (c) all such directors and executive officers as a group, and (d) each person known by our managing general partner to be the beneficial owner of 5% or more of our common units. Our managing general partner is owned by 65.34% by Foresight Reserves, 34.0% by Murray Energy Corporation, and 0.66% by Michael J. Beyer, the former Chief Executive Officer of our general partner. The address of each of Foresight Energy GP LLC, Christopher Cline, the Cline Trust Company and each of the directors and officers reflected in the table below is 3801 PGA Blvd., Suite 903, Palm Beach Gardens, Florida 33410. The percentage of units beneficially owned is based on 65,192,646 common units and 64,954,691 subordinated units outstanding.
* Less than one percent.
(1)
Murray Energy Corporation’s address is: 46226 National Road, St. Clairsville, OH, 43950. Murray Energy Corporation owns a 34% voting interest in our general partner. There are no options, warrants or other rights or obligations outstanding that are currently exercisable, or exercisable within 60 days, into common units. Robert E. Murray may be deemed to have voting and investment power over the common units. The selling unitholder is not a registered broker dealer and is not an affiliate of a registered broker dealer.
(2)
Donald R. Holcomb, the manager of Cline Trust Company, may be deemed to have voting and investment power over the common units held of record by Cline Trust Company. The members of the Cline Trust Company are four trusts of which Mr. Holcomb is trustee, each of which owns an approximately equal interest in the Cline Trust Company: (i) The Alex T. Cline 2004 Irrevocable Trust, the beneficiary of which is Alex T. Cline, a child of Mr. Cline, (ii) The Candace L. Cline 2004 Irrevocable Trust, the beneficiary of which is Candace L. Cline, a child of Mr. Cline, (iii) The Christopher L. Cline 2004 Irrevocable Trust, the beneficiary of which is Christopher L. Cline, a child of Mr. Cline, and (iv) The Kameron N. Cline 2004 Irrevocable Trust, the beneficiary of which is Kameron N. Cline, a child of Mr. Cline. Mr. Holcomb is the former Vice President, Secretary and Treasurer of Cline Resource Development Company d/b/a The Cline Group (“CRDC”), which is wholly owned by Christopher Cline. Mr. Holcomb also served as the Chief Financial Officer of Foresight Reserves until March 31, 2013 and currently serves on the Board of Directors of Natural Resource Partners LP, an affiliate of the Partnership. The selling unitholder is not a registered broker dealer and is not an affiliate of a registered broker dealer.
(3)
Units held personally by Christopher Cline, as an individual, are included in the 5% Unitholders section above.
Equity Compensation Plan Information
The following table sets forth information with respect to compensation plans under which our equity is authorized for issuance.
(1)
The Long-Term Incentive Plan (“LTIP”) was adopted by our general partner in June 2014 in connection with our IPO and did not require approval by our unitholders. The LTIP contemplates the issuance of up to 7,000,000 common units to satisfy awards under the LTIP.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence
Certain Relationships and Related Transactions
The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, cannot be presumed to be the result of arm’s-length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.
Affiliated entities principally include: (a) Entities owned and controlled by Chris Cline, the majority owner of our general partner, (b) Murray Energy Corporation, owner of a 34% interest in our general partner and owner of all of the outstanding subordinated units, and (c) NRP and its affiliates, for which Chris Cline owns a beneficial interest in the general partner and limited partner interests.
Murray Energy also has an option, subject to certain conditions described below, to purchase an additional 46% of the voting interests in FEGP for $25 million during a five-year period. Murray Energy’s ability to exercise the option is conditioned upon (i) the exercise of the call option with respect to Colt LLC, a wholly-owned subsidiary of Foresight Reserves and (ii) the refinancing of the FELP notes and FELP’s existing credit facilities on terms reasonably acceptable to Foresight Reserves, or any other transaction (whether by amendment, waiver or a consent solicitation) that would have the effect of eliminating the “change of control” provisions of the FELP notes and FELP’s existing credit facilities with respect to the exercise of the option.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Foresight Energy LP.
Formation Stage
The consideration received by Foresight Reserves and a member of management for the contribution of their interests
•
Common and subordinated units of 47,238,895 and 64,738,895, respectively and
•
the incentive distribution rights
The net proceeds from the IPO were used to pay a $115.0 million special distribution to Foresight Reserves and a member of management and to repay $210.0 million of outstanding Term Loan principal.
Operational Stage
Distributions to our general partner and its affiliates
We will generally make cash distributions 100% to the unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.
Payments to our general partner and its affiliates
Our general partner does not receive a management fee or other compensation for its management of Foresight Energy LP, but we reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Liquidation Stage
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Registration Rights Agreement
Under our partnership agreement, we have agreed to register for resale under the Securities Act of 1933 and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration
rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.
2013 Reorganization
In August 2013, Foresight Energy LLC underwent a restructuring (the “2013 Reorganization”), pursuant to which:
•
Foresight Energy LLC distributed its 100% ownership interest in Sitran (which was a wholly-owned subsidiary that conducted our transloading operations on the Ohio River) and Adena Resources (which was a wholly-owned subsidiary that provided water and other miscellaneous rights) to its owners. Each of Williamson, Sugar Camp, Hillsboro and Macoupin entered into a transloading and storage agreement with Sitran for the unloading of coal from railcars into stockpiles at Sitran and for the loading of coal from such stockpiles into barges;
•
Foresight Energy LLC distributed certain Hillsboro transportation assets known as the “Clean Coal Handling System,” along with the surface property underlying those assets, to Hillsboro Transport LLC (“Hillsboro Transport”), a subsidiary of Foresight Reserves. Hillsboro and Hillsboro Transport then entered into a throughput agreement for Hillsboro Transport to operate and maintain the Clean Coal Handling System to transport and load clean coal;
•
Each of Williamson, Sugar Camp, Hillsboro and Macoupin entered into agreements with Adena Resources for the use of certain water rights and facilities owned or controlled by Adena Resources;
•
Savatran and Hillsboro distributed to Foresight Reserves, in May 2014, approximately 1,900 acres of surface land not needed for current or projected future operations with a carrying value of $12.2 million.
•
Hillsboro and Macoupin entered into development agreements with Colt, pursuant to which Hillsboro and Macoupin have the right to offer Colt the ability to develop additional longwall coal mines and associated transportation infrastructure in coal reserves leased by Colt. If Colt develops a mine, Hillsboro and Macoupin, under their respective agreements, would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement; and
•
Sugar Camp entered into a development agreement with Ruger, pursuant to which Sugar Camp has the right to offer Ruger the ability to develop additional longwall coal mines and associated transportation infrastructure in coal reserves leased by Ruger to Sugar Camp or where Sugar Camp has the right to mine by virtue of an overriding royalty agreement with Ruger. If Ruger develops a mine, Sugar Camp would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement.
Sitran Agreements
In connection with the 2013 Reorganization, each of Williamson, Sugar Camp, Hillsboro and Macoupin entered into a transloading and storage agreement with Sitran. These agreements provide for the unloading of coal from railcars into stockpiles at Sitran and for the loading of coal from stockpiles into barges. Under these agreements each mine will pay Sitran a fee for each ton of coal offloaded, stored or transloaded at Sitran’s facility. Each agreement has an initial term of three years and will renew automatically for successive one-year periods unless terminated by either party. For the years ended December 31, 2014 and 2013, the mines paid $9.3 million and $3.1 million, respectively, in transloading fees with Sitran. On February 25, 2015, Foresight Reserves and a member of management contributed Sitran to the Partnership (see “Contribution of Assets” below).
Hillsboro Throughput Agreement
Concurrent with the 2013 Reorganization, a throughput agreement was entered into between Hillsboro and Hillsboro Transport for Hillsboro Transport to operate the Clean Coal Handling System for Hillsboro. The agreement, which has an initial term of ten years, grants Hillsboro Transport the right to be the exclusive provider of clean coal handling services for Hillsboro. After the initial ten-year term of the throughput agreement, the parties can agree to continue renewing the agreement in five-year increments (up to 16 times). At the expiration of each term, Hillsboro has an option to acquire the Clean Coal Handling System for its then fair value. As compensation for operating and maintaining the Clean Coal Handling System, Hillsboro Transport will receive $0.99 per ton for each ton of coal loaded through the Clean Coal Handling System, subject to a minimum quarterly payment of $1.25 million. Subsequent to the 2013 Reorganization date, Hillsboro Transport was determined to be a variable interest entity and Hillsboro consolidates Hillsboro Transport as the primary beneficiary. See our audited historical consolidated financial statements, and notes thereto, included elsewhere in this Annual Report on Form 10-K. For the years ended December 31, 2014 and 2013, Hillsboro Transport earned net income of $3.8 million and $2.0 million, respectively, under the throughput agreement, which was recorded as income attributable to noncontrolling interests in our consolidated statements of operations. On February 25, 2015, Foresight Reserves and a member of management contributed Hillsboro Transport to the Partnership (see “Contribution of Assets” below).
Adena Water Resources Agreements
Adena Resources has various contractual water rights contracts with various state and local governments that are used to provide water to certain of our mines. Concurrent with the distribution of Adena Resources to Foresight Reserves, each of Williamson, Sugar Camp, Hillsboro and Macoupin entered into an agreement with Adena Resources providing for water resources to be available at each of the mines for use in mining operations. The agreements have an initial term of three years and automatically renew for successive periods of one year unless either party opts out of the agreement. Under the agreements, the mines pay Adena Resources the actual cost incurred by Adena Resources in furnishing water to the mine, including any capital expenditures necessary to fulfill its obligations under the agreements, plus an annual fee of $10,000. Subsequent to the 2013 Reorganization date, Adena Resources was determined to be a variable interest entity and we continue to consolidate Adena Resources as the primary beneficiary. See our audited historical consolidated financial statements included elsewhere in this Annual Report on Form 10-K. On February 25, 2015, Foresight Reserves and a member of management contributed Adena Resources to the Partnership (see “Contribution of Assets” below).
Hillsboro 2 and 3 Development Agreement
In connection with the 2013 Reorganization, Hillsboro entered into a development agreement with Colt (the “Hillsboro Development Agreement”). Pursuant to the Hillsboro Development Agreement, Hillsboro put in place the right to offer Colt the ability to develop one or two additional longwall coal mines, previously identified as the “Hillsboro 2” and “Hillsboro 3” longwall mines and associated transportation infrastructure in coal reserves leased by Colt to Hillsboro. If Colt accepts the offer to develop a mine and associated transportation related infrastructure, Hillsboro will automatically acquire the option to purchase the fully developed mines, but not the transportation assets, for fair market value. Hillsboro will have the right to exercise this fair market value purchase option during a twelve month period that begins when Colt has first sold 100,000 tons of clean coal produced by the longwall method from any new mine. Hillsboro will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Colt develops a mine and Hillsboro elects not to exercise its option to purchase the mine, Hillsboro will surrender its rights to the coal associated with that mine under its lease with Colt.
Macoupin Low Sulfur Longwall Development Agreement
In connection with the 2013 Reorganization, Macoupin entered into a development agreement with Colt (the “Macoupin Development Agreement”). Pursuant to the Macoupin Development Agreement, Macoupin put in place the right to offer Colt the ability to develop one longwall coal mine and associated transportation infrastructure in coal reserves previously identified by Macoupin for a low sulfur longwall mine. If Colt accepts the option to develop the mine and associated infrastructure, then Macoupin will automatically acquire the option to purchase the fully developed mine, but not the transportation assets, for fair market value. Macoupin will have the right to exercise this fair market value purchase option during a twelve month period that begins when Colt has first sold 100,000 tons of clean coal produced by the longwall method from the new mine. Macoupin will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Colt develops a mine and Macoupin elects not to purchase the mine, Macoupin will surrender its rights to the coal associated with that mine under its lease with Colt.
Sugar Camp 3 and 4 Development Agreement
In connection with the 2013 Reorganization, Sugar Camp entered into a development agreement with Ruger (the “Sugar Camp Development Agreement”). Pursuant to the Sugar Camp Development Agreement, Sugar Camp put in place the right to offer Ruger the ability to develop one or two additional longwall coal mines and associated transportation infrastructure in coal reserves either leased by Ruger to Sugar Camp or reserves where Ruger has granted Sugar Camp the right to mine coal and pay a royalty to Ruger. These areas have been previously identified by Sugar Camp as the “Sugar Camp 3” and “Sugar Camp 4” longwall mines. If Ruger accepts the option to develop the mine and associated infrastructure, then Sugar Camp will automatically acquire the option to purchase the fully developed mine, but not the transportation assets, for fair market value. Sugar Camp will have the right to exercise this fair market value purchase option during a twelve month period that begins when Ruger has first sold 100,000 tons of clean coal produced by the longwall method from any new mine. Sugar Camp will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Ruger develops a mine and Sugar Camp elects not to purchase the mine, Sugar Camp will surrender its rights to the coal associated with that mine under its lease and overriding royalty agreement with Ruger.
Contribution of Assets
On February 25, 2015, Foresight Reserves and a member of management contributed 100% of the equity of Sitran, Adena and Hillsboro Transport to the Partnership. These entities were contributed for no consideration and had an aggregate net book value of approximately $60.6 million on the contribution date.
Transactions with Natural Resource Partners, L.P. and its Affiliates
We have engaged in a series of transactions with NRP and its affiliates, an entity in which Christopher Cline directly and indirectly beneficially owns 4% of the limited partnership interest. In addition to his 4% limited partnership ownership in NRP, Chris Cline also directly and indirectly beneficially owns 31% of the limited partnership interests in NRP’s general partner. Foresight Reserves and its subsidiaries have sold to NRP or subsidiaries of NRP certain coal reserves and transportation assets in exchange for equity in NRP and its general partner as well as entering into a restricted business contribution agreement and leases under which we will make royalty payments and pay fees as we mine leased coal and use leased transportation facilities owned by NRP, all as more further described below. Subsidiaries of NRP for which we have transacted include HOD, WPP, Williamson Transport, LLC (“Williamson Transport”) and Independence Energy, LLC (“Independence”).
On January 4, 2007, Chris Cline, Foresight Reserves, Adena Minerals LLC and their respective affiliates (collectively, “Adena Entities”) and NRP executed a restricted business contribution agreement. The restricted business contribution agreement obligates the Adena Entities and their affiliates to offer NRP any business owned, operated or invested in by the Adena Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in identified transportation infrastructure relating to certain future mine developments by the Adena Entities in Illinois. NRP’s acquisition of certain coal reserves and infrastructure assets related to our Macoupin, Hillsboro and Sugar Camp mining complexes, discussed more fully below, were deals consummated under the restricted business contribution agreement with the Adena Entities. We are required to offer and could consummate additional deals under the Restricted Business Contribution Agreement in the future.
Williamson has a coal mining lease agreement with WPP with an initial term of 15 years and options for an additional five years or until all merchantable and mineable coal has been mined and removed. Williamson is required to pay the greater of 8.0% of the gross selling price or $2.50 per ton for the first eight million tons of clean coal mined from the leased premises in any calendar year. For all tonnage mined in excess of the eight million tons, the royalty is the greater of 5.0% of the gross selling price or $1.50 per ton of clean coal mined from the leased premises. In addition to the tonnage royalty, the quarterly minimum royalty is $2.0 million, payable on the 20th of January, April, July and October in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined during the preceding nineteen quarters from the excess tonnage royalty on a first paid, first recouped basis. Furthermore, the lease provides for an overriding royalty of $0.10 per ton on the first 8.5 million tons mined from specific coal reserves outlined in the agreement. The lease also requires a wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises. During the years ended December 31, 2015, 2014 and 2013, Williamson paid $12.7 million, $19.8 million and $21.9 million, respectively, in royalties and other payments to WPP under this coal lease.
Williamson leases property from Williamson Transport under two surface leases with initial terms through October 15, 2031 and an option to extend the leases in five-year increments until all the coal leased from an NRP affiliate is mined on Williamson’s premises. Williamson Transport has the option to put the land to Williamson for its fair market value as determined by an independent appraiser at any time during the lease term. Additionally, under a separate lease with an initial term through March 12, 2018, Williamson pays $5,000 per year for use of the premises and a fee currently at $1.83 per ton for each ton of coal produced at Williamson that is loaded through the Williamson Loadout facility, which escalates approximately $0.02 per year throughout the term of the agreement. Williamson Transport may elect to renew or extend the sublease for successive five-year periods. If Williamson Transport elects not to renew the sublease, Williamson has the option to buy the Williamson Loadout facility for its fair market value as determined by an independent appraiser. Williamson receives a fee of $0.25 per ton from Williamson Transport for each ton of coal that is loaded through the Williamson Loadout facility in exchange for operating the load out. During the years ended December 31, 2015, 2014 and 2013, Williamson Transport was paid $8.9 million, $9.7 million and $10.2 million, respectively, under these leases (net of the operating fee paid to Mach Mining, LLC).
Another of the entities sold by the Adena Entities to NRP on January 4, 2007 was Independence, which had previously been owned by Foresight Reserves. We had previously entered into a coal mining lease with Independence to lease a certain tract of approximately 3,500 acres adjacent to the Williamson mining complex to perform certain mining activities on the tract. The term of this agreement is 15 years and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed.
Williamson is obligated to pay overriding royalties to WPP pursuant to a special warranty deed dated August 22, 1990 between its predecessors in interest, Coal Properties Corporation, Grantor and Fairview Land Company. Under this deed, WPP is owed an overriding royalty in the amount of $0.25 per ton for each ton of coal mined and sold by Williamson from the mineral reserves subject to the deed. During the years ended December 31, 2015, 2014 and 2013, Williamson paid $0, $0.5 million and $0.5 million, respectively, in overriding royalties to WPP under this agreement.
In January 2009, NRP acquired additional coal reserves and infrastructure assets related to Macoupin for $143.5 million. Simultaneous with the closing, Macoupin entered into a lease transaction with WPP and HOD for mining of the mineral reserves and
for the rail facility, which we account for as a sale-leaseback financing arrangement. The mineral reserve mining lease is for a term of 20 years and can be extended for additional five-year terms limited to six such renewals. The lease requires a tonnage royalty equal to the greater of (i) 8% of the gross selling price of the coal plus $0.60 per ton or (ii) $5.40 per ton to be paid on the first 3.4 million tons of coal mined and sold in any given calendar year. Additionally, for the first 20-year term of the lease, Macoupin is required to pay a recoupable quarterly minimum deficiency payment equal to the difference between the tonnage royalty and $4.0 million. The lease also requires a wheelage fee of 0.5% of the gross selling price of any foreign coal transported across the property. During the years ended December 31, 2015, 2014 and 2013, Macoupin paid $14.8 million, $16.2 million and $15.5 million, respectively, in royalties and other payments to WPP under this mineral lease. We are currently in dispute with WPP in regards to the application of the recoupment provision within this agreement.
The Macoupin rail load-out facility and rail loop facility leases are for terms of 20 years with 16 renewals for five years each. For the first 30 years of the leases, each lease requires a payment of $1.50 per ton for every ton of coal loaded through the facility, up to 3.4 million tons per year. Annual rental payments of $10,000 per year are due after the expiration of the first 30 years. Macoupin is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order. During the years ended December 31, 2015, 2014 and 2013, Macoupin paid $6.5 million, $3.8 million and $3.0 million, respectively, in payments to HOD under the rail facility leases.
Hillsboro entered into a coal mining lease agreement on September 10, 2009, with WPP. Under such agreement, Hillsboro leased certain mineral rights from WPP for a term of 20 years and can renew this lease for additional five-year terms, with a maximum of six terms or until all merchantable and mineable coal has been mined and removed. Hillsboro is required to pay WPP the greater of 8.0% of the gross selling price or $4.00 per ton and a fixed royalty in the amount set forth in the agreement for the coal mined from the leased premises. Hillsboro is subject to a minimum quarterly royalty under the agreement of $7.5 million until 2031, for the prior quarter’s production. Beginning with the quarterly minimum royalty due April 20, 2032, the quarterly minimum will be $125,000 for each quarter of 2032 and each subsequent quarter. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the applicable quarterly minimum royalty, Hillsboro may recoup any unrecouped quarterly deficiency payments made during the preceding twenty quarters from the excess tonnage royalty on a first paid, first recouped basis. We are a guarantor, on a declining basis, of the first $54.8 million of Hillsboro’s minimum quarterly payments to WPP. During the years ended December 31, 2015, 2014 and 2013, Hillsboro paid $17.6 million, $28.6 million and $32.4 million, respectively, to WPP under this lease. As of December 31, 2015, we paid WPP $46.6 million in advance minimum payments under this agreement that remain eligible for recoupment, all of which has been reserved for as we do not expect to recoup this balance based on the remaining recoupment period for certain minimum payments and the idling of the mine as a result of the mine fire.
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 $16.2 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.
Williamson has a coal mining lease agreement with Independence the term of which runs through March 13, 2021 and can be renewed for additional five-year periods or until all merchantable and mineable coal has been mined and removed. Williamson is required to pay Independence the greater of 9.0% of the gross selling price or $2.85 per ton for the coal mined from the leased premises. In addition to the tonnage royalty, Williamson is required to pay a quarterly minimum royalty of $416,750 in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the $416,750 quarterly minimum royalty, Williamson may recoup any unrecouped quarterly deficiency payments made during the preceding nineteen quarters from the excess tonnage royalty on a first paid, first recouped basis. The lease also has a provision for a wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises. Williamson has an overriding royalty agreement with Independence. As such, Independence will receive an overriding royalty interest in the amount of $0.30 per ton for each ton of clean coal mined from certain mineral reserves identified in the agreement that Williamson controls or in the future will control that are sold to any third party for the life of the Williamson mining operations on the identified mineral reserves. During the years ended December 31, 2015, 2014 and 2013, Williamson paid $4.9 million, $3.8 million, and $6.0 million respectively, in royalties and other payments to Independence.
In March 2012, HOD acquired a rail load-out facility at Sugar Camp for $50.0 million The transaction includes a lease of the rail load-out to Sugar Camp for which Sugar Camp is required to pay to HOD a $1.10 per ton tonnage fee, subject to adjustment, on certain tonnages of coal loaded through the load-out during the first 20 years of the lease, subject to a minimum recoupable quarterly deficiency payment of $1.3 million. After the first 20 years, Sugar Camp may elect to extend the lease for additional 5-year terms up to a maximum of 16 times. Sugar Camp has the option to purchase the rail load-out for fair market value at any time after the expiration of the first 20 years and for the remainder of the lease. The lease also requires Sugar Camp to maintain and operate the load-out. We are a guarantor, on a declining basis, of the first $15 million of Sugar Camp’s minimum quarterly payments to HOD.
During the years ended December 31, 2015, 2014 and 2013, Sugar Camp made $6.3 million, $6.2 million and $6.2 million, respectively, in payments to HOD under the load out lease.
In addition, we have entered into various ancillary agreements with NRP and its subsidiaries providing for acquisition of additional mineral rights within the assigned reserves of Williamson and Macoupin, all in support of our mining transactions with NRP for leased reserves.
As a result of these transactions and contracts, as of December 31, 2015, we had $2.3 million of net outstanding payable to NRP and its affiliates, $2.1 million in accrued interest and $193.4 million in sales-leaseback obligations recorded to consolidated balance sheet. As a result of these transactions and contracts, as of December 31, 2014, we had $7.0 million of net outstanding payable to NRP and its affiliates, $5.6 million in accrued interest and $193.4 million in sales-leaseback obligations recorded to consolidated balance sheet. During the years ended December 31, 2015, 2014 and 2013, we paid NRP and its affiliates $82.0 million, $88.7 million and $95.6 million, respectively, in aggregate payments under the agreements described herein (inclusive of the sale-leaseback arrangements).
The following presents future minimum royalties, by year, required under noncancelable royalty agreements (inclusive of our sale-leaseback obligations) with NRP and its affiliates as of December 31, 2015 (in millions):
Transactions With The Cline Group and its Affiliates
As part a reorganization in 2010, we entered into a series of mineral leases requiring minimum royalty payments and production royalty payments with Colt LLC (“Colt”) and Ruger Coal Company, LLC (“Ruger”), affiliates both owned by Foresight Reserves.
Williamson leases coal reserves from Colt. The term of this lease is for ten years with six renewal periods of five years each. Williamson is required to pay the greater of $3.40 per ton or 8.0% of the gross sales price of such coal. The minimum royalty for this lease, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million per year. During the years ended December 31, 2015, 2014 and 2013, Williamson paid $2.0 million, $2.0 million, and $2.1 million, respectively, in royalties to Colt under this coal lease. As of December 31, 2015, we paid Colt $5.7 million in advanced minimum royalty payments that remain eligible for recoupment.
Hillsboro leases coal reserves from Colt, the terms of which are identical but that each covers different reserves. The term of each of these leases is for five years with seven renewal periods of five years each. Hillsboro is required to pay the greater of $3.40 per ton or 8.0% of the gross sales price of such coal. The minimum royalty for each of these leases, which is recoupable only against actual production royalty from future tons during the period of 10 years following the date on which any such minimum royalty, is $4.0 million. Hillsboro paid $8.0 million in each of the years ended December 31, 2015, 2014 and 2013 in royalties to Colt under this coal lease. As of December 31, 2015, Hillsboro paid Colt $35.6 million in advanced minimum royalty payments that remain eligible for recoupment.
Sugar Camp leases coal reserves from Ruger. The term of this lease is for ten years with six renewal periods of five years each. Sugar Camp is required to pay the greater of $3.40 per ton or 8.0% of the gross sales price of such coal. There is no minimum royalty associated with this lease. Sugar Camp has two overriding royalty agreements with Ruger pursuant to which Sugar Camp is given the right to mine certain reserves controlled by Ruger as lessee. Pursuant to these overriding royalty agreements, the total royalty that Sugar Camp will be required to pay for each ton of coal mined is equal to the difference between (i) the actual production royalty paid by Sugar Camp to the lessor of the reserves under the leases assumed by Sugar Camp from Ruger and (ii) the amount which is equal to 8% of the gross selling price of the coal mined under the leases. In addition to the overriding royalty, the remaining future minimum royalty for each of these agreements, which is recoupable only against actual overriding royalty during the period of ten years following the date on which such overriding royalty was paid, is $1.0 million. During the years ended December 31, 2015, 2014 and 2013, Sugar Camp paid $3.1 million, $11.5 million and $7.4 million, respectively, in royalties to Ruger under these coal lease and overriding royalty agreements described above. As of December 31, 2015, Sugar Camp paid Ruger $3.3 million in advanced minimum royalty payments under the overriding royalty agreements that remain eligible for recoupment.
Macoupin leases coal reserves from Colt under two leases, the terms of which are identical but that cover different reserves. The term of these leases is for ten years with six renewal periods of five years each. Macoupin is required to pay the greater of $3.40 per ton or 8.0% of the gross sales price of such coal. The remaining future minimum royalties for each of these leases, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million.
Effective June 1, 2012 Macoupin leased additional coal reserves from Colt under another lease. The term of this lease is ten years with six renewal periods of five years each. Macoupin is required to pay the greater of $3.40 per ton or 8.0% of the gross sales price of such coal, subject to minimum annual payments of $0.5 million in 2013 and $2.0 million per year thereafter. Minimum annual payments are recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid.
During the years ended December 31, 2015, 2014 and 2013, Macoupin paid $6.0 million in royalties to Colt under these coal leases. As of December 31, 2015, Macoupin paid Colt $25.0 million under these leases in advanced minimum payments that remain eligible for recoupment.
As of December 31, 2015 and 2014, the mines had $0.1 and $0 million, respectively, in aggregate outstanding payables to Colt and Ruger under all of the leases above. During the years ended December 31, 2015, 2014 and 2013, we paid Colt and Ruger $19.1 million, $27.5 million and $23.5 million, respectively, in aggregate royalty payments under the agreements described herein.
The following presents future minimum royalties, by year, required under noncancelable royalty agreements with Foresight Reserves and its affiliates as of December 31, 2015 (in millions):
Mitigation Agreements
New River Royalty, LLC (“New River Royalty”) (formerly Williamson Development Company LLC), an affiliate owned by Foresight Reserves, entered into mitigation agreements with each of Hillsboro, Macoupin, Sugar Camp and Williamson on August 12, 2010 (“Mitigation Agreements”). The Mitigation Agreements are contracts providing for the mitigation by each of the coal mining companies of subsidence damage to any structures located on certain surface lands owned by New River Royalty. Under these agreements, the mining companies are obligated to either repair any significant damage to structures on New River Royalty’s surface lands caused by mine subsidence or compensate New River Royalty for the diminution in value of the structure caused by the subsidence damage, in satisfaction of their obligation under the Illinois Surface Coal Mining and Conservation and Reclamation Act, 225 ILCS 720/1.01 et. seq. As an alternative, under the Mitigation Agreements, the mining companies can elect to pay New River Royalty the appraised value of any structures expected to be impacted by subsidence activities prior to mining in exchange for a waiver of liability for any obligation to repair or compensate New River Royalty for any damage after subsidence occurs. Appraised values and diminution in value are determined by licensed appraisers.
Convent Marine Terminal Transloading Agreement
In August 2011, an affiliated company owned by Foresight Reserves acquired the IC RailMarine Terminal in Convent, Louisiana. This terminal, commonly referred to as the Convent Marine Terminal (“CMT”), is owned by Raven Energy LLC (“Raven”), an entity controlled by Chris Cline and beneficially owned by Christopher Cline, trusts for his children and entities beneficially owned by his management team. The terminal is designed to ship and receive commodities via rail, river barge and ocean vessel. We have a contract for throughput at the terminal that continues through December 31, 2021. We pay fees under the contract based on the tonnages of coal we move through the terminal, subject to minimum annual take-or-pay volume commitments throughout the duration of the contract. Effective May 1, 2015, the Partnership amended its material handling agreement with Raven to reduce the minimum annual throughput volume at CMT to 5.0 million tons and to extend the duration of the contract by one year to 2022. In August 2015, Raven was sold to entity under which Chris Cline does not have significant influence; therefore the Partnership’s business activities with Raven are no longer considered affiliate transactions subsequent to August 2015. For the years ended December 31, 2015, 2014 and 2013, we paid $19.3 million, $41.9 million and $26.1 million, respectively, to Raven (as an affiliate) under this agreement.
Equipment Repair and Rebuild Services
On August 1, 2013, Foresight Energy Services LLC entered into an equipment repair and rebuild agreement with Seneca Rebuild LLC (“Seneca Rebuild”), an affiliate owned by Chris Cline, to be the primary provider of repair and rebuild services for mining machinery and equipment for our mines. On April 1, 2014, we acquired Seneca Rebuild for $3.8 million (net of cash acquired).
Affiliate Supply Agreement
On May 1, 2013, certain unaffiliated suppliers of mining products and Seneca Industries, Inc., one of our affiliates, formed a joint venture whose primary purpose is the manufacture and sale of certain mine supplies primarily for use by us in the conduct of our mining operations. In May 2013, we entered into an amendment to our existing supply agreement with the unaffiliated supplier parties that added the joint venture in which one of our affiliates owns 50% as a supplier party to the agreement, extended the term to April 2018 and updated the pricing provisions of the agreement. The agreement, as amended, obligates our mines to purchase at least 90% of their aggregate annual requirements for certain mine supplies from the supplier parties, subject to certain exceptions as set forth in the agreement. The mine supplies covered under this arrangement are sold pursuant to a price schedule incorporated into the agreement that is reviewed and, if necessary, adjusted every six months to result in an agreed-upon fixed profit percentage for the joint venture as set forth in the agreement. We and our affiliates purchased $14.5 million, $18.1 million and $14.7 million in mining supplies from the joint venture during the years ended December 31, 2015, 2014 and 2013, respectively.
2021 Senior Notes
On August 23, 2013, Cline Resource and Development Company (“CRDC”) acquired $16.5 million of outstanding principal amounts of our 2021 Senior Notes (the “Original Purchase”), which bear interest at the rate of 7.875% annually. During September and October 2013, CRDC sold the Original Purchase primarily to affiliates, including $8.0 million to Chris Cline, $4.0 million to an entity controlled by John F. Dickinson, a director of our general partner’s board of directors, and $3.8 million to two former executives of the Partnership. Additional amounts were acquired independently in 2015 by Chris Cline and The Cline Trust Company LLC, as discussed below.
As of December 31, 2015 and 2014, Chris Cline owned $44.5 million and $8.0 million, respectively, of the outstanding principal on our 2021 Senior Notes. Chris Cline acquired $8.0 million in principal of the Original Purchase and during the year ended December 31, 2015, acquired an additional $36.5 million in principal from third parties in open market transactions. During the years ended December 31, 2015, 2014, and 2013, $1.9 million, $0.6 million and $0 million, respectively, of interest on the 2021 Senior Notes was paid to Chris Cline, respectively. As of December 31, 2015 and 2014, $1.3 million and $0.2 million, respectively, of interest on the 2021 Senior Notes was accrued to the benefit of Chris Cline.
The entity controlled by Mr. Dickinson owned $4.0 million of the outstanding principal on our 2021 Senior Notes as of December 31, 2015 and 2014, all of which was acquired from the Original Purchase. During the year ended December 31, 2015 and 2014, $0.3 million of interest on the 2021 Senior Notes was paid to Mr. Dickinson. As of December 31, 2015 and 2014, $0.1 million of interest on the 2021 Senor Notes was accrued to the benefit of the entity controlled by Mr. Dickinson.
As of December 31, 2015, The Cline Trust Company LLC owned $10.0million in principal of our 2021 Senior Notes, all of which was acquired during the year ended December 31, 2015. During the year ended December 31 2015, no interest had been paid to The Cline Trust Company LLC. As of December 31, 2015, $0.3 million of interest on the 2021 Senior Notes was accrued to the benefit of The Cline Trust Company LLC.
Also, Michael Beyer, the former chief executive officer of FELP, who resigned in May 2015, and Drexel Short, a former executive of our predecessor, who retired in March 2014, acquired $3.2 million and $0.5 million, respectively, from the Original Purchase. Mr. Beyer disposed of his 2021 Senior Notes in September of 2015. These former executives were no longer affiliates of the Partnership subsequent to their termination dates. During each of the years ended December 31, 2015 and 2014, $0.3 million of interest was paid to Mr. Beyer and Mr. Short, collectively, while they were affiliates of the Partnership.
Other Related Party Transactions
We are party to two surface leases in relation to the coal preparation plant and rail load out facility at Williamson with New River Royalty. The primary terms of the leases expire on October 15, 2021, but may be extended by Williamson for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases. Additionally,
New River Royalty may require Williamson to purchase any portion of either of the leased properties at any time while the leases are in effect for $3,000 an acre. Williamson Transport has the option to purchase any property optioned under the leases if Williamson does not perform its purchase obligation within fifteen days of receiving notice of its purchase obligation.
We may arrange air travel on an individual flight basis with affiliated entities controlled by The Cline Group. These expenses are incurred hourly (at estimated cost), by flight, and are initially paid by The Cline Group and then we reimburse The Cline Group. We also utilize other assets controlled by The Cline Group from time to time and reimburse The Cline Group on a time-incurred basis. For the year ended December 31, 2013, we reimbursed entities controlled by The Cline Group $1.5 million for usage of non-Foresight Energy LP assets. There was no such activity in 2015 or 2014.
Several affiliates by common ownership which own or lease property on which we conduct mining have obtained subsidence rights either from the surface owner or lessor. Normally, these rights permit us to subside the surface owner’s property in exchange for subsidence mitigation. The extent of the mitigation is normally determined at the time we undermine the surface and the cost is normally not material to our operations. Because those subsidence rights were previously held by affiliates by common ownership, we have entered into global assignments of such rights in exchange for our obligation to satisfy all subsidence mitigation.
Transactions with Murray Energy Corporation and its Affiliates
Murray Management Services Agreement
On April 16, 2015, a MSA was executed between FEGP and Murray American Coal, Inc. (the ”Manager”), a wholly-owned subsidiary of Murray Energy, 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 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. After taking into account the contractual adjustments for direct costs incurred by FELP, the amount of net expense due to the Manager for the year ended December 31, 2015 was $4.7 million.
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 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 $98.7 million at December 31, 2015, with unearned income equal to $37.7 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 December 31, 2015, the outstanding Transport Lease financing receivable was $61.0 million, of which $2.5 million was classified as current in the 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 $34.1 million at December 31, 2015, with unearned income equal to $22.3 million. As of December 31, 2015, the outstanding ORRA financing receivable was $11.8 million, of which $0.2 million was classified as current in the consolidated balance sheet.
Other Murray Transactions
During the year ended December 31, 2015, we purchased $3.3 million in equipment, supplies and rebuild services from affiliates of Murray Energy. During the year ended December 31, 2015, our affiliate Coalfield Construction provided $0.2 million in equipment, supplies and rebuild services to affiliates of Murray Energy.
During the year ended December 31, 2015, we purchased $17.4 million in coal from Murray Energy and its affiliates to meet quality specifications under certain customer contracts and we sold $23.1 million of coal to Murray Energy and its affiliates, including Javelin Global Commodities Limited (“Javelin”). Javelin is an international commodities marketing and trading joint venture owned by Murray Energy and E.ON Global Commodities SE.
During the year ended December 31, 2015, 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 $11.0 million. These usage fees were billed to Murray Energy, resulting in no impact to our consolidated statement of operations. The usage of the railway line with this third-party rail company by Murray Energy counts towards the minimum annual throughput volumes with the third-party rail company, thereby reducing the Partnership’s exposure to contractual liquidated damage charges. Similarly, during the year ended December 31, 2015, we incurred $0.2 million of transportation fees incurred for shipments under one of Murray Energy’s third-party transloading contracts.
During the year ended December 31, 2015, we earned $0.3 million in other revenues for Murray Energy’s usage of Sitran.
Transactions with our Contract Operators
We operate each mine with a work force that is employed by a contractor that is not under common ownership by us, but is an “affiliate” of us due to our ability to exert control with respect to certain matters. We account for each of these operators as a variable interest entity. Due to the treatment of these contract operators as “variable interest entities,” their assets, liabilities and results of operations are reflected in our consolidated financial statements. For the years ended December 31, 2015 , 2014 and 2013, we paid $0.5 million, $0.5 million and $0.4 million, respectively, in the aggregate, plus reimbursement for actual costs incurred to these affiliated contract operators. See Part I. “Item 1. Business-Employees and Labor Relations” for a detailed description of the agreements governing the relationship with these affiliated contract operators.
Procedures for Review, Approval and Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the conflicts committee. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Foresight Reserves, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. The independent members of the board of directors of our general partner serve on our conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is adverse to the interest of the partnership. Any matters approved by the conflicts committee are conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. The policy described above was adopted in connection with the IPO, and as a result the transactions executed prior to the IPO were not reviewed under such policy.
Director Independence
The information appearing under Part III. “Item 10. Directors, Executive Officers and Corporate Governance of the Managing Partner - Director Independence” is incorporated herein by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table presents fees for professional services rendered by our independent registered public accounting firm, Ernst and Young, LLP, during the years ended December 2015 and 2014:
(1)
Audit fees represent fees for professional services rendered in connection with (i) the audit of our annual financial statements, including the audit of internal control over financial reporting, (ii) the reviews of our quarterly reports on Form 10-Q and (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters (including the Registration Statements on Form S-1 filed in connection with our initial public offering). The amount recorded as audit fees, including out-of-pocket expenses, are for the current year audit irrespective of the period in which the related services are billed.
(2)
Audit-related fees represent fees for assurance and related services. This category primarily includes services relating to fees for audits of employee benefit plans.
(3)
Tax fees represent fees for professional services rendered in connection with tax compliance, tax advice and tax planning.
(4)
All other fees represent fees for services not classified under the other categories listed above.
The charter of the audit committee of the board of directors of our general partner provides that the audit committee is responsible for reviewing and approving, in advance, any audit and permissible non-audit engagement or relationship between us and our independent auditors, other than as provided under the de minimis exception rule.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)
The following documents are filed as part of this Annual Report on Form 10-K:
(1)
Financial Statements-Set forth under Part II, Item 8. “Financial Statements and Supplementary Data”
(2)
Financial Statement Schedules-Valuation and Qualifying Accounts-Set forth under Part II, Item 8. “Financial Statements and Supplementary Data.” All other schedules are omitted because they are not applicable or the information is shown in the financial statements or notes thereto.
(3)
Exhibits-Exhibits required to be filed by Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K and are incorporated herein by reference.
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 March 15, 2016.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Robert D. Moore
President, Chief Executive Officer and Director
March 15, 2016
Robert D. Moore
/s/ James T. Murphy
Principal Financial Officer and Chief Accounting Officer
March 15, 2016
James T. Murphy
*
Principal Strategy Officer and Chairman of the Board of Directors
March 15, 2016
Christopher Cline
*
Director
March 15, 2016
G. Nicholas Casey
*
Director
March 15, 2016
Bennett K. Hatfield
*
Director
March 15, 2016
Daniel S. Hermann
*
Director
March 15, 2016
Paul H. Vining
*By:
/s/ Robert D. Moore
Robert D. Moore, Attorney-in-fact
INDEX TO EXHIBITS