UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-K*

 

(Mark One)

For the fiscal year ended December 31, 2019

OR

For the transition period from          to          

Commission File Number: 001-36503

 

Foresight Energy LP

(Exact Name of Registrant as Specified in its Charter)

 

 

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

 

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

Securities registered pursuant to Section 12(g) of the Act:  None

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ☐     No  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  ☐     No ☒

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.     Yes  ☒    No  ☐  

The aggregate market value of units held by non-affiliates as of June 30, 2019 was $21,163,127.

As of March 20, 2020, the registrant had 80,996,773 common units and 64,954,691 subordinated units outstanding.

 

* The registrant is relying on an order under Section 36 (Release No. IA-5469) of the Exchange Act, granting exemptions from specified provisions of the Exchange Act and certain rules thereunder (the "Order") in connection with the delayed filing of this Annual Report on Form 10-K for the fiscal year ended December 31, 2019, as a result of the circumstances set forth below.

As a result of the global outbreak of the coronavirus disease (COVID – 19) and out of an abundance of caution, certain employees of the Partnership, including financial reporting and accounting staff, have been working remotely beginning on or about March 13, 2020.  As a result, the Partnership had limited access to its corporate headquarters office where certain financial data and work papers are kept, was unable to determine when such access could be made safely, and was unable to complete its Annual Report on Form 10-K for the year ended December 31, 2019 in a timely manner.

 

 

 

 

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TABLE OF CONTENTS

 

 

 

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

Certain statements and information in this Annual Report on Form 10-K, and certain oral statements made from time to time by our representatives, may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “outlook,” “estimate,” “potential,” “continues,” “may,” “will,” “seek,” “approximately,” “predict,” “anticipate,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that the future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are described in Part I. “Item 1A. Risk Factors.”

 

Readers are cautioned not to place undue reliance on forward-looking statements, which are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

 

REFERENCES WITHIN THIS ANNUAL REPORT

 

All references to “FELP,” the “Partnership,” “we,” “us,” and “our” refer to the results of Foresight Energy LP and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

 

PART I

 

Item 1. Business

 

We mine and market coal from reserves and operations located exclusively in the Illinois Basin. We control nearly 2.1 billion tons of proven and probable coal in the state of Illinois (including 73 million tons of coal reserves associated with our recently idled Macoupin complex), which makes us one of the largest reserve holders in the United States. 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 consisting of three longwall mines and one continuous miner operation. We invested substantially to construct state-of-the-art, low-cost and highly productive mining operations and related transportation infrastructure. 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 were idled since March 2015 due to a combustion event.  In October 2018, we reached a settlement of certain litigation matters associated with the Hillsboro combustion event.  In January 2019, we resumed production at Hillsboro with one continuous miner unit and in March 2020, longwall production at Hillsboro resumed.  In March 2020, we idled operations at our Macoupin complex, owing to the significant challenges in the thermal coal markets further described below.  

 

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. We own a 25 million ton per year barge-loading river terminal on the Ohio River and also have contractual agreements for significant export capacity via the Gulf of Mexico. These logistical arrangements provide the flexibility to direct shipments to markets that provide the highest margin for our coal sales.

 

We market and sell our coal primarily to electric utility and industrial companies in the eastern half of the 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.

 

 

 

 

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Foresight Energy LP, a Delaware limited partnership formed on January 26, 2012, completed its initial public offering on June 23, 2014 and currently trades over-the-counter under the symbol “FELPQ”. We are managed and operated by the board of directors and executive officers of our general partner, Foresight Energy GP LLC (“FEGP”), which is owned by Murray Energy Corporation (“Murray Energy”) and Foresight Reserves LP (“Foresight Reserves”).

 

Below is a diagram of our organizational and ownership structure as of March 20, 2020:

 

 

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The thermal coal markets that we traditionally serve have been meaningfully challenged over the past three to four years, and deteriorated significantly in the last several months. This sector-wide decline has been driven largely by (a) the closure of approximately 93,000 megawatts of coal-fired electric generating capacity in the United States, (b) a record production of inexpensive natural gas, and (c) the growth of wind and solar energy, with gas and renewables, displacing coal used by U.S. power plants. During its peak in 2007, coal was the power source for half of electricity generation in the United States and by early 2019, coal-fired electricity generation fell to approximately 27 percent. These challenges have intensified recently as (i) certain electric utility companies have filed for bankruptcy protection and others have sought, and received, subsidies for their nuclear generation capacity to avoid bankruptcy, at the expense of coal-fired facilities, (ii) domestic natural gas prices hit 20-year lows this past summer, and (iii) overall demand for electricity in the United States has declined two percent in 2019, further depleting demand for coal at domestic utilities. At the same time, demand for U.S. coal from international utilities has been subject to its own set of negative forces, and the European benchmark price for thermal coal has halved in the last year. The impact of depressed demand and pricing in both domestic and international markets has impacted us significantly in recent months: customers with pre-existing commitments have refused to accept delivery, and with export markets depressed there is simply no alternative market to place product. These factors have led us to seek protection under Chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”), as further described below.

 

Filing Under Chapter 11 of the Bankruptcy Code

 

On March 10, 2020 (the “Petition Date”), we filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code (the “Foresight Chapter 11 Cases”) in the United States Bankruptcy Court for the Eastern District of Missouri (the “Bankruptcy Court”).  Further information regarding our bankruptcy filing under Chapter 11 of the United States Bankruptcy Code, as well as information on our liquidity, capital resources, debt obligations and going concern matters, are disclosed in Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.

 

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Mining Operations

 

Each of our four mining complexes operates in the Illinois Basin; with two located in Southern Illinois and two located in Central Illinois. Williamson, Sugar Camp, and Hillsboro are longwall operations. Macoupin is a continuous miner operation. The geology, mine plan, equipment and infrastructure at each of our Williamson, Sugar Camp and Hillsboro mines are relatively similar. Each of our mining complexes has its own preparation plant and support facilities. The following map shows the location of our mining complexes and transportation network:

 

 

(1)“CN”: Canadian National line; “EVWR”: the Evansville Western line; “NS”: the Norfolk Southern line; “UP”: Union Pacific line; “BNSF”: BNSF Railway line; and “CSX”: CSX Corporation line.

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The table below summarizes our operations, available mining methods, transportation access, reserves and production:

 

 

Longwall mining is a highly-automated, underground mining technique that generates high volumes of low-cost coal production and is typically supported by one or two continuous mining units. While the continuous mining units contribute to coal production, the primary function is to prepare an area of the mine for longwall operations. A longwall mining system uses a shearer to cut the coal, self-advancing roof supports to protect the miners working at the longwall face and an armored face conveyor to transport the coal. The longwall mining system is highly productive due to the continuous nature of coal production and the high volume of coal produced relative to the number of personnel required to operate the system.

 

Below is an illustrative diagram of the longwall mining process:

 

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We have been able to sustain our high productivity and low operating costs since we started our first longwall in 2008 and the high productivity at the newer mines we have developed demonstrates the repeatability of our mine design. The high productivity translates into low costs and, in 2019, our operations had an average cash cost of $23.95 per ton sold. Our mines that operated during 2019 were among the most productive underground coal mines in the United States on a clean tons produced per man hour basis based on MSHA data, as illustrated below.

 

Source: MSHA data. Note: The chart above displays the top 25 most productive underground mines out of 142 mines with over 150,000 tons produced during 2019 on a clean tons produced per man hour basis. Darker shading denotes mines owned by Foresight Energy LP. Longwall mining operations at our Hillsboro complex recommenced in March 2020 and is thus not included in the chart above.

 

Williamson Mining Complex

 

Our Williamson mine is wholly-owned by our subsidiary Williamson Energy, LLC (“Williamson”) and is located in southern Illinois near the town of Marion. Williamson is the first mine we developed, with longwall mining production commencing in 2008. The mine operates in the Herrin No. 6 Seam, using one longwall system and two continuous miner units to develop the mains and gate roads for its longwall panels. Coal is washed at Williamson’s 2,000 tons-per-hour (“tph”) preparation plant, stockpiled and then shipped by rail or truck to our customers or a terminal. Williamson’s coal is shipped via multiple railroads to the Ohio and Mississippi Rivers to serve the domestic thermal market or to a terminal near New Orleans to serve the international thermal market. Williamson has access to several barge facilities on the Ohio and Mississippi Rivers and two vessel loading facilities near New Orleans. Williamson was the third most productive underground coal mine in the United States in 2019 on a clean tons produced per man hour basis based on MSHA data.

 

Sugar Camp Mining Complex

 

Our Sugar Camp mine is wholly-owned by our subsidiary Sugar Camp Energy, LLC (“Sugar Camp”), and is located in southern Illinois approximately 12 miles north of Williamson. Sugar Camp’s first longwall system began production in the first quarter of 2012 and its second longwall system began production in the second quarter of 2014. Sugar Camp’s original infrastructure, including its bottom development, slope belt, material handling system and rail loadout, supports both longwalls. Sugar Camp operates in the Herrin No. 6 Seam and uses a similar mine design and equipment as Williamson. With additional equipment, infrastructure and mine development, Sugar Camp has the capacity to add two incremental longwall systems. Coal is washed at Sugar Camp’s two 2,000 tph preparation plants, stockpiled and then shipped by rail or truck to our customers or a terminal. Sugar Camp has direct access to the EVWR and CN railroads, which can deliver its coal to the Ohio and Mississippi Rivers, respectively, to serve the domestic thermal market or to two vessel loading facilities near New Orleans to serve the international thermal market. Sugar Camp also has indirect access to the NS, BNSF and CSX railroads. Sugar Camp was the most productive underground coal mine in the United States in 2019 on a clean tons produced per man hour basis based on MSHA data.

 

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Hillsboro Mining Complex

 

Our Hillsboro mine is wholly-owned by our subsidiary Hillsboro Energy LLC (“Hillsboro”), and is located in central Illinois near the town of Hillsboro. Hillsboro’s longwall mining system began production in the third quarter of 2012. The mine operates in the Herrin No. 6 Seam and uses similar mine design and similar equipment as Williamson and Sugar Camp. Coal is washed at Hillsboro’s 2,000 tph preparation plant, stockpiled and then shipped by rail or truck to our customers or a terminal. Hillsboro has direct access to the UP and NS railroads and indirect access to the CN railroad, which allows for the delivery of its coal directly to customers or to the Ohio and Mississippi Rivers in order to serve the domestic thermal market or the international thermal market through two terminals near New Orleans.

 

Our Hillsboro mine experienced an underground combustion event beginning in March 2015 and had been idle since that time.  In December 2017, we submitted a re-entry plan to MSHA which contained a plan for the permanent sealing of the current longwall district of the Hillsboro mine.  In connection with the re-entry plan, certain longwall equipment and other related assets was permanently sealed within and was not recovered, resulting in a $42.7 million impairment loss during 2017.  In connection with certain litigation matters related to the combustion event and due to additional facts and circumstances arising in April 2018, we announced that our Hillsboro operation would be closed and certain long-lived assets consisting primarily of mineral reserves and certain buildings and structures, machinery and equipment, and other related assets were not expected to generate future positive cash flows. As the expected future cash flows were projected to be immaterial and not sufficient to support the recoverability of the assets’ carrying values, the assets were reduced to their estimated fair values.  As such, we recorded an aggregate impairment charge of $110.7 million during 2018.  In October 2018, we reached a settlement of certain litigation matters associated with the Hillsboro combustion event. In January 2019, we resumed production at Hillsboro with one continuous miner unit and in March 2020, longwall production at Hillsboro resumed.  

 

Macoupin Mining Complex

 

Our Macoupin mine is wholly-owned by our subsidiary Macoupin Energy LLC (“Macoupin”), and is located in central Illinois near the town of Carlinville. We acquired the Macoupin mine in 2009 and sealed the majority of the previously mined area and implemented a new mine plan and design. In addition, the surface facilities were upgraded, including the rehabilitation of the preparation plant. Coal production began in 2009 with a single continuous miner super-section utilizing battery powered coal haulers. An additional continuous miner unit was added in 2011 using a flexible conveyor train system rather than coal haulers. Coal is washed at Macoupin’s 850 tph preparation plant, stockpiled and then shipped by rail or truck to our customers or a terminal. Macoupin has direct access to both the UP and NS railroads and indirect access to the CN railroad, which allows for the delivery of its coal directly to customers or to terminals at the Ohio and Mississippi Rivers to serve the domestic thermal market or the international thermal market through two terminals near New Orleans. Macoupin was the twentieth most productive underground coal mine in the United States in 2019 on a clean tons produced per underground man hour basis based on MSHA data.  In March 2020, we idled operations at our Macoupin complex, owing to the significant challenges in the thermal coal markets. As a result of the idling, the expected future cash flows at Macoupin were projected to be immaterial and not sufficient to support the recoverability of the assets’ carrying values, the assets were reduced to their estimated fair values.  As such, we recorded an aggregate impairment charge of $143.6 million at Macoupin during 2019.

 

Transportation

 

Our coal is transported to our domestic and export customers by rail, barge, truck, and vessel. Depending on the proximity of our customers to the mines and the transportation available to deliver coal to that customer, transportation costs can be a substantial part of the total delivered cost of coal. Because our reserves and mines are favorably located near multiple rail and river transportation options, we believe we can negotiate advantageous transportation rates, allowing us to keep our transportation costs relatively low while providing broad market access for our coal.

 

We have direct and indirect rail access to domestic customers via five Class I railroads, river access to domestic customers via various Ohio and Mississippi River terminals, and river and rail access to coal export terminals for shipping to international customers. We also have favorable access to the international market through the CN railroad and export terminals through contractual arrangements. The international market provides us with an alternative to the domestic market and has historically been an important economic outlet for our coal. While transportation costs are higher for exports to the international market, we do, in certain market conditions, receive higher coal sale prices on export sales, which offset the higher transportation costs. Rates and practices of the transportation companies serving a particular mine or customer may affect our marketing efforts with respect to coal produced from the relevant mine.

 

For the year ended December 31, 2019, approximately 21% of our coal sales volume was shipped to our domestic customers by barge, 48% to our domestic customers by rail or truck and 31% was shipped to our international customers.

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Our Sitran terminal is a high-capacity coal transloading facility on the Ohio River near Evansville, Indiana to which each of our mines has access. The facility currently has a single rail loop, a bottom discharge rail car unloader, stacking tubes to facilitate ground storage and blending, barge loading capabilities and throughput capacity of 25 million tons of coal per year. The terminal has the potential for a dual rail loop that would have capacity for two loaded and two empty unit trains.

 

Coal Marketing and Sales

 

During the years ended December 31, 2019, 2018 and 2017, we generated total revenues of $841.5 million, $1.105 billion and $954.5 million, respectively. Our primary domestic customers are electric utility and industrial companies in the eastern half of the United States. Our four largest customers in 2019 were Javelin Global Commodities (an affiliate of Murray Energy), Southern Company, LG&E, and Santee Cooper, representing approximately 37%, 14%, 9%, and 8% of our total coal sales revenues, respectively. If these customers or any of our largest customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to our largest customers on terms that are favorable to us, our results of operations may be materially adversely affected.

 

The international thermal coal market has also been a substantial part of our business with direct and indirect sales to end users in Europe, South America, Africa and Asia. During the years ended December 31, 2019, 2018, and 2017, export tons represented approximately 31%, 38% and 27% of tons sold, respectively. The charts below illustrate our sales mix, by destination, for the years ended December 31, 2019, 2018, and 2017.

Our management actively monitors trends in contract pricing and seeks to enter into coal sales contracts at favorable prices. Many of our contracts allow us to substitute coal from our other mining complexes. For 2020, as of March 20, 2020, we have over 12 million tons, excluding unexercised option tonnage, contractually committed.

 

The terms of our coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts, including price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions, and termination and assignment provisions, vary significantly by customer.

 

Most of our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific quality characteristics such as heat content, sulfur, and ash. Failure to meet these conditions could result in substantial price reductions or suspension or termination of the contract at the election of the customer. Although the minimum volume to be delivered under a long-term contract is stipulated, either party may vary the timing of delivery based on certain contractual provisions. Contracts also typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events beyond the control of the affected party, including labor disputes. Some contracts may terminate upon continuance of an event of force majeure for an extended period. Some of our long-term contracts provide for a predetermined adjustment to the stipulated base price at times specified in the agreement or at other periodic intervals to account for changes in prevailing market prices.

 

In addition, most of our contracts contain provisions permitting us to adjust the base price due to compliance with new statutes, ordinances or regulations that affect our costs related to performance of the agreement. Also, some of our contracts contain provisions that allow for the recovery of certain costs incurred due to modifications or changes in the interpretations or application of any applicable government statutes.

 

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Price reopener provisions are present in certain of our long-term contracts. These provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract.

 

Competition

 

The United States coal industry is highly competitive, both regionally and nationally. In the Illinois Basin, we compete primarily with coal producers such as Peabody Energy Corporation, Alliance Resource Partners, L.P., and Murray Energy (an affiliate). Outside of the Illinois Basin, we compete broadly for coal sales with other United States-based producers of thermal coal, and we compete internationally with numerous global coal producers.

 

A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on: the coal consumption patterns of the electricity industry in the United States and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear, hydroelectric and renewable energy. Coal consumption patterns are affected primarily by the demand for electricity, the amount of coal supply in the market, environmental and other governmental regulations and technological developments. The most important factors on which we compete are price, coal quality characteristics, and reliability of supply.

 

Segments

 

We operate as a single reportable segment. See Part II. “Item 8. Financial Statements and Supplementary Data” for our consolidated revenues and total assets.

 

Employees and Labor Relations

 

As of December 31, 2019, we had 12 corporate employees and 844 employees working in mining and mining-related operations. None of our operations have employees represented by a union. In 2015, we entered into a management services agreement with a subsidiary of Murray Energy pursuant to which it provides certain management and administration services to us for a quarterly fee. Please read Part II. “Item 8. Financial Statements and Supplementary Data, Note 16–Related-Party Transactions” for additional discussion.

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Environmental and Other Regulatory Matters

 

Our operations are subject to a variety of U.S. federal, state and local laws and regulations, such as those relating to employee health and safety; water discharges; air emissions; plant and wildlife protection; the restoration of mining properties; the storage, treatment and disposal of wastes; remediation of contaminants; surface subsidence from underground mining and the effects of mining on surface water and groundwater conditions.

 

We are not aware of any notice from a governmental agency of any material non-compliance with applicable laws, regulations, or permits that the Partnership has failed to respond to pursuant to applicable regulations. However, there can be no assurance that violations will not occur in the future; that we will be able to always obtain, maintain or renew required permits; or that changes in these requirements or their enforcement or the discovery of new conditions will not cause us to incur significant costs and liabilities in the future. Due to the nature of the regulatory programs that apply to our mining operations, which can impose liability even in the absence of fault and often involve subjective criteria, it is not reasonable to expect any coal mining operation to be free of citations. Certain of our current and historical mining operations use or have used or store regulated materials which, if released into the environment, may require investigation and remediation. Under certain permits, we are required to monitor groundwater quality on and adjacent to our sites and to develop and implement plans to minimize and correct land subsidence, as well as impacts on waterways and wetlands, caused by our mining operations. Major regulatory requirements are briefly discussed below.

 

Mine Safety and Health

 

In the United States, the Coal Mine Health and Safety Act of 1969, the Federal Mine Safety and Health Act of 1977 (the “1977 Act”) and the Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) impose stringent mine safety and health standards on all aspects of mining operations. In 1978, MSHA was created to carry out the mandates of the 1977 Act and was granted enforcement authority. MSHA is authorized to inspect all underground mining operations at least four times a year and issue citations with civil penalties for the violation of a mandatory health and safety standard. MSHA review and approval is required for a number of miner safety and welfare plans including ventilation, roof control/bolting, safety training and ground control, refuse disposal and impoundments and respirable dust. Also, the State of Illinois has its own programs for mine safety and health regulation and enforcement.

 

Under the 1977 Act, MSHA has the authority to issue orders or citations to mine operators regardless of the degree of culpable conduct engaged in by the operator, and it must assess a penalty for each citation and most orders. Factors such as degree of negligence and gravity of the violation, among other things, affect the am ount of penalty assessed, and sometimes permit MSHA to issue orders directing withdrawal of miners from the mine or affected areas within the mine. The 1977 Act contains provisions that can impose criminal liability on the mine operator or individuals if the statutory prerequisite is satisfied.

 

The MINER Act added more extensive health and safety compliance standards, and increased civil and criminal penalties. Some of the MINER Act requirements included stricter criteria for sealing off abandoned areas of mines, the addition of refuge alternatives, stricter requirements for conveyor belts, and upgrades to communication with and tracking of miners underground.

 

MSHA continues to promulgate rules that affect our mining operations. In March 2013, MSHA implemented a revised Pattern of Violations (“POV”) standard. Under the revised standard, mine operators are no longer entitled to a ninety day notice of potential POV. In addition, MSHA began screening for POV by using issued citations and orders, prior to their final adjudication. If a mine is designated as having a POV, MSHA will issue an order withdrawing miners from any areas affected by violations which pose a significant and substantial (“S&S”) hazard to the health and/or safety of miners. Once a mine is in POV status, it can be removed from that status only upon (i) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA or (ii) no POV-related withdrawal orders being issued by MSHA within ninety (90) days following the mine operator being placed on POV status. However, from time to time one or more of our operations may meet the POV screening criteria, and we cannot make assurances that one or more of our operations will not be placed into POV status, which could materially and adversely affect our results of operations.

 

In April 2014, MSHA issued, among other provisions, a final rule lowering certain standards for respirable dust. Specifically, the rule reduces the overall dust standard from 2.0 to 1.5 milligrams per cubic meter of air and cuts in half the standard from 1.0 to 0.5 for certain mine entries and miners with pneumoconiosis, as well as changes sampling protocols and increases governmental oversight. On August 1, 2016, Phase III of MSHA’s respirable dust rule, imposing these new limits, went into effect. These final rules could make compliance more costly and approval for ventilation plans in underground coal mines more difficult to obtain.

 

In August 2016 and then again in January 2017 and 2018, MSHA adjusted its existing civil penalties for inflation, which prior to these dates were last set in 2007. A final rule was published in the federal register on January 23, 2019.  While these rules resulted in

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different relative impacts on particular penalty amounts, the net effect of these adjustments increased the amount of penalties that MSHA may impose on operators.

 

In January 2015, MSHA issued a final rule on the use of proximity detection systems on certain pieces of underground mining equipment. The rule requires, among other provisions, continuous mining machines to be equipped with electronic sensing devices that can detect the presence of miners in proximity to the machines and then cause moving or repositioning continuous mining machines to stop before contacting a miner. The final rule has a phase in period, depending upon the age of the continuous mining machine, of 8 to 36 months.

 

These requirements have, and will continue to have, a significant effect on our operating costs.

 

In June 2016, MSHA issued a request for information on approaches to control and monitor miners’ exposures to diesel exhaust. While MSHA’s existing regulations address health hazards to coal miners from exposure to diesel particulate matter (“DPM”), MSHA is requesting information on approaches that would improve control of DPM and diesel exhaust. The request for information and comments has been extended and is currently set to expire on September 25, 2020.  Although no rule has been proposed, if a rule that lowered DPM emission limits is proposed and adopted, it could have a significant impact on our operating costs.

 

At this time, it is not possible to predict the full effect that various new or proposed statutes, regulations and policies will have on our operating costs, but certain will increase our costs and those of our competitors. Some, but not all, of these additional costs may be passed on to customers.

 

Black Lung

 

Under the United States Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who have been diagnosed with pneumoconiosis and are current or former employees and must also pay into a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Through December 31, 2018, the trust fund was funded by an excise tax on production sold domestically of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales prices, excluding transportation.  For 2019, these rates decreased to a maximum of $0.50 per ton for deep-mined coal and $0.25 per ton for surfaced-mined coal, with neither amount to exceed 2% of the gross sales price, excluding transportation. On January 1, 2020, the rates reverted to pre-2019 levels.

 

U.S. Environmental Laws

 

We are subject to various U.S. federal, state and local environmental laws. Some of these laws, as discussed below, impose stringent requirements on our coal mining operations. U.S. federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance. U.S. federal and state inspectors are required to inspect our mining facilities on a frequent schedule. Future laws, regulations or orders, as well as future interpretations or more rigorous enforcement of existing laws, regulations or orders, may require increases in capital and operating costs, the extent of which we cannot predict.

 

The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”)

 

SMCRA, which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals from the OSM or the applicable state agency. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. Illinois has achieved primary control of enforcement through federal authorization.  SMCRA also stipulates compliance with many other major environmental statutes, including: the Clean Air Act; the Endangered Species Act; the Clean Water Act of 1972 (“CWA”); the Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”). SMCRA seeks to limit the adverse impacts of coal mining to the environment, and more restrictive requirements may be adopted from time to time.

 

SMCRA permit provisions include a complex set of requirements governing the following processes: coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; restoration to the approximate original contour; and re-vegetation. The disposal of coal refuse is also permitted under SMCRA. Both coarse refuse and slurry disposal areas, including the disposal of slurry underground, require permits from the Illinois Department of Natural Resources (“IDNR”).

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The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of culturally and historically important natural resources, soils, vegetation, and wildlife, as well as the assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, state programs and other complementary environmental programs that regulate coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required by the OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

 

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may take months or years to be reviewed and issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations.

 

The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to SMCRA’s adoption in 1977. The fee is $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from October 1, 2012 to September 30, 2021.

 

Various federal and state laws, including SMCRA, require us to obtain surety bonds or other forms of financial security to secure payment of certain long-term obligations, including mine closure and reclamation costs. In August 2016, the OSM issued a Policy Advisory discouraging state regulatory authorities from approving self-bonding arrangements. The Policy Advisory indicated that the OSM would begin more closely reviewing instances in which states accept self-bonds for mining operations. In the same month, the OSM also announced that it was beginning the rulemaking process to strengthen regulations on self-bonding.  Although we do not use self-bonding, the elimination or restriction of this option may lead more parties to see third party bonding which could end up restricting supply and increasing our costs of maintaining our bonds.

 

As of December 31, 2019, we had active outstanding surety bonds of $97.4 million primarily related to these matters. Changes in these laws or regulations could require us to obtain additional surety bonds or other forms of financial security.

 

Clean Air Act

 

The Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations may occur through Clean Air Act permitting requirements or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants.

 

Clean Air Act requirements that may directly or indirectly affect our operations include the following:

 

Acid Rain. Title IV of the Clean Air Act requires a two-phase reduction of sulfur dioxide emissions by electric utilities and applies to all coal-fired power plants generating greater than 25 megawatts of power. The affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on our customers and in turn, on our business in future years. We believe that implementation of the Act has resulted in increasing installations of pollution control devices as a control measure and thus, has created a growing market for our higher sulfur coal.

 

Fine Particulate Matter. The Clean Air Act requires the Environmental Protection Agency (“EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for criteria pollutants capable of adverse health effects. Areas that are not in compliance with these standards (referred to as “non-attainment areas”) must take steps to reduce emissions levels. The EPA has promulgated NAAQS for particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM10 and for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns, or PM2.5. Meeting current or potentially more stringent new PM standards may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement

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of the new PM2.5 standard will affect many power plants and coke plants, especially coal-fired power plants and all plants in non-attainment areas. Continuing non-compliance could prevent issuance of permits to plants within the non-attainment areas.

 

Ozone. Significant additional emissions control expenditures will be required at coal-fired power plants and coke plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers and coke plants will continue to become more stringent in the years ahead. In October 2015, the EPA updated the NAAQS for ozone to 70 parts per billion (ppb), down from 75 ppb. EPA has initiated a review of the 2015 rule, which will include the natural sources of ozone and international transport of ozone precursors. Separately, a lawsuit challenging the final rule is pending before the D.C. Circuit. The EPA has the authority to further strengthen ozone standards to protect public health, and the Clean Air Act requires periodic review of the NAAQS. If the NAAQS for ozone becomes more stringent in the future, it could increase the costs of operating coal-fired power plants.

 

Cross-State Air Pollution Rule (“CSAPR”). The CSAPR, which was intended to replace the previously developed Clean Air Interstate Rule (“CAIR”), requires states to reduce power plant emissions that contribute to ozone or fine particle pollution in other states. Under the CSAPR, emissions reductions were to have started January 1, 2012, for SO₂ and annual NOx reductions, and May 1, 2012, for ozone season NOx reductions. Several states and other parties filed suits in the United States Court of Appeals for the District of Columbia Circuit in 2011 challenging the CSAPR. On August 21, 2012, the D.C. Circuit vacated the CSAPR and ordered the EPA to continue administering CAIR, pending the promulgation of a replacement rule. On April 29, 2014, the United States Supreme Court found that the EPA was complying with statutory requirements when it issued CSAPR and reversed the D.C. Circuit’s vacation of CSAPR. On October 23, 2014, the D.C. Circuit granted the EPA’s request to lift the stay on CSAPR. In July 2015 and on remand from the Supreme Court of the United States, the D.C. Circuit upheld the provisions of CSAPR against broad challenges to the rule, but granted certain limited relief to states that brought “as applied” challenges to their respective emissions budgets set by EPA. In November 2015, the EPA issued a proposed CSAPR Rule Update in part to address the D.C. Circuit’s ruling regarding emissions budgets. The Rule Update required implementation of CSAPR’s emission budgets in the 2017 ozone season. In September 2016, the EPA finalized the CSAPR Rule Update for the 2008 ozone NAAQS. In May 2017, the rule reduced summertime NOx emissions from power plants in 22 states in the eastern U.S. In September 2017, EPA finalized further revisions to CSAPR to address the D.C. Circuit’s 2015 decision. The industry’s appeal of the 2015 decision was unsuccessful. It is unclear what effect, if any, CSAPR will have on our operations or results. Because U.S. utilities have continued to take steps to comply with CAIR, which requires similar power plant emissions reductions, and because utilities are preparing to comply with the Mercury and Air Toxics Standards regulations which require overlapping power plant emissions reductions, the practical impact of the reinstatement of CSAPR is expected to be limited. However, the cost of compliance with CAIR and now CSAPR could add to pressure to shut down units, which may further adversely affect the demand for our coal.

 

Mercury and Air Toxic Standards (“MATS”). On December 16, 2011, the EPA issued the MATS to reduce emissions of toxic air pollutants, including mercury, other metals and acid gases, from new and existing coal and oil fired power plants. Under the final rule, existing power plants had up to four years to comply with the MATS by installing or upgrading pollution controls, fuel switching, or using existing emissions controls as necessary to meet the compliance deadline. On June 29, 2015, the Supreme Court of the United States ruled that the EPA acted unreasonably when it determined that cost was irrelevant to the threshold finding that regulating these emissions was appropriate and necessary. This ruling did not overturn MATS in its entirety or allow previously-installed pollution controls to be removed. The EPA acted to address the Supreme Court ruling by issuing a supplemental finding that a consideration of costs would not change its threshold finding that regulation of these pollutants was appropriate and necessary. This supplemental finding was challenged in the D.C. Circuit.  During that litigation, EPA announced it intended to revisit its supplemental finding.  The D.C. Circuit postponed oral argument and has requested ongoing status reports from EPA.  On December 16, 2018, EPA proposed a revised supplemental finding along with a proposed risk and technology review for the MATS rule.  While EPA proposes to find it is no longer appropriate and necessary to regulate power plants under Section 112 of the Clean Air Act, EPA also proposes that MATS remain in place pending any future decision on delisting. These requirements could therefore continue to significantly increase our customers’ costs and to cause them to reduce their demand for coal, which may materially impact our results of operations. In August 2016, the EPA denied two petitions for reconsideration of startup and shutdown provisions in MATS, leaving in place the startup and shutdown provisions finalized in November 2014. The EPA also proposed changes to the electronic reporting requirements for MATS in an effort to streamline e-reporting requirements for power plants and make data about emissions more transparent and accessible to the public. EPA’s actions pertaining to startup and shutdown provisions and e-reporting requirements will have limited impact on coal-fired power plants relative to the overall impact of MATS.

 

Greenhouse Gases (“GHG”). Increasing concern about GHG, including carbon dioxide, emitted from burning coal at electricity generation plants has led to efforts at all levels of government to reduce their emissions, which could require utilities to burn less or eliminate coal in the production of electricity. Congress has considered federal legislation to reduce GHG emissions which, among other things, could establish a cap and trade system for GHG, including carbon dioxide emitted by coal burning power plants, and requirements for electric utilities to increase their use of renewable energy such as solar and wind power. Also, the EPA has taken

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several recent actions under the Clean Air Act to regulate GHG emissions. These include the EPA’s finding of “endangerment” to public health and welfare from GHG, its issuance in 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule, which requires large sources, including coal-fired power plants, to monitor and report GHG emissions to the EPA annually starting in 2011, and issuance of its Prevention of Significant Deterioration (“PSD”) and Title V Greenhouse Gas Tailoring Rule, which requires large industrial facilities, including coal-fired power plants, to obtain permits to emit, and to use best available control technology to curb GHG emissions. In response to Supreme Court and D.C. Circuit decisions, in August 2016 the EPA issued a proposed rule to revise existing PSD and Title V regulations to ensure that a source is not required to obtain a permit under the regulations solely because of GHG emissions. On September 20, 2013, the EPA proposed new source performance standards (“NSPS”), and in January 2014 issued final rules establishing NSPS, for GHG for new coal and oil-fired power plants, which likely will require partial carbon capture and sequestration to comply. On June 2, 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. The EPA issued its final rules, called the Clean Power Plan (“CPP”), in August 2015. Under the CPP, nationwide carbon dioxide emissions from existing plants would be reduced by 32% by 2030, while offering states and utilities flexibility in achieving these reductions. Both the CPP and the NSPS were challenged in the D.C. Circuit by several petitioners. On February 9, 2016, the U.S. Supreme Court issued a temporary stay of the CPP regulations. On September 27, 2016, an en banc panel of the D.C. Circuit Court of Appeals held oral argument in the case challenging the CPP. The Supreme Court stay will remain in place until the D.C. Circuit Court of Appeals rules on the merits of legal challenges to those regulations, and, if following a ruling by the D.C. Circuit Court of Appeals, a writ of certiorari from the Supreme Court is sought and granted, the stay will remain in place until the Supreme Court issues its decision on the merits.

 

Twenty-five states and other parties filed lawsuits challenging EPA’s final NSPS rule. One of the primary issues in these lawsuits is EPA’s establishment of standards of performance based on technologies including carbon capture and sequestration (“CCS”). New coal plants cannot meet the new standards unless they implement CCS, which reportedly is not yet commercially available or technically feasible.  Should EPA’s regulations be upheld by the court, they could materially impact the ability of customers to build new, or modify or reconstruct existing, coal-fired power plants, and thus reduce the demand for coal.

 

On March 28, 2017, President Trump issued Executive Order 13783, which called for the review of the CPP and NSPS, and EPA subsequently announced its intent to review these rules.   On October 16, 2017, EPA proposed a rule to repeal the CPP and on August 31, 2018, proposed the Affordable Clean Energy rule as a replacement to the CPP. Further, on December 20, 2018, EPA proposed revisions to the NSPS.  The D.C. Circuit has granted motions by the EPA to hold the cases challenging the CPP and NSPS in abeyance while the Agency reconsiders the rules.  EPA continues to file status reports in the cases while its rulemaking continues. The EPA has targeted May 2020 to finalize rule making.

 

In addition to the above developments, 195 nations (including the United States) signed the Paris Agreement, a long-term, international framework convention designed to address climate change over the next several decades. This agreement entered into force in November 2016 after more than 70 countries, including the United States, ratified or otherwise agreed to be bound by the agreement. The United States was among the countries that submitted its declaration of intended greenhouse gas reductions in early 2015, stating its intention to reduce U.S. greenhouse gas emissions by 26-28% by 2025 compared to 2005 levels. On June 1, 2017, President Trump announced the United States has withdrawn from the Paris Agreement, with an effective withdrawal date of November 4, 2020.  Certain state and local officials have stated that they will, nevertheless, voluntarily participate in the Paris Agreement. Over the long term, international participation in the Paris Agreement framework could reduce overall demand for coal which could have a material adverse impact on us. These effects could be more adverse to the extent regions of United States ultimately participate in these reductions (whether via the Paris Agreement or otherwise).  

 

Regional Emissions Trading. Nine northeast and mid-Atlantic states have cooperatively developed a regional cap and trade program, the Regional Greenhouse Gas Initiative (“RGGI”), intended to reduce carbon dioxide emissions from power plants in the region. There can be no assurance at this time that this, or similar state or regional carbon dioxide cap and trade programs (including the Western Climate Initiative, the Midwestern Greenhouse Gas Reduction Accord and the California Global Warming Solutions Act), in the states where our customers operate, will not adversely affect the future market for coal in the region.

 

Regional Haze. The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could adversely affect the future market for coal. In January 2017, EPA revised its regional haze rules for the second long-term strategy period and, in July 2017, EPA proposed guidance in connection with the rule.  On Jan. 17, 2018, EPA announced it will revisit aspects of the 2017 regional haze rule. The EPA has targeted May 2020 to finalize rule making.

 

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Resource Conservation and Recovery Act (“RCRA”)

 

The RCRA affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

 

Coal Ash Rule. Subtitle C of the RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under the RCRA. Following a large spill of coal ash waste at a coal burning power plant in Tennessee in 2008, the EPA, in 2010, proposed two alternative sets of regulations governing the management and storage of coal ash: one would regulate coal ash and related ash impoundments at coal-fired power plants under federal regulations governing hazardous solid waste under Subtitle C of the RCRA and the other would regulate coal ash as a non-hazardous solid waste under Subtitle D. In December 2014, the EPA announced that it would regulate coal combustion wastes as a nonhazardous substance under Subtitle D of the RCRA rather than as hazard waste pursuant to the provisions of Subtitle C. On April 17, 2015, the EPA finalized regulations under the solid waste provisions (“Subtitle D”) of RCRA and the finalized regulations became effective on October 19, 2015. While classifying coal combustion waste as a hazardous waste under Subtitle C would have led to more stringent requirements, the new rule could still increase customers’ operating costs and may make coal less attractive for electric utilities. Under the new rule, entities storing coal combustion wastes are susceptible to litigation from citizen groups or other stakeholders. The Coal Ash Rule is currently being challenged in the D.C. Circuit by both environmental and industry groups. The ongoing efforts by environmental groups to expand energy companies’ liability under RCRA could have potential adverse legal and business outcomes for coal-fired power plants. On Dec. 20, 2017, EPA submitted a draft proposed “remand” rule to the Office of Management and Budget for interagency review.  On March 1, 2018, EPA proposed changes to the regulation of coal ash.  EPA's regulatory agenda indicates a final rule will be issued by June 2019. On February 20, 2020, EPA published its proposed Federal CCR Permit Program in the Federal Register. 85 Fed. Reg. 9940-9987. As proposed, the new Federal CCR Permit Program represents a drastic change in direction from the Coal Ash Rule. It will do away with self-implementation, and will severely restrict the ability of citizens groups to enforce the Coal Ash Rule with RCRA citizen suits.

 

Most state hazardous waste laws exempt coal combustion waste and instead treat it as either a solid waste or a special waste. These laws may also be revised, and the EPA and the U.S. Department of Interior (“DOI”) have indicated that they intend to address placement of coal combustion waste on mine sites in a separate rulemaking. Additionally, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate EPA’s final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule. Any costs associated with handling or disposal of coal ash as hazardous waste would increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, potential liability for contamination caused by the past or future use, storage or disposal of ash could substantially increase.

 

Clean Water Act of 1972 (“CWA”)

The CWA established in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.

Total Maximum Daily Load. Total Maximum Daily Load (“TMDL”) regulations establish a process by which states may designate stream segments as “impaired” (not meeting present water quality standards) and then set pollutant allocation caps designed to restore those segments to attainment.  Those caps then must be translated into NPDES permit limits for contributing pollutant sources.  Industrial dischargers, including coal mines and plants, will be required to meet new TMDL allocations or more stringent water quality standards for these stream segments. The adoption of new TMDLs or more stringent water quality standards in receiving streams could hamper or delay the issuance of discharge and Section 404 permits, and if issued, could require new effluent limitations for our coal mines and could require more costly water treatment, which could adversely affect our coal production or results of operations. States are also adopting anti-degradation policies to designate certain water bodies or streams as “high quality.” These policies would prohibit the degradation of water quality in these streams. Water discharged from coal mines to high quality streams will be required to meet or exceed new “high quality” standards. The designation of high quality streams at or in the vicinity of our coal mines could require more costly water treatment and could adversely affect our coal production or results of operations.

Waters of the United States. In June 2015, the EPA published its final "Waters of the United States" (“WOTUS”) rule (“2015 Rule”), specifying the waterways that are subject to the jurisdiction of the EPA and the U.S. Army Corps of Engineers. The rule expands the scope of a navigable body of water to include tributaries that contain flowing water for some portion of a year. Although the rule is final, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the rule in October 2015. On January 22, 2018, the Supreme Court unanimously held that initial challenges to this rule belong in district courts rather than appeals courts and

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the Sixth Circuit’s stay of the 2015 Rule was lifted and existing challenges to the 2015 Rule in various Federal District Courts resumed. The EPA then delayed applicability of the 2015 Rule (through its “Suspension Rule”).  In August 2018, a South Carolina District Court issued an order enjoining EPA’s “Suspension Rule” nationwide, which had the effect of making the 2015 Rule effective in the states that are not subject to an order of Federal District Courts in Georgia and North Dakota prohibiting implementation of the 2015 Rule. States still subject to the 2015 Rule include Illinois, Ohio and Pennsylvania.  This has created uncertainty and EPA and the Corps have been addressing implementation issues under the 2015 Rule on a case-by-case basis.

Meanwhile, EPA and the Corps continue to move forward with their two-step, repeal and replace process for the 2015 Rule.  In June 2017 and again in June 2018, the agencies proposed to repeal the 2015 Rule.  And in December 2018, the agencies issued their formal proposal to replace the 2015 Rule with a new regulatory definition that would narrow the scope of federally regulated waterways to include only those waters that are oceans, rivers, streams, lakes, ponds, and wetlands, and their “naturally occurring surface water channels.”  The proposal also includes 11 exclusions, including for groundwater, ditches, and water-filled depressions “incidental to mining,” among others.  

On October 22, 2019, the Environmental Protection Agency and Department of the Army (the agencies) published a final rule to repeal the 2015 Rule defining “waters of the United States” and re-codify the regulatory text that existed prior to the 2015 Rule. This final rule became effective on December 23, 2019, and will be replaced by the Navigable Waters Protection Rule once the final rule takes effect.

With the final Step One rule, the agencies maintained a longstanding regulatory framework that is more familiar to and better-understood by the agencies, states, tribes, local governments, regulated entities, and the public until the final Navigable Waters Protection Rule takes effect.

On January 23, 2020, the EPA and the Department of the Army (Army) finalized the Navigable Waters Protection Rule to define “waters of the United States” (WOTUS). For the first time, the agencies are streamlining the definition so that it: includes four simple categories of jurisdictional waters, provides clear exclusions for many water features that traditionally have not been regulated, and defines terms in the regulatory text that have never been defined before.

Congress, in the Clean Water Act, explicitly directed the Agencies to protect “navigable waters.” The Navigable Waters Protection Rule regulates these waters and the core tributary systems that provide perennial or intermittent flow into them. The final rule fulfills Executive Order 13788 and reflects legal precedent set by key Supreme Court cases as well as robust public outreach and engagement, including pre-proposal input and comments received on the proposed rule.    

National Enforcement Initiatives. In February 2016, the EPA announced its National Enforcement Initiatives for fiscal years 2017-2019, including an initiative called “Keeping Industrial Pollutants Out of the Nation’s Waters,” which focuses the EPA enforcement resources on certain industrial sectors including mining. Under the initiative, the EPA will use water pollution data to target potential violations of discharge permits and increase the scrutiny of compliance issues. The initiative raises the possibility of stricter permit standards and increased enforcement attention for companies and facilities that discharge wastewater to waters of the U.S.

EPA issued a memorandum on August 21, 2018 transitioning EPA’s National Enforcement Initiatives to National Compliance Initiatives in order to recognize the Administration’s focus on compliance rather than enforcement “bean-counting.”  EPA plans to provide additional opportunity for engagement with states and tribes on compliance and to provide additional compliance assurance tools.  EPA is currently seeking comments on its proposed National Compliance Initiatives for fiscal years 2020-2023.  Under the proposed National Compliance Initiatives, EPA plans to transition away from its current “Keeping Industrial Pollutants Out of the Nation’s Waters” initiative to a new initiative focused on NPDES “Significant Non-Compliance (SNC) Reduction” including a goal of reducing significant noncompliance by 50 percent by fiscal year 2022.  Notably, all of EPA’s proposed compliance initiatives will focus on environmental and public health risks and will no longer target specific industry sectors.  

Steam Electric Power Generating Effluent Guidelines. In addition, environmental groups filed a notice of intent to sue the EPA for failing to update effluent limitation guidelines (“ELG”) under the Clean Water Act for coal-fired power plants to limit discharges of toxic metals from handling of coal combustion waste. In April 2013, the EPA released its proposed revised ELG to address toxic pollutants discharged from power plants, including discharges from coal ash ponds. On November 3, 2015, the EPA issued final revised ELG for the Steam Electric Power Generating category, effective January 4, 2016. These regulations, for the first time, set federal limits on certain metals in wastewater discharges from power plants. Individually and collectively, these regulations could make coal burning more expensive or less attractive for electric utilities and, in turn, impact the market for our products. Several industry groups have filed lawsuits challenging the rule in the U.S. Court of Appeals for the Fifth Circuit. The EPA issued an

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immediate administrative stay, followed by a longer-term postponement of the rule's standards until 2020. This lawsuit remains in abeyance pending reconsideration by the EPA.

On November 22, 2019, EPA proposed revisions to the 2015 rule for flue gas desulfurization wastewater and for bottom ash (BA) transport water and notice of this rulemaking was posted in the Federal Register.  The EPA estimates that its proposed rule would result in compliance cost savings of more than $175 million pre-tax annually while reducing the amount of pollutants discharged to our nation’s waters by approximately 100 million pounds per year over the existing Obama-era regulation as a result of: less costly FGD wastewater technologies that could be used to comply with the proposed relaxation of the 2015 rule’s selenium limit; less costly BA transport water technologies that could be used to comply with the proposed relaxation of the 2015 rule’s requirement to recycle 100 percent of the system water; a two-year extension of compliance time frames for FGD wastewater; and additional proposed subcategories for both FGD wastewater and BA transport water.

The additional pollutant reductions are attributable to a voluntary incentives program that provides the certainty of more time (until December 31, 2028) for plants to implement new requirements, if they adopt additional process changes and controls that achieve more stringent limitations on mercury, arsenic, selenium, nitrate/nitrite, bromide, and total dissolved solids in FGD wastewater.

Cooling Water Intake Structures. On May 19, 2014, the EPA finalized standards under Section 316(b) of the CWA that require the use of Best Technology Available (“BTA”) for minimizing the injury and death of fish and other aquatic life from cooling-water intake structures at existing power plants.  Because many coal-fired power plants utilize once-through cooling systems that are subject to this rule, implementation of the 316(b) regulations could, in addition to other regulatory burdens, result in further coal plant retirements and adversely affect the future market for coal.  

 

CERCLA and Similar State Superfund Statutes

 

CERCLA and similar state laws affect coal mining by creating liability for the investigation and remediation of releases of regulated materials into the environment and for damages to natural resources. Under these laws, joint and several liability may be imposed on waste generators, current and former site owners or operators and others regardless of fault, for all related site investigation and remediation costs.

 

Permits

 

Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters. These provisions include requirements for building dams; coal prospecting; mine plan development; topsoil removal, storage and replacement; protection of the hydrologic balance; subsidence control for underground mines; subsidence and surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.

 

 

Required permits include mining and reclamation permits under the SMCRA (see “U.S. Environmental - The Surface Mining Control and Reclamation Act”), issued by the IDNR, and wastewater discharge, or NPDES, permits under the CWA, issued by the Illinois Environmental Protection Agency (“IEPA”).  In addition to the required permits, for surface operations, the mining companies also need to obtain air quality permits from IEPA, fill and dredge permits from the United States Army Corps of Engineers and flood plain permits from the IDNR. For refuse disposal operations, the mining companies may need to obtain impounding permits or underground slurry disposal permits from the IDNR. In addition, MSHA approval for ventilation, roof control and numerous specific surface and underground operations must be obtained and maintained. The authorization and permitting requirements imposed by these and other governmental agencies are costly and may delay development or continuation of mining operations. In December 2014 the Council on Environmental Quality ("CEQ") released updated draft guidance discussing how federal agencies should consider the effects of GHG emissions and climate change in their National Environmental Policy Act (“NEPA”) evaluations.  On March 28, 2017, President Trump issued Executive Order 13783 which, among other things, directed CEQ to rescind its final guidance. While the guidance has been officially withdrawn CEQ has advised agencies that they can still utilize the guidance while it considers how to proceed on future guidance. This type of analyses may increase the likelihood of future challenges to the NEPA documents prepared for actions requiring federal approval. The application review process may take years to complete, and agencies may ask for submission of additional studies, evaluations or other information.  Regulatory authorities have considerable discretion in the timing of permit issuance.  Additionally, many environmental laws and regulations provide the public with the opportunity to comment on draft permits, and otherwise engage in the permitting process.   Permit applications are increasingly being challenged by environmental and other advocacy groups.  Accordingly, we may experience difficulty or delays in obtaining mining permits or other necessary approvals, or even face denials of permits altogether.

 

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Currently, we have the necessary permits for mining operations at each of the four complexes. Continued and expanded operations will require additional or renewed permits. These additional permits may include significant permit revisions to the SMCRA mining permit and fill and dredge permits; new NPDES, new SMCRA, new impounding, and possible CWA permits for additional refuse areas; and revisions to the SMCRA permit and a NPDES construction permit for additional bleeder shafts. Due to various and, sometimes, interrelated requirements from different agencies, it is not possible to predict an average or approximate time frame required to obtain all permits and approvals to operate new or expanded mines. In addition, expanded permitting activity in Illinois coupled with challenges from environmental groups will likely increase the various agencies’ permit and approval review time in the future.

 

Appeals of permits issued by the IEPA, including some CWA permits, are made to the Illinois Pollution Control Board (“IPCB”). The IPCB is an independent agency with five board members appointed by the Governor of the State of Illinois that both establishes environmental regulations under the Illinois Environmental Protection Act and decides contested environmental cases. Appeals before the IPCB are based on alleged violations of environmental laws as found in the permit and the accompanying permit record without additional testimony or evidence being taken. Appeals from the IPCB decisions are made to an Illinois appellate court.

Requests for an administrative review of permits issued by the IDNR, such as the SMCRA permits, are made to an IDNR hearing officer. Although the basis of the request for the administrative review is the alleged violations in the permit and the permit record, the administrative code rules allow for additional discovery and an evidentiary hearing. Appeals from the IDNR hearing officer’s decisions are made to an Illinois Circuit Court.

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Item 1A. Risk Factors

 

An investment in our common units involves risks. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the risks described below, together with the other information in this Annual Report on Form 10-K, before investing in our common units. Our business, financial condition, results of operation and cash available for distribution could be materially and adversely affected by future events. In such case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment in, and expected return on, our common units.

 

Risks Related to Filing Under Chapter 11 of the Bankruptcy Code

 

As a result of the Foresight Chapter 11 Cases, we are subject to the risks and uncertainties associated with Chapter 11 cases, and operating under Chapter 11 may restrict our ability to pursue strategic and operational initiatives.

 

For the duration of the Foresight Chapter 11 Cases, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy.  These risks include:

 

 

These risks and uncertainties could affect our business and operations in various ways.  For example, negative events or publicity associated with the Foresight Chapter 11 Cases could adversely affect our relationships with our suppliers, customers and employees.  In particular, critical vendors may determine not to do business with us due to Foresight Chapter 11 Cases and we may not be successful in securing alternative sources.  Also, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond timely to certain events or take advantage of opportunities.  Because of the risks and uncertainties associated with the Foresight Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 process may have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

 

Prosecution of the Foressight Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

 

While the Foresight Chapter 11 Cases continue, our management will be required to spend a significant amount of time and effort focusing on the cases.  This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Foresight Chapter 11 Cases are protracted.

 

During the Foresight Chapter 11 Cases, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition.  A loss of key personnel or material erosion of employee morale could have a materially adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations.  The failure to retain or attract members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

 

If we are unable to confirm a Chapter 11 plan of reorganization, we could be required to liquidate under Chapter 7 of the Bankruptcy Code.

 

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code.  We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative

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expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

 

Our post-bankruptcy capital structure is yet to be determined, and any changes to our capital structure may have a material adverse effect on existing debt and security holders.

 

Our post-bankruptcy capital structure will be set pursuant to a plan that requires Bankruptcy Court approval.  The reorganization of our capital structure may include exchanges of new debt or equity securities for our existing debt and equity securities, and such new debt may be issued at different interest rates, payment schedules and maturities than our existing debt securities and existing equity securities are expected to be cancelled.  The success of a reorganization through any such exchanges or modifications will depend on approval by the Bankruptcy Court and the willingness of existing debt and security holders to agree to the exchange or modification, subject to the provisions of the Bankruptcy Code, and there can be no guarantee of success.  If such exchanges or modifications are successful, holders of our debt may find their holdings no longer have any value or are materially reduced in value, or they may be converted to equity and be diluted or may be modified or replaced by debt with a principal amount that is less than the outstanding principal amount, longer maturities and reduced interest rates.  There can be no assurance that any new debt or equity securities will maintain their value at the time of issuance.  If existing debt or equity holders are adversely affected by a reorganization, it may adversely affect our ability to issue new debt or equity in the future.

 

Any Chapter 11 plan that we may implement will be based in large part upon assumptions and analyses developed by us.  If these assumptions and analyses prove to be incorrect, or adverse market conditions persist or worsen, our plan may be unsuccessful in its execution.

 

Any Chapter 11 plan that we may implement will affect both our capital structure and the ownership, structure and operation of our remaining businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances.  Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure; and (ii) the overall strength and stability of general economic conditions, both in the U.S. and in global markets.  The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

 

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, consolidated adjusted EBITDA, capital expenditures, debt service and cash flow.  Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate.  In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure.  Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated.  Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations.  The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

 

We may be subject to claims that will not be discharged in our Chapter 11 cases, which could have a material adverse effect on our financial condition and results of operations.

 

The Bankruptcy Code provides that the confirmation of a Chapter 11 plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation.  With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization.  Any claims not ultimately discharged through a Chapter 11 plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

 

Operating in bankruptcy for a long period of time may harm our business.

 

A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations, and liquidity.  So long as the Foresight Chapter 11 Cases continue, senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on business operations.  A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success of our business.  In addition, the longer the Foresight Chapter 11 Cases continue, the

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more likely it is that customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

So long as the Foresight Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Foresight Chapter 11 Cases, including the cost of litigation.  In general, litigation can be expensive and time consuming to bring or defend against.  Such litigation could result in settlements or damages that could significantly affect our financial results.  It is also possible that certain parties will commence litigation with respect to the treatment of their claims under a plan of reorganization.  It is not possible to predict the potential litigation that we may become party to, nor the final resolution of such litigation.  The impact of any such litigation on our business and financial stability, however, could be material.

Should the Foresight Chapter 11 Cases be protracted, we may also need to seek new financing to fund operations.  If we are unable to obtain such financing on favorable terms or at all, the chances of confirming a Chapter 11 plan may be seriously jeopardized and the likelihood that we will instead be required to liquidate our assets may increase.

 

Risks Related to Our Business

 

We may not have sufficient cash from operations to enable us to pay distributions.

 

Even though we are currently restricted under our debt documents from paying certain distributions, the amount of cash we may be able to distribute on our common and subordinated units in the future primarily depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

 

In addition, the actual amount of cash we have available for distribution depends on several other factors, including:

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We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.

 

At December 31, 2019, our indebtedness (excluding our sale-leaseback arrangements) was approximately $1.3 billion. Our substantial indebtedness could adversely affect our results of operations, business and financial condition, and our ability to meet our debt obligations and continue payment of distributions to our unitholders:

 

 

An extended decline in coal prices within the industry or increase in the costs of mining could continue to adversely affect our operating results and the value of our coal reserves.

 

Our operating results largely depend on the margins that we earn on our coal sales. A significant amount of our coal sales contracts are forward sales contracts under which customers agree to pay a specified price under their contracts for coal to be delivered in future years. The profitability of these contracts depends on our ability to adequately control the costs of the coal production underlying the contracts. Our margins reflect the price we receive for our coal less our cost of producing and transporting our coal and are impacted by many factors, including:

 

 

An extended decline in the price that we receive for our coal or increases in the costs of mining our coal could have a material adverse effect on our operating results and our ability to generate the cash flows we require to invest in our operations, satisfy our obligations and resume the payment of distributions to unitholders. To the extent our costs increase but pricing under these coal sales contracts remains fixed or declines, we will be unable to pass increasing costs on to our customers. If we are unable to control our costs, our profitability under our forward sales contracts may be impaired and our results of operations, business and financial condition, and our ability to make distributions to our unitholders could be materially and adversely affected.

 

Our future costs of production may be substantially higher than our historical costs due to a number of factors, including increased regulatory requirements applicable to coal mining, and the success of longwall mining operations at our Hillsboro mine.

 

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A decrease in the use of coal by electric utilities or in the demand for electricity could affect our ability to sell the coal we produce.

 

The amount of coal consumed by the electricity generation industry is affected primarily by the overall demand for electricity and by environmental and other governmental regulations as well as by the price and availability of renewable energy sources, including biomass, hydroelectric, wind and solar power and other non-renewable fuel sources, including natural gas and nuclear power. The low price of natural gas has resulted, in some instances, in domestic generators increasing natural gas consumption while decreasing coal consumption. Future environmental regulation of GHG emissions could accelerate the use by utilities of fuels other than coal. Domestically, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for our coal. A number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources to generate a certain percentage of their power. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. Certain customers have foregone or delayed capital investments necessary to keep their existing coal plants operating in an efficient and competitive manner, which may lead to the reduced utilization or earlier closure of these plants. A decrease in coal consumption by the electricity generation industry could adversely affect the price of coal, which could negatively affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

A certain amount of our coal is shipped through contractual arrangements with minimum volume requirements that are due regardless of whether coal is actually shipped or mined.

 

A certain amount of the coal that we ship is through contractual arrangements that have minimum volume requirements. 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 (transportation to and through export terminals). To the extent coal pricing to export markets decline, we expect our sales volume to the export markets to also continue to decline thereby resulting in higher charges for shortfalls on minimum contractual throughput volume requirements. If our operations do not meet the minimum volume requirements then we could suffer from a shortage of cash due to the ongoing requirement to pay minimum payments despite a lack of shipping and the associated sales revenue.  As a result, our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders may be materially adversely affected.

 

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our results of operations.

 

For the year ended December 31, 2019, we derived approximately 68% of our total coal sales revenues from our four largest customers, including 37% of our coal sales revenues from our largest customer. Negotiations to extend existing agreements or enter into long-term agreements with these and other customers may not be successful, and such customers may not continue to purchase coal from us. If these four customers or any of our top customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to our top customers on terms as favorable to us as the terms under our current contracts, our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders may be materially adversely affected.

 

We may not be able to incur debt or access the debt and equity capital markets because of the state of the coal industry and the deterioration of the financial markets.

 

The cost of raising money in the debt and equity capital markets has increased substantially, particularly for the U.S. coal industry, while the availability of funds from those markets generally has diminished. The cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to those of our current debt and have reduced and, in some cases, ceased to provide funding to borrowers or determined to stop providing credit to the coal industry. We may be unable to incur indebtedness under credit facilities or term loans on reasonable terms or at all.

 

Our current capital structure restricts our ability to raise further debt, subject to exceptions that can be significant.  Even if we were to need additional funding, due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to refinance our existing indebtedness, take advantage of business opportunities or respond to competitive pressures, which could negatively affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

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An increase in interest rates may cause the market price of our common units to decline.

 

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

 

Our general partner has limited its liability regarding our obligations and under certain circumstances unitholders may have liability to repay distributions.

 

Our general partner has limited its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

 

Unitholders may have to repay amounts wrongfully returned or distributed to them.

 

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law are liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Failure to meet certain provisions in our coal supply agreements could result in economic penalties.

 

Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as heat value, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, purchasing replacement coal in a higher-priced open market, rejection of deliveries or termination of the contracts. In some of the contract price adjustment provisions, failure of the parties to agree on price adjustments may allow either party to terminate the contract.

 

Many agreements also contain provisions that permit the parties to adjust the contract price upward or downward for specific events, including changes in the laws regulating the timing, production, sale or use of coal. Moreover, a limited number of these agreements permit the customer to terminate the agreement if transportation costs increase substantially or, in the event of changes in regulations affecting the coal industry, such changes increase the price of coal beyond specified amounts. Additionally, a number of agreements provide that customers may terminate the agreement in the event a new or amended environmental law or regulation prevents or restricts the customer from utilizing coal supplied by us and/or requires material additional capital or operating expenditures to utilize such coal.

 

Certain of our customers may seek to defer contracted shipments of coal, which could affect our results of operations and liquidity.

 

From time to time, certain customers have sought, and others may seek, to delay shipments or request deferrals under existing agreements. There is no assurance that we will be able to resolve existing and potential deferrals on favorable terms, or at all. Any such deferrals may have an adverse effect on our business, results of operations and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

We sell a portion of our uncommitted tons in the spot market which is subject to volatility.

 

We derive a portion of our revenue from coal sales in the spot market, typically defined as contracts with terms of less than one year. The pricing in spot contracts is significantly more volatile than pricing through long-term coal supply agreements because it is subject to short-term demand swings. If spot market pricing for coal is unfavorable, this volatility could materially adversely affect our

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results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Some of our customers blend our coal with coal from other sources, making our sales dependent upon our customers locating additional sources of coal.

 

Our coal’s characteristics, particularly the sulfur or chlorine content, are such that many of our customers blend our coal with other purchased supplies of coal before burning it in their boilers. Some of our current or future coal sales may therefore be dependent in part on those customers’ ability to locate additional sources of coal with offsetting characteristics which may not be available in the future on terms that render the customers’ overall cost of blended coal economic. A loss of business from such customers may materially adversely affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Global economic conditions, or economic conditions in any of the industries in which our customers operate, and continued uncertainty in financial markets may have material adverse impacts on our business and financial condition that we cannot predict.

 

If economic conditions or factors that negatively affect the economic health of the U.S., Europe, Africa, South America, Central America, or Asia worsen, our revenues could be reduced and thus adversely affect our results of operations. Markets have historically experienced disruptions relating to volatility in security prices, diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, failure and potential failures of major financial institutions, high unemployment rates and volatility in interest rates. Such conditions may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. Also, if the economic impact of a downturn impacts foreign markets disproportionately, global currencies may weaken against the U.S. dollar. A weaker U.S. dollar would unfavorably impact our ability to export our coal by making it more expensive for foreign buyers. We believe that deterioration or a prolonged period of economic weakness will have an adverse impact on our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Longwall mining efforts at Hillsboro Energy’s Deer Run Mine may ultimately not succeed.

 

Since March 26, 2015, underground mining at Hillsboro Energy’s Deer Run Mine had been prevented by spontaneous combustion occurring within the mine. Hillsboro could not restore the mine to production until such time as it could establish that the spontaneous combustion was extinguished, determine that future spontaneous combustion events are not likely, and would no longer expose the workforce to a health and safety risk upon resumption of underground mining. 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 and, since that time, have been undertaking steps to re-enter the mine upon satisfaction of certain conditions.

 

In December 2017, we submitted a re-entry plan to MSHA which contains a plan for the permanent sealing of the current longwall district of the Hillsboro mine immediately upon MSHA’s approval.  MSHA approved the plan and, as a result, certain longwall equipment and other related assets were permanently sealed within and were not recovered, resulting in a $42.7 million impairment loss during 2017.

 

In connection with certain litigation matters related to the combustion event and due to additional facts and circumstances arising in April 2018, we announced that our Hillsboro operation would be closed and certain long-lived assets consisting primarily of mineral reserves and certain buildings and structures, machinery and equipment, and other related assets were not expected to generate future positive cash flows. As the expected future cash flows were projected to be immaterial and not sufficient to support the recoverability of the assets’ carrying values, the assets were reduced to their estimated fair values.  As such, we recorded an aggregate impairment charge of $110.7 million during 2018.  

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In October 2018, we reached a settlement of certain litigation matters associated with the Hillsboro combustion event.  We resumed production in January 2019 with one continuous miner section and in March 2020 we recommenced longwall mining operations. However, there can be no assurances that longwall mining operations at the Deer Run Mine will be successful.  As a result, our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders may be materially adversely affected.

 

A substantial amount of our coal reserves are leased or subleased and are subject to minimum royalty payments that are due regardless of whether coal is actually mined.

 

A substantial amount of the reserves that our operating companies lease are subject to minimum royalty payments, including those leases with affiliates. Failure to meet minimum production requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself along with cetain mining equipment on the premises. If certain operations do not meet production goals then we could suffer from a shortage of cash due to the ongoing requirement to pay minimum royalty payments without any corresponding production and coal sales. As a result, our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders may be materially adversely affected.

 

The availability or reliability of current transportation facilities could affect the demand for our coal or temporarily impair our ability to supply coal to our customers. In addition, our inability to expand our transportation capabilities and options could further impair our ability to deliver coal efficiently to our customers.

 

We depend upon rail, barge, ocean-going vessels and port facilities to deliver coal to customers. Disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays, lack of rail or port capacity or other events could temporarily impair our ability to supply coal to customers and thus could adversely affect our results of operations, cash flows and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Additionally, if there are disruptions of the transportation services provided by the railroad and we are unable to find alternative transportation providers to ship our coal, our business and profitability could be adversely affected. While we currently have contracts in place for transportation of coal from our facilities and have continued to develop alternative transportation options, there is no assurance that we will be able to renew these contracts or to develop these alternative transportation options on terms that remain favorable to us. Any failure to do so could have a material adverse impact on our financial position and results of operations as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Significant increases in transportation costs could make our coal less competitive when compared to other fuels or coal produced from other regions.

 

Transportation costs represent a significant portion of the total cost of coal for our customers and the cost of transportation is an important factor in a customer’s purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuations in the price of diesel fuel, could make coal a less competitive source of energy when compared to other fuels, such as natural gas, or could make our coal less competitive than coal produced in other regions of the U.S. or abroad.

 

 

Significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country and from abroad, including coal imported into the U.S. Coordination of the many eastern loading facilities, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern U.S. inherently more expensive on a per ton-mile basis than shipments originating in the western U.S. Historically, high coal transportation rates and transportation constraints from the western coal producing areas into eastern U.S. markets limited the use of western coal in those markets. However, a decrease in rail rates or an increase in rail capacity from the western coal producing areas to markets served by eastern U.S. producers could create major competitive challenges for eastern producers. Increased competition due to changing transportation costs could have an adverse effect on our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Our ability to mine and ship coal may be affected by adverse weather conditions, which could have an adverse effect on our revenues.

 

Adverse weather conditions can impact our ability to mine and ship our coal and our customers’ ability to take delivery of our coal. Lower than expected shipments by us during any period could have an adverse effect on our revenues. In addition, severe weather may affect our ability to conduct our mining operations and severe rain, ice or snowfall may affect our ability to load and

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transport coal. If we are unable to conduct our operations due to severe weather, it could have an adverse effect on our results of operations or business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Our mining operations are extensively regulated which imposes significant costs on us, and changes to existing and potential future regulations or violations of regulations could increase those costs or limit our ability to produce coal.

 

The coal mining industry is subject to increasingly strict regulations by federal, state and local authorities on matters such as:

 

Because we engage in longwall mining, subsidence issues are particularly important to our operations. Failure to timely secure subsidence rights or any associated mitigation agreements could materially affect our results by causing delays or changes in our mining plan through stoppages or increased costs because of the necessity of obtaining such rights.

 

Because of the extensive and detailed nature of these regulatory requirements, it is extremely difficult for us and other underground coal mining companies in particular, as well as the coal industry in general, to comply with all requirements at all times. We have been cited for violations of regulatory requirements in the past, and we expect to be cited for violations in the future. None of our violations to date has had a material impact on our operations or financial condition, but future violations may have a material adverse impact on our business, result of operations or financial condition. While it is not possible to quantify all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations, and delays in the receipt of or failure to receive or revocation of necessary government permits, could substantially increase the cost of coal mining or have a material adverse effect on our results of operations, cash flows and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Extensive environmental regulations, including existing and potential future regulatory requirements relating to air emissions, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.

 

The utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, particularly with respect to air emissions, which could affect demand for our coal. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants will, or are expected to become effective in coming years. In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.

 

More stringent air emissions limitations may require significant emissions control expenditures for many coal-fired power plants and could have the effect of making coal-fired plants less profitable. As a result, some power plants may continue to switch to other fuels that generate less of these emissions or they may close. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal.

 

It is possible that new environmental legislation or regulations may be adopted, or that existing laws or regulations may be differently interpreted or more stringently enforced, any of which could have a significant impact on our mining operations or our customers’ ability to use coal.

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Recent developments in the regulation of GHG emissions and coal ash could materially adversely affect our customers’ demand for coal and our results of operations, cash flows and financial condition.

 

Coal-fired power plants produce carbon dioxide and other GHGs as a by-product of their operations. GHG emissions have received increased scrutiny from local, state, federal and international government bodies. Future regulation of GHGs could occur pursuant to U.S. treaty obligations or statutory or regulatory change. The EPA and other regulators are using existing laws, including the federal Clean Air Act, to limit emissions of carbon dioxide and other GHGs from major sources, including coal-fired power plants that may require the use of “best available control technology.” For example, in 2011, the EPA issued regulations, including permitting requirements, restricting GHG emissions from any new U.S. power plants, and from any existing U.S. power plants that undergo major modifications that increase their GHG emissions. In response to recent decisions by the Supreme Court and the D.C. Circuit Court of Appeals, in August 2016, the EPA issued a proposed rule to revise its existing GHG permitting program to ensure that a source is not required to obtain a permit solely because of its GHG emissions. In addition, in June 2013, President Obama announced additional initiatives intended to reduce greenhouse gas emissions globally, including curtailing U.S. government support for public financing of new coal-fired power plants overseas and promoting fuel switching from coal to natural gas or renewable energy sources. Global treaties have been adopted that place restrictions on carbon dioxide and other GHG emissions. In October 2015, the EPA formally published final new source performance standards (“NSPS”) for carbon dioxide emissions from new power plants.  To meet the NSPS, new coal plants are likely to be required to install carbon capture and storage technology.

 

On August 3, 2015, President Obama and the EPA announced the final Clean Power Plan (“CPP”), which includes final emission guidelines for states to follow in developing plans to reduce GHG emissions from existing fossil fuel-fired electric generating units (“EGU”s) as well as limits on GHG emission rates for new, modified and reconstructed EGUs. Under the CPP, nationwide carbon dioxide emissions would be reduced by 32% by 2030, while offering states and utilities flexibility in achieving these reductions. On February 9, 2016, the U.S. Supreme Court issued a temporary stay of the CPP regulations. The stay will be in place until the D.C. Circuit Court of Appeals rules on the merits of legal challenges to those regulations, and, if following a ruling by the D.C. Circuit Court of Appeals, a writ of certiorari from the Supreme Court is sought and granted, the stay will remain in place until the Supreme Court issues its decision on the merits. An en banc panel of the D.C. Circuit Court of Appeals held oral argument in the case challenging the CPP on September 27, 2016. Lawsuits have also been filed in the D.C. Circuit challenging EPA’s final NSPS rule for CO2 from new, modified, and reconstructed power plants under the CAA Section 111(b), which challenges EPA’s establishment of standards of performance based on technologies including CCS.  The finalization of the NSPS for new air pollutant sources under Section 111(b) is a prerequisite for the use of authority under Section 111(d) to regulate existing sources, which is the authoritative basis for the Clean Power Plan.  On March 28, 2017, President Trump issued Executive Order 13783, which called for the review of CPP, and EPA announced its review of the CPP.   On October 16, 2017, EPA proposed a rule to repeal the CPP, with a comment period closing April 26, 2018. Further, on December 20, 2018, EPA proposed revisions to the NSPS.  The D.C. Circuit has granted motions by the EPA to hold the cases challenging the CPP and NSPS in abeyance while the Agency reconsiders the rules.  EPA continues to file status reports in the cases while its rulemaking continues. The EPA has targeted May 2020, to finalize rule making. Even without the legal challenges, demand for coal will likely be further decreased as a result of the CPP, potentially significantly, and could adversely impact our business.

 

In addition, state and regional climate change initiatives to regulate GHG emissions, such as the RGGI of certain northeastern and Mid-Atlantic states, the Western Climate Initiative, the Midwestern Greenhouse Gas Reduction Accord and the California Global Warming Solutions Act, either have already taken effect or may take effect before federal action. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities. There have also been several public nuisance lawsuits brought against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs are seeking various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court recently determined that such claims cannot be pursued under federal law, plaintiffs may seek to proceed under state common law.

 

In December 2014, the EPA announced that it had determined to regulate coal combustion wastes, sometimes referred to as coal ash or coal combustion by-products (“CCB”), as a nonhazardous substance under Subtitle D of the RCRA rather than as a hazardous waste product under Subtitle C of the RCRA. On April 17, 2015, the EPA finalized regulations under the solid waste provisions (“Subtitle D”) of RCRA which became effective on October 19, 2015. While classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, regulation under Subtitle D imposes certain requirements on management of CCBs and may still increase our customers’ operating costs and potentially reduce their ability to purchase coal. On February 20, 2020, EPA published its proposed Federal CCR Permit Program in the Federal Register. 85 Fed. Reg. 9940-9987. As proposed, the new Federal CCR Permit Program represents a drastic change in direction from the Coal Ash Rule. It will do away with self-implementation, and will severely restrict the ability of citizens groups to enforce the Coal Ash Rule with RCRA citizen suits.

 

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The enactment of these and other laws or regulations regarding emissions from the combustion of coal or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources thereby reducing demand for our coal. Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fueled electricity generating plants and certain new export transloading facilities due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired generation plants could also reduce the demand for our coal. Further, policies limiting available financing for the development of new coal-fueled power plants could adversely impact the global demand for coal in the future. The potential impact on us of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws, regulations or other policies may have on our results of operations, cash flows and financial condition as well as our ability to meet our debt obligations and pay distributions to our unitholders. However, such impacts could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Extensive governmental regulation pertaining to safety and health imposes significant costs on our mining operations and could materially and adversely affect our results of operations.

 

Federal and state safety and health regulations in the coal mining industry are among the most comprehensive and extensive systems for protection of employee safety and health affecting any U.S. industry. Compliance with these requirements imposes significant costs on us and can result in reduced productivity. New health and safety legislation, regulations and orders may be adopted that may materially and adversely affect our mining operations.

 

Federal and state health and safety authorities inspect our operations, and there may be a continued increase in the frequency and scope of these inspections. In recent years, federal authorities have also conducted special inspections of coal mines for, among other safety concerns, the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, the federal government has announced that it is considering changes to mine safety rules and regulations, which could potentially result in or require additional safety training and planning, enhanced safety equipment, more frequent mine inspections, stricter enforcement practices and enhanced reporting requirements.

 

In addition, in March 2013, MSHA implemented a revised POV standard. Under the revised standard, mine operators are no longer entitled to a ninety day notice of potential POV. In addition, MSHA began screening for POV by using issued citations and orders, prior to their final adjudication. If a mine is designated as having a POV, MSHA will issue an order withdrawing miners from any areas affected by violations which pose a significant and substantial hazard to the health and/or safety of miners. Once a mine is in POV status, it can be removed from that status only upon (i) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA or (ii) no POV-related withdrawal orders being issued by MSHA within ninety (90) days following the mine operator being placed on POV status. Litigation testing the validity of the standard and its application by MSHA is ongoing. However, from time to time one or more of our operations may meet the POV screening criteria, and we cannot make assurances that one or more of our operations will not be placed into POV status, which could materially and adversely affect our results of operations.

 

In 2014, MSHA began implementation of a finalized new regulation titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.” In addition to lowering the allowable respirable dust in certain areas of underground coal mines, the final rule changes dust sampling requirements, increases MSHA oversight, and could make ventilation plans more difficult to obtain, all of which is expected to increase mining costs. The final rule became effective in August 2016.

 

In June 2016, MSHA issued a request for information on approaches to control and monitor miners’ exposures to diesel exhaust. While MSHA’s existing regulations address health hazards to coal miners from exposure to DPM, MSHA is requesting information on approaches that would further improve control of DPM and diesel exhaust. Although no rule has been proposed, if a rule that lowered DPM emission limits is proposed and adopted, it would likely make compliance more costly.

 

We must compensate employees for work-related injuries. If adequate provisions for workers’ compensation liabilities are not made, our future operating results could be harmed. Also, federal law requires we contribute to a trust fund for the payment of benefits and medical expenses to certain claimants. Prior to January 1, 2019, the trust fund was funded by an excise tax on coal production of $1.10 per ton for underground coal sold domestically, not to exceed 4.4% of the gross sales price, excluding transportation. For 2019, the excise tax decreased to $0.50 per ton for underground coal sold domestically, not to exceed 2% of the gross sales price, excluding transportation. On January 1, 2020, the excise tax amounts returned to pre-2019 levels.  If this tax increases, or if we could no longer pass it on to the purchasers of our coal under our coal sales agreements, our operating costs could be increased and our results could be materially and adversely affected. If new laws or regulations increase the number and award size of claims, it could materially and adversely harm our business. In addition, the erosion through tort liability of the protections we are currently provided by workers’

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compensation laws could increase our liability for work-related injuries and have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Extensive environmental regulations, including existing and potential future regulatory requirements, pertaining to discharge of materials into the environment, including wastewater, impose significant costs on our mining operations and could materially and adversely affect our production, cash flow and profitability.

 

Our mining operations are subject to numerous complex regulatory, compliance, and enforcement programs. While we believe we are in compliance with all environmental regulatory requirements, our operations have, from time to time, been issued violation notices from various agencies, including the IEPA. In July 2014, following issuance of a violation notice, we entered into a plan which resolves all outstanding violations regarding pumped mine discharges at our Sugar Camp operation and provides long-term water treatment and disposal capacity for that operation. We believe we are currently in compliance with the plan. However, we can make no assurances that Sugar Camp will not receive future violations notwithstanding the implementation of the plan, and these violations may result in the assessment of fines or penalties, or, a temporary or permanent suspension of the affected mining operations. Additionally, we cannot make assurances that one or more of our operations will not receive future violation notices that result in fines, penalties, mandatory corrective action plans, or suspension of mining activities. Such corrective action plans or suspensions could have a material adverse effect on our results of operations, cash flows and financial condition, as well as our ability to make distributions to our unitholders.

 

Additionally, regulatory agencies may, from time to time, add more stringent compliance requirements to our environmental permits either by rule, or regulation or during the permit renewal process. More stringent requirements could lead to increases in costs and could materially and adversely affect our production, cash flow and profitability. For example, on April 30, 2013, citing lack of resources and the priority of other matters, the EPA denied a petition brought by environmental groups seeking to add coal mines to the Clean Air Act section 111 list of stationary source categories, which would have had the effect of regulating methane emissions from coal mines in some manner. Following the environmental groups’ challenge to EPA’s denial, the United States Court of Appeals for the District of Columbia upheld the EPA’s action in May 2014. However, the EPA could, in the future, determine to add coal mines to the list of regulated sources and impose emission limits on coal mines, which could have a significant impact on our mining operations.

 

We may be unable to obtain, maintain or renew permits necessary for our operations and to mine all of our coal reserves, which would materially and adversely affect our production, cash flow and profitability.

 

In order to develop our economically recoverable coal reserves, we must regularly obtain, maintain or renew a number of permits that impose strict requirements on various environmental and operational matters in connection with coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. Permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical and could result in the discontinuance of mine development or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements prepared in connection with applicable regulatory processes, and otherwise engage in the permitting process, including bringing citizens’ claims to challenge the issuance or renewal of permits, the validity of environmental impact statements or performance of mining activities. Our mining operations are currently, and may become in the future, subject to legal challenges before administrative or judicial bodies contesting the validity of our environmental permits under SMCRA and the CWA, among other statutory provisions. Accordingly, required permits may not be issued in a timely fashion or renewed at all, or permits issued or renewed may not be maintained, may be challenged or may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flow, and profitability as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

We make no assurances that we will be able to obtain, maintain or renew any of the governmental permits that we need to continue developing our proven and probable coal reserves. Further, new legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment and to human health and safety that would further regulate and tax the coal industry may also require us to change operations significantly or incur increased costs.

 

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published their final rule expanding the definition of “Waters of the United States” (“WOTUS Rule”) that expands the jurisdiction of the EPA and the United States Army Corps of Engineers to regulate waters not previously regulated. The WOTUS Rule became effective on August 28, 2015 and, if fully implemented, will

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likely add an additional layer of permitting to activities involving previously non-jurisdictional waters and likely cause states that have jurisdiction over their own waters to enhance their already robust regulatory programs, adding delays to the permitting process and extending review times even further for regulatory agencies. On October 9, 2015, the United States Court of Appeals for the Sixth Circuit issued a temporary nationwide stay of the effectiveness of the WOTUS Rule while litigation regarding its legality progresses. The temporary stay could be lifted at any time. The WOTUS Rule has been challenged in several jurisdictions, both at the district and appellate court levels. In addition to issuing a nationwide stay, the Sixth Circuit ruled that district courts do not have jurisdiction to consider the matter. Industry groups opposed this decision and asked the Supreme Court to overturn the Sixth Circuit and send the cases back to the district courts. On January 13, 2017, the Supreme Court agreed to review the Sixth Circuit’s finding that it has jurisdiction to hear challenges to the rule. This rule, if it becomes final, could impact our ability to timely obtain necessary permits. Such changes could have a material adverse effect on our financial condition and results of operations as well as our ability to meet our debt obligations and pay distributions to our unitholders. On January 22, 2018, the Supreme Court unanimously held that initial challenges to this rule belong in district courts rather than appeals courts.  The EPA then, on January 31, 2018, delayed applicability of the 2015 rule. On October 22, 2019, the Environmental Protection Agency and Department of the Army (the agencies) published a final rule to repeal the 2015 Rule defining “waters of the United States” and re-codify the regulatory text that existed prior to the 2015 Rule. This final rule became effective on December 23, 2019, and will be replaced by the Navigable Waters Protection Rule once the final rule takes effect.

With the final Step One rule, the agencies maintained a longstanding regulatory framework that is more familiar to and better-understood by the agencies, states, tribes, local governments, regulated entities, and the public until the final Navigable Waters Protection Rule takes effect.

On January 23, 2020, the EPA and the Department of the Army (Army) finalized the Navigable Waters Protection Rule to define “waters of the United States” (WOTUS). For the first time, the agencies are streamlining the definition so that it: includes four simple categories of jurisdictional waters, provides clear exclusions for many water features that traditionally have not been regulated, and defines terms in the regulatory text that have never been defined before.

Congress, in the Clean Water Act, explicitly directed the Agencies to protect “navigable waters.” The Navigable Waters Protection Rule regulates these waters and the core tributary systems that provide perennial or intermittent flow into them. The final rule fulfills Executive Order 13788 and reflects legal precedent set by key Supreme Court cases as well as robust public outreach and engagement, including pre-proposal input and comments received on the proposed rule.

 

In March 2014, the Illinois State Attorney General, the Illinois Department of Natural Resources and others entered into an order which has potentially far-reaching effects on the permitting process for mines in Illinois. While the final rules have yet to be promulgated, and thus the impact on the permitting process cannot yet be determined, the order could have the effect of extending the permit review and approval process. The inability to conduct mining operations or obtain, maintain or renew permits may have a material adverse effect on our results of operations, business and financial position, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Competition within the coal industry may adversely affect our ability to sell coal and excess production capacity in the industry could put downward pressure on coal prices.

 

We compete with other producers primarily on the basis of price, coal quality, transportation cost and reliability of delivery. We cannot assure you that competition from other producers will not adversely affect us in the future. The coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. We cannot assure you that the result of current or further consolidation in the industry will not adversely affect us. In addition, potential changes to international trade agreements, trade concessions or other political and economic arrangements may benefit coal producers operating in countries other than the U.S., where our mining operations are currently located. We cannot assure you that we will be able to compete on the basis of price or other factors with companies that in the future may benefit from favorable trading or other arrangements. We compete directly for domestic and international coal sales with numerous other coal producers located in the U.S. and internationally, in countries such as Australia, China, India, South Africa, Indonesia, Russia and Colombia. The price of coal in the markets into which we sell our coal is also influenced by the price of coal in the markets in which we do not sell our coal because significant oversupply of coal from other markets could materially reduce the prices we receive for our coal. Increases in coal prices could encourage the development of expanded capacity by new or existing coal producers, which could result in lower coal prices. As a result, our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders may be materially adversely affected.

 

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The benefits of reduced costs associated with the management services agreement and joint management with Murray Energy may not be realized.

 

We may not realize the reduction in selling, general and administrative costs which we expect under the management services agreement with Murray Energy or the expected procurement synergies resulting from increased purchasing power with third party vendors and lower pricing on equipment acquired from Murray Energy’s manufacturing facilities.

 

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf reduce cash available for distribution to our unitholders. Our general partner determines the amount and timing of such reimbursements.

 

We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf and have entered into a management services agreement with Murray Energy to provide operational services to us. Our partnership agreement does not limit 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. Our partnership agreement provides that our general partner determines the expenses that are allocable to us. Under the management services agreement, we are obligated to pay Murray Energy for services provided to us, subject to future contractual escalations and adjustments (currently $5.2 million per quarter as of December 31, 2019), but we may agree to revise the management services agreement to provide for a different reimbursement amount. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates reduces the amount of cash available for distributions to our unitholders.

 

Murray Energy and Foresight Reserves own our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Murray Energy and Foresight Reserves, have conflicts of interest with us and limited duties, and they may favor their own interests to our detriment and that of our unitholders.

 

Murray Energy and Foresight Reserves own and control our general partner and appoint all of the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Murray Energy and Foresight Reserves. Therefore, conflicts of interest may arise between Murray Energy, Foresight Reserves or their respective affiliates, including our general partner, on the one hand, and us and any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders.

 

These conflicts include the following situations, among others:

•      our general partner is allowed to take into account the interests of parties other than us, such as Murray Energy and Foresight Reserves, in exercising certain rights under our partnership agreement;

•      neither our partnership agreement nor any other agreement requires Murray Energy or Foresight Reserves to pursue a business strategy that favors us;

•      our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

•      Murray Energy, Foresight Reserves and their respective affiliates are not limited in their ability to compete with us and may offer business opportunities or sell assets to third parties without first offering us the right to bid for them;

•      except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

•      our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

•      our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders, which, in turn, may affect the ability of the subordinated units to convert.

•      when permitted pursuant to the terms of our debt agreements, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

•      our partnership agreement permits us to distribute up to $125 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;

•      our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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•      our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates, including Murray Energy, for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

•      our general partner intends to limit its liability regarding our contractual and other obligations;

•      our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

•      our general partner controls the enforcement of obligations that it and its affiliates owe to us;

•      our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

•      our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

 

We share key personnel with Murray Energy, including our chief executive officer, our chief accounting officer, and nearly all of our sales and purchasing personnel, so there may be a conflict of interest in the duties of such personnel as they relate to Murray Energy and us. Such personnel have fiduciary duties to Murray Energy, which may cause them to pursue business strategies that disproportionately benefit Murray Energy or which otherwise are not in the best interest of our unitholders. As a result, there may be instances where a conflict of interest arises between Murray Energy and us that could have an adverse effect on our business.

 

In addition, Murray Energy is one of our principal competitors and Murray Energy, Foresight Reserves, and their respective affiliates currently hold substantial interests in other companies in the energy and natural resource sectors. We may compete directly with Murray Energy or entities in which Murray Energy, Foresight Reserves, or their respective affiliates have an interest for customers or acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us.

 

Our ability to collect payments from Murray Energy could be impaired as a result of Murray Energy’s petition for relief under Chapter 11 of the Bankruptcy Code, if Murray Energy’s creditworthiness deteriorates further, or if production at the Murray Energy mine ceases.

 

As further described in Part II. “Item 8. Financial Statements and Supplementary Data – Note 16. Related-Party Transactions” of this Annual Report on Form 10-K, on October 29, 2019, the debtor entities of Murray Energy filed voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Ohio Western Division.  As of December 31, 2019, the Partnership had amounts receivable from Murray Energy and its subsidiaries (excluding Javelin) of $8.7 million included in due from affiliates on the consolidated balance sheet.  In addition, the Partnership has two long-term financing arrangements with subsidiaries of Murray Energy totaling $60.7 million, for which we have recorded a reserve of $60.4 million as of December 31, 2019, owing to the Murray Energy bankruptcy.  Our ability to receive payments on these receivables and financing arrangements may be impaired pending the outcome of the Murray Energy bankruptcy, if the operation of any Murray Energy mines were to cease, or if Murray Energy’s creditworthiness was to deteriorate further.  The Partnership would bear the risk for any Murray Energy payment default. The failure to collect payment under these receivables and financing arrangements may materially adversely affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Our business requires substantial capital expenditures and we may not have access to the capital required to reach full development of our mines.

 

Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations require substantial capital expenditures. While a significant amount of capital expenditures required to build-out our mines has been spent, we must continue to invest capital to maintain or to increase our production. Decisions to increase our production levels could also affect our capital needs. We cannot assure you that we will be able to maintain our production levels or generate sufficient cash flow, or that we will have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels and we may be required to defer all or a portion of our capital expenditures. Our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders may be materially adversely affected if we cannot make such capital expenditures.

 

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Major equipment and plant failures could reduce our ability to produce and ship coal and materially and adversely affect our results of operations.

 

We depend on several major pieces of mining equipment and preparation plants to produce and ship our coal, including, but not limited to, longwall mining systems, preparation plants, and transloading facilities. If any of these pieces of equipment or facilities suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation, or otherwise, we may be unable to replace or repair them in a timely manner or at a reasonable cost which would impact our ability to produce and ship coal and materially and adversely affect our results of operations, business and financial condition as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

We may not be able to obtain equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our coal mining and transportation operations.

 

We use equipment in our coal mining and transportation operations such as continuous miners, conveyors, shuttle cars, rail cars, locomotives, roof bolters, shearers and shields. We procure this equipment from a concentrated group of suppliers, and obtaining this equipment often involves long lead times. Occasionally, demand for such equipment by mining companies can be high and some types of equipment may be in short supply. Delays in receiving or shortages of this equipment, as well as the raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes, or the cancellation of our supply contracts under which we obtain equipment and other consumables, could limit our ability to obtain these supplies or equipment. In addition, if any of our suppliers experiences an adverse event, or decides to no longer do business with us, we may be unable to obtain sufficient equipment and raw materials in a timely manner or at a reasonable price to allow us to meet our production goals and our revenues may be adversely impacted. We use considerable quantities of steel in the mining process. If the price of steel or other materials increases substantially or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses could increase. Any of the foregoing events could materially and adversely impact our results of operations, business and financial condition as well as our profitability as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

The development of a longwall mining system is a challenging process that may take longer and cost more than estimated, or not be completed at all.

 

The full development of our reserve base may not be achieved. We may encounter adverse geological conditions or delays in obtaining, maintaining or renewing required construction, environmental or operating or mine design permits. Construction delays cause reduced production and cash flow while certain fixed costs, such as minimum royalties and debt payments, must still be paid on a predetermined schedule.

 

Defects in title or loss of any leasehold interests in our properties could limit our ability to conduct mining operations on these properties or result in significant unanticipated costs.

 

A substantial amount of our coal reserves are leased or subleased from affiliates. A title defect or the loss of any lease upon expiration of its term, upon a default or otherwise, could adversely affect our ability to mine the associated reserves or process the coal that we mine. Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to mine a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine certain of our reserves has in the past been, and may again in the future be, adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

 

In order to obtain, maintain or renew leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. Some leases have minimum production requirements. As a result, our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders may be materially adversely affected.

 

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Numerous political and regulatory authorities and governmental bodies, as well as environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal and potentially materially and adversely impacting our future financial results, liquidity and growth prospects.

 

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants.

 

Federal, state and local governments may pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may decrease demand for our coal products. The Clean Power Plan is one of a number of recent developments aimed at limiting GHG emissions which could limit the market for some of our products by encouraging electric generation from sources that do not generate the same amount of GHG emissions. Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures. For example, the Paris Agreement resulting from the 2015 United Nations Framework Convention on Climate Change contains commitments by numerous countries to reduce their GHG emissions. The Paris Agreement entered into force in November 2016. Currently, 187 of the 195 Parties to the Convention have ratified the Paris Agreement, and additional Parties may ratify, increasing the firm commitments by various nations with respect to future GHG emissions. These commitments could further disfavor coal-fired generation, particularly in the medium- to long-term. On June 1, 2017, President Trump announced the United States has withdrawn from the Paris Agreement, with an effective withdrawal date of November 4, 2020.  Certain state and local officials have stated that they will, nevertheless, voluntarily participate in the Paris Agreement.

 

Congress has extended certain tax credits for renewable sources of electric generation, which will increase the ability of these sources to compete with our coal products in the market. In addition, in January 2016, the U.S. Department of Interior announced a moratorium on issuing certain new coal leases on federal land while the Bureau of Land Management undertakes a programmatic review of the federal coal program. While none of our operations are located on federal lands impacted by this moratorium, these governmental actions do signal increased attention at the federal level to coal mining practices and the GHG emissions resulting from coal combustion.

 

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. In California, for example, legislation was enacted in October 2015 requiring California’s state pension funds to divest investments in companies that generate 50% or more of their revenue from coal mining by July 2017. Other activist campaigns have urged banks to cease financing coal-driven businesses. As a result, at least ten major banks enacted such policies in 2015, joined by at least 5 major banks in 2016. The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

 

In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. Collectively, these actions and campaigns could adversely impact our future financial results, liquidity and growth prospects.

 

We may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.

 

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. For example, government entities, such as the City of Baltimore and the states of California and New York, have brought claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement

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under various tort theories. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

 

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

 

Certain of our coal mining operations use or have used hazardous and other regulated materials and have generated hazardous wastes. In addition, one of our locations was used for coal mining involving hazardous materials prior to our involvement with, or operation of, such location. We may be subject to claims under federal and state statutes or common law doctrines for penalties, toxic torts and other damages, as well as for natural resource damages and for the investigation and remediation of soil, surface water, groundwater, and other media under laws such as the CERCLA, commonly known as Superfund, or the Clean Water Act. Such claims may arise, for example, out of current, former or threatened conditions at sites that we currently own or operate as well as at sites that we and companies we acquired owned or operated in the past, or sent waste to for treatment or disposal, and at contaminated sites that have always been owned or operated by third parties.

 

We have used coal ash for reclamation at our Macoupin mine. On December 19, 2014, the EPA issued a final rule concerning disposal and beneficial use of coal ash. In the final rule, the EPA determined that it would regulate coal ash as a nonhazardous material under Subtitle D of the RCRA.  The EPA also clarified the definition of beneficial use of coal ash. Additionally, in the preamble to its final rule, the EPA affirmed “this rule does not apply to CCR placed in active or abandoned underground or surface mines.” Instead, “the U.S. Department of Interior (“DOI”) and the EPA will address the management of CCR in mine fills in a separate regulatory action(s).”  While these requirements are less stringent than the proposed rule treating coal ash as a hazardous material under Subtitle C of the RCRA, we can make no assurances that the new rule, or the potential DOI and EPA rulemaking mentioned in the rule’s preamble, will not increase our costs for the use of coal ash at Macoupin or expose us to additional liability through citizen suits brought under RCRA.

 

We are involved in legal proceedings that if determined adversely to us, could significantly impact our profitability, financial position or liquidity.

 

We are, and from time to time may become, involved in various legal proceedings that arise in the ordinary course of business. Some lawsuits seek fines or penalties and damages in very large amounts, or seek to restrict our business activities. In particular, we are subject to legal proceedings relating to our receipt of and compliance with permits under the SMCRA and the CWA and to other legal proceedings relating to environmental matters involving current and historical operations, ownership of land or permitting. It is currently unknown what the ultimate resolution of these proceedings will be, but these proceedings could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to make distributions to our unitholders.

 

 

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.

 

Federal or state regulatory agencies, including MSHA, IDNR and IEPA, have the authority under certain circumstances following significant health, safety or environmental incidents or pursuant to permitting authority to temporarily or permanently close one or more of our mines. If this occurred, we may be required to incur capital expenditures and/or additional expenses to re-open the mine. In the event that these agencies cause us to close one or more of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend our obligations to deliver coal under such contracts. However, our customers may challenge our issuances of force majeure notices in connection with these closures. If these challenges are successful, we may have to purchase coal from third-party sources, if available, to fulfill these obligations, incur capital expenditures to re-open the mine or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or termination of such customers’ contracts. Any of these actions could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

We face numerous uncertainties in estimating our economically recoverable coal reserves.

 

Coal is economically recoverable when the price at which coal can be sold exceeds the costs and expenses of mining and selling the coal. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our reserve information on engineering, economic and geological data assembled and analyzed by third parties and our staff, which includes various engineers. The reserve estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically

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recoverable coal reserves necessarily depend upon a number of factors and assumptions, any one of which may, if inaccurate, result in an estimate that varies considerably from actual results. These factors and assumptions include:

 

As a result, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our production from reserves may vary materially from estimates. These estimates thus may not accurately reflect our actual reserves. Any material inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability which could materially adversely affect our results of operations, business and financial condition as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

 

Our operations are subject to risks, some of which are not insurable, and we cannot assure you that our existing insurance would be adequate in the event of a loss.

 

We maintain insurance to protect against risk of loss but our coverage is subject to deductibles and specific terms and conditions. We cannot assure you that we will have adequate coverage or that we will be able to obtain insurance against certain risks, including certain liabilities for environmental pollution or hazards. We cannot assure you that insurance coverage will be available in the future at commercially reasonable costs, or at all, or that the amounts for which we are insured or that we may receive, or the timing of any such receipt, will be adequate to cover all of our losses. Uninsured events may adversely affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

We have future mine closure and reclamation obligations, the timing and amount of which are uncertain. In addition, our failure to maintain required financial assurances could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease the coal.

 

In view of the uncertainties concerning future mine closure and reclamation costs on our properties, the ultimate timing and future costs of these obligations could differ materially from our current estimates. We estimate our asset retirement obligations for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash 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. Our estimates for this future liability are subject to change based on new or amendments to existing applicable laws and regulations, the nature of ongoing operations and technological innovations. Although we accrue for future costs in our consolidated balance sheets, we do not reserve cash in respect of these obligations or otherwise fund these obligations in advance. As a result, we will have significant cash outlays when we are required to close and restore mine sites that may, among other things, affect our ability to satisfy our obligations under our indebtedness and other contractual commitments and pay distributions to unitholders. We cannot assure you that we will be able to obtain financing on satisfactory terms to fund these costs, or at all.

 

In addition, regulatory authorities require us to provide financial assurance to secure, in whole or in part, our future reclamation projects. The amount and nature of the financial assurances are dependent upon a number of factors, including our financial condition and reclamation cost estimates. Changes to these amounts, as well as the nature of the collateral to be provided, could significantly increase our costs, making the maintenance and development of existing and new mines less economically feasible. Currently, the security we provide consists of surety bonds. The premium rates and terms of the surety bonds are subject to annual renewals. Our failure to maintain, or inability to acquire, surety bonds or other forms of financial assurance that are required by applicable law, contract or permit could adversely affect our ability to operate. That failure could result from a variety of factors including the lack of availability, higher expense or unfavorable market terms of new surety bonds or other forms of financial assurance. There can be no guarantee that we will be able to maintain or add to our current level of financial assurance. Additionally, any capital resources that we do utilize for this purpose will reduce our resources available for our operations and commitments as well as our ability to pay distributions to our unitholders. As of December 31, 2019, we have active outstanding surety bonds with third parties of $97.4 million.

 

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Significant increases in, or the imposition of new, taxes we pay on the coal we produce could materially and adversely affect our results of operations.

 

All of our mining operations are in Illinois. If Illinois was to impose a state severance tax or any other tax applicable solely to our Illinois operations, we may be significantly impacted and our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders could be materially and adversely affected. Any imposition of Illinois state severance tax or any county tax could disproportionately impact us relative to our competitors that are more geographically diverse.

 

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner has the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934. As of March 20, 2020, Murray Energy owns 100.0% of our subordinated units and 12.1% of our common units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), Murray Energy would own an aggregate of 51.2% of our common units.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

 

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

 

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Many utilities have sold their power plants to non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, some of our customers have been adversely affected by the current economic downturn, which may impact their ability to fulfill their contractual obligations. Competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default. We also have contracts to supply coal to energy trading and brokering customers under which those customers sell coal to end users. If the creditworthiness of any of our energy trading and brokering customers declines, we may not be able to collect payment for all coal sold and delivered to or on behalf of these customers. An inability to collect payment from these counterparties may materially adversely affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

All of our coal and controlled reserves are in Illinois making us vulnerable to risks associated with operating in a single geographic area.

 

Because we operate exclusively in Illinois, any disruptions to our operations due to adverse geographical conditions or changes to the Illinois regulatory environment could significantly impact our operations, reduce our sales of coal and adversely affect our results of operation and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel.

 

Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of our executive officers and other key employees. The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a replacement. A limited number of persons exist with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, we

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believe that our future success will depend on our continued ability to attract and retain highly skilled personnel with coal industry experience. Competition for these persons in the coal industry is intense and we may not be able to successfully recruit, train or retain qualified managerial personnel. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

 

Our ability to operate our mines efficiently and profitably is dependent upon skilled mining labor. A shortage of skilled mining labor in the U.S. could decrease our labor productivity and increase our labor costs, which would adversely affect our profitability.

 

Efficient coal mining using complex and sophisticated techniques and equipment requires skilled laborers proficient in multiple mining tasks, including mining equipment maintenance. Any shortage of skilled mining labor reduces the productivity of experienced employees who must assist in training unskilled employees. If a shortage of experienced labor occurs, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.

 

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions affecting our customers could cause delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the U.S. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

Other events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating results.

 

Our results could be affected in various ways by global or domestic events beyond our control.  Most recently, we have considered the impacts of a coronavirus disease (COVID – 19) on our overall operations. While the full impact of this disease and the worldwide reaction to it remain unknown at this time, any widespread growth in infections, travel restrictions, quarantines, or site closures as a result of the disease could, among other things, impact the ability of our employees to perform their duties and lead to disruptions in our supply chain and transportation network. Any of these outcomes could have a material adverse effect on our business.  

 

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

 

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our employees, analyze mining information, and estimate quantities of coal reserves, as well as other activities related to our businesses. We have implemented cyber security protocols and systems with the intent of maintaining the security of our operations and protecting our and our counterparties' confidential information against unauthorized access. Despite such efforts, we may be subject to cyber security breaches which could result in unauthorized access to our information systems or infrastructure.

 

Strategic targets, such as energy-related assets, may be at greater risk of future cyber-attacks than other targets in the United States. Deliberate cyber-attacks on, or security breaches in, our digital systems or information technology infrastructure, or that of third parties, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

 

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The holder or holders of our incentive distribution rights may elect to cause us to issue common units to them in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

 

Our general partner, the holder of our incentive distribution rights, has the right, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the then-applicable third target distribution for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be calculated as an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will equal the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election.

 

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, our general partner may transfer the incentive distribution rights at any time. It is possible that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels.

 

It is our policy to distribute a significant portion of our available cash to our unitholders, which could limit our ability to grow or make acquisitions.

 

Pursuant to our cash distribution policy, we intend to distribute a significant portion of our available cash to our unitholders and rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund potential acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy may impair our ability to grow.

 

As we intend to regularly distribute a portion of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

 

We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

 

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. Additionally, we are not limited in the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance of additional common units would have the following effects:

 

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In addition, to the extent that we are unable to generate a sufficiently large return from investment of the proceeds of the issuance of additional units, such issuances would be dilutive to the existing unitholders.

 

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units.

 

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

 

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, Murray Energy and Foresight Reserves, as owners of our general partner, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

 

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

 

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Our partnership agreement provides that the conflicts committee of the board of directors of our general partner may be comprised of one or more independent directors. If our general partner establishes a conflicts committee with only one independent director, your interests may not be as well served as if the conflicts committee were comprised of at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

 

Murray Energy Corporation and The Cline Group (an affiliate of Foresight Reserves) each currently hold substantial interests in other companies in the coal mining business, including other coal reserves in Illinois. The Cline Group and Murray Energy Corporation each makes investments and purchases entities that acquire, own and operate coal mining businesses and transportation. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, Murray Energy Corporation, The Cline Group, and certain other affiliates of our general partner may compete with us for investment opportunities and affiliates of our general partner may own an interest in entities that compete with us.

 

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and Foresight Reserves. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment for us and our unitholders.

 

Holders of our common units have limited voting rights and are not entitled to elect or remove our general partner or its directors, which could reduce the price at which the common units would trade.

 

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by the owners of our general partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

 If our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. Unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. The owners of our general partner have the ability to prevent the removal of our general partner.

 

Due to “abnormally low” trading price levels under the New York Stock Exchange’s (“NYSE”) continued listing standards, our common units were delisted from the NYSE.  Trading in our common units was suspended on November 8, 2019 and our common units were delisted from the NYSE shortly thereafter.  Our delisting from the NYSE could negatively affect our business, financial condition, and results of operations.

 

Our delisting from the NYSE could adversely affect our relationships with our suppliers, customers, and potential customers and their decisions to conduct business with us. Such decisions could negatively affect our business, financial condition, and results of operations.  In addition, our delisting could impair our ability to raise additional capital through equity or debt financing and our ability to attract and retain employees and members of management by means of equity-based compensation.

 

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On November 12, 2019, our common units commenced trading over-the-counter and currently trade under the symbol “FELPQ.”  The over-the-counter markets are a more limited market than the NYSE and it is likely that there would be significantly less liquidity in the trading of our common units, decreases in institutional and other investor demand for our common units, coverage by securities analysts, market making activity and information available concerning trading prices and volume, and fewer broker-dealers willing to execute trades in our common units. The occurrence of any of these events could result in a further decline in the market price of our common units.

 

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner to transfer their membership interests in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

 

The incentive distribution rights may be transferred to a third party without unitholder consent.

 

Our general partner or our sponsors may transfer their respective incentive distribution rights to a third party at any time without the consent of our unitholders. If our sponsors transfer their incentive distribution rights to a third party but retain their respective ownership interests in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if our sponsors had retained their ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by our sponsors could reduce the likelihood of our sponsors accepting offers made by us relating to assets owned by them, as they would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

 

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf reduce cash available for distribution to our unitholders. Our general partner determines the amount and timing of such reimbursements.

 

We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not limit 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. Our partnership agreement provides that our general partner determines the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates reduces the amount of cash available for distributions to our unitholders.

 

As a publicly traded partnership, we are not required to comply with certain corporate governance requirements.

 

Because we are a publicly traded partnership, we are not required to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of these corporate governance requirements.

 

Our revenues and operating profits could be negatively impacted if we are unable to extend existing agreements at comparable pricing or enter into new agreements due to competition, environmental regulations affecting our customers’ changing coal purchasing patterns or other variables.

 

We compete with other coal suppliers when renewing expiring agreements or entering into new agreements. If we cannot renew these coal supply agreements or find alternate customers willing to purchase our coal, our revenue and operating profits could suffer. Our customers may decide not to extend existing agreements or enter into new long-term contracts or, in the absence of long-term contracts, may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms or may decide not to purchase at all. Any decrease in demand may cause our customers to delay negotiations for new contracts or request lower pricing terms or seek coal from other sources. Furthermore, uncertainty caused by laws and regulations affecting electric utilities could deter our customers from entering into long-term coal supply agreements. Some long-term contracts contain provisions for termination due to environmental regulatory changes if such changes prohibit utilities from burning the contracted coal. In addition, a number of our long-term contracts are subject to price re-openers. If market prices are lower than the existing contract price, pricing for these contracts could reset to lower levels.

 

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Coal mining operations are subject to inherent risks and are dependent on many factors and conditions beyond our control, any of which may adversely affect our productivity and our financial condition.

 

Our mining operations, including our transportation infrastructure, are influenced by changing conditions that can affect the safety of our workforce, production levels, delivery of our coal and costs for varying lengths of time and, as a result, can diminish our revenues and profitability. In particular, underground mining and related processing activities present inherent risks of injury to persons and damage to property and equipment. A shutdown of any of our mines or prolonged disruption of production at any of our mines or transportation of our coal to customers would result in a decrease in our revenues and profitability, which could be material. Certain factors affecting the production and sale of our coal that could result in decreases in our revenues and profitability include:

 

These risks, conditions and events could (1) result in: (a) damage to, or destruction of value of, our coal properties, our coal production or transportation facilities, (b) personal injury or death, (c) environmental damage to our properties or the properties of others, (d) delays or prohibitions on mining our coal or in the transportation of coal, (e) monetary losses and (f) potential legal liability; and (2) could have a material adverse effect on our operating results and our ability to generate the cash flows we require to invest in our operations and satisfy our debt obligations. Our insurance policies only provide limited coverage for some of these risks and will not fully cover these risks. A significant mine accident could potentially cause a mine shutdown, and could have a substantial adverse impact on our results of operations, financial condition or cash flows, as well as our ability to meet our debt obligations and pay distributions to our unitholders.

 

 

Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of our common units.

 

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Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us. Several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our common units could be negatively impacted.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

 

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for federal income tax purposes.

 

However, any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units.

 

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, including potential income arising from the discharge of indebtedness resulting from the outcome of the Foresight Chapter 11 Cases, regardless of whether you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability resulting from that income.

 

Tax gain or loss on the disposition of our common units could be more or less than expected.

 

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

 

A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

 

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

 

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raise issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal income tax returns and pay tax on its share of our

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taxable income. The Tax Cuts and Jobs Act of 2017 imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder's sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges.  It is not clear if or when such regulations or other guidance will be issued. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

 

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest may reduce our cash available for distribution to you.

 

We have not requested a ruling from the IRS regarding our treatment as a partnership for federal income tax purposes. The IRS could adopt positions that differ from the positions we take in the future. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS, and the outcome of such contest, may materially and adversely impact the market for our common units and the price at which they trade. The costs of any such contest would result in a reduction in cash available for distribution to our unitholders and would indirectly be borne by our unitholders.

 

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

 

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

 

We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

 

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We generally prorate items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

 

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We have adopted certain valuation methodologies in determining unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.

 

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

 

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to you. It also could affect the amount of gain from your sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to your tax return without the benefit of additional deductions.

 

If your common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units), you may be considered as having disposed of those common units. If so, you would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

 

Because there are no specific rules governing the federal income tax consequence of loaning a partnership interest, if your common units are the subject of a securities loan you may be considered as having disposed of the loaned units. In that case, you may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and you may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by you and any cash distributions received by you as to those common units could be fully taxable as ordinary income. If you desire to assure your status as partner and avoid the risk of gain recognition from a securities loan, you are urged to modify any applicable brokerage account agreements to prohibit your broker from borrowing your common units.

 

You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our common units.

 

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We own assets and conduct business in several states (including Illinois, Indiana and Missouri), each of which currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You will likely be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with these requirements.

 

As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.

 

The effect of comprehensive U.S. tax reform legislation on us, whether adverse or favorable, is uncertain.

 

The Tax Cuts and Jobs Act of 2017, signed into law on December 22, 2017, is subject to potential amendments and technical corrections, as well as interpretations and regulations enacted and proposed by the IRS, any of which could affect certain impacts of the legislation. For instance, the Tax Cuts and Jobs Act of 2017 limits the ability to take certain business interest expense deductions beginning in 2018. In addition, there is uncertainty with respect to how U.S. federal income tax changes will affect state and local taxation, which often uses federal taxable income as a starting point for computing state and local tax liabilities.  

 

Item 1B. Unresolved Staff Comments

 

None.

 

 

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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 nearly 2.1 billion tons (including 73 million tons of coal reserves associated with our recently idled Macoupin complex), almost entirely through lease, of proven and probable recoverable reserves at December 31, 2019. 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, 2019. All of our reserves are considered high sulfur coal, with average sulfur content ranging between 1.71% and 3.45% and high Btu coal, with Btu content ranging between 10,799 and 11,893 Btu per pound. The table below presents our estimated recoverable coal reserves at December 31, 2019.

 

 

 

Each of the mining companies leases the reserves they mine pursuant to a series of leases with related entities 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

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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. 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, 2019, we have $1.3 million accrued, in the aggregate, for various litigation matters.

 

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, 2019.

 

 

 

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PART II.

 

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

 

The common units representing limited partnership’ interests and currently trade on the over-the-counter markets under the symbol “FELPQ”. On March 20, 2020, the closing market price for FELP common units was $0.009 per unit and there were 80,996,773 common units outstanding and 64,954,691 subordinated units outstanding. There were approximately 4,500 record holders of our common units as of December 31, 2019.

 

The following table sets forth the amount of cash distributions declared and paid with respect to each common unit from January 1, 2018 to December 31, 2019.

 

 

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. To the extent the quarterly distribution is below the MQD, the 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. Given that quarterly distributions have been below the MQD beginning with the quarter ended December 31, 2015, arrearages have accrued to the benefit of common unitholders which shall be payable should future distributions be paid. However, there is no assurance as to the future cash distributions since they are dependent upon compliance with and restrictions within our various debt agreements, future earnings, cash flows, capital requirements, financial condition and other factors.

 

Our indebtedness resulting from the March 28, 2017 refinancing transactions have certain prepayment provisions that could require us to utilize a substantial amount of our annual excess cash flow to prepay outstanding borrowings based on satisfaction of specified net secured leverage ratios as defined under our debt agreements.  This excess cash flow prepayment requirement is therefore currently restrictive to our ability to pay distributions.  

 

Incentive Distribution Rights

 

Our incentive distribution rights (“IDRs”) are held by Murray Energy and Foresight Reserves. 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 IDRs may be transferred separately from any 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.

 

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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 no application of arrearages on common units.

 

 

Equity Compensation Plans

 

The information relating to our equity compensation plans required by Part II. “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” 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.

 

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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-Organization, Nature of Business and Basis of Presentation” for a discussion on the basis of presentation for the consolidated financial statements.

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Adjusted EBITDA is not a measure of performance defined in accordance with U.S. generally accepted accounting principles (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.

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Below is a reconciliation between net loss attributable to controlling interests and Adjusted EBITDA for the years ended December 31, 2019 and 2018, for the period from January 1, 2017 to March 31, 2017, for the period from April 1, 2017 to December 31, 2017, and for the years ended December 31, 2016, and 2015:

 

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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 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 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. On March 28, 2017, Murray Energy acquired an additional 46% voting interest in FEGP, thereby increasing Murray Energy’s voting interest in the FEGP to 80%.  

 

The presented financial results include the consolidated financial position, results of operations and cash flow information of FELP and its subsidiaries for all periods presented. In this Item 7, all references to “FELP,” the “Partnership,” “we,” “us,” and “our” refer to the results of FELP and its subsidiaries, unless the context otherwise requires or where otherwise indicated.

 

We control nearly 2.1 billion tons of coal reserves (including 73 million tons of coal reserves associated with our recently idled Macoupin complex), almost all of which exist in three large, contiguous blocks of coal: two in central Illinois and one in southern Illinois. Since our inception, we have invested significantly in capital expenditures to develop what we believe are industry-leading, geologically similar, low-cost and highly productive mines and related infrastructure. We currently operate under one reportable segment with four operating underground mining complexes in the Illinois Basin: Williamson, Sugar Camp, and Hillsboro which are longwall operations, and Macoupin, which is currently a continuous miner operation. The Williamson and Hillsboro complexes operate with one longwall system each; the Sugar Camp complex operates with two longwall mining systems.

 

Mining operations at our Hillsboro complex were idle since March 2015 due to a combustion event. In May 2017, we breached the seal and mine rescue teams evaluated the mine.  In December 2017, we submitted a re-entry plan to MSHA, which contained a plan for the permanent sealing of the current longwall district of the Hillsboro mine.  MSHA approved the plan and, as a result, certain longwall equipment and other related assets were permanently sealed within and were not recovered, resulting in a $42.7 million impairment loss during 2017.

 

In connection with certain litigation matters related to the combustion event and due to additional facts and circumstances arising in April 2018, we announced that our Hillsboro operation would be closed and certain long-lived assets consisting primarily of mineral reserves and certain buildings and structures, machinery and equipment, and other related assets were not expected to generate future positive cash flows. As the expected future cash flows were projected to be immaterial and not sufficient to support the recoverability of the assets’ carrying values, the assets were reduced to their estimated fair values.  As such, we recorded an aggregate impairment charge of $110.7 million during 2018.  

 

In October 2018, we reached a settlement of certain litigation matters associated with the Hillsboro combustion event.  We resumed production in January 2019 with one continuous miner section.  In March 2020, longwall production resumed at Hillsboro.

 

In March 2020, we idled operations at our Macoupin complex, owing to the significant challenges in the thermal coal markets. As a result of the idling, the expected future cash flows at Macoupin were projected to be immaterial and not sufficient to support the recoverability of the assets’ carrying values, the assets were reduced to their estimated fair values.  As such, we recorded an aggregate impairment charge of $143.6 million at Macoupin during 2019.  

 

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

 

Filing Under Chapter 11 of the Bankruptcy Code

 

On the Petition Date, we commenced the Foresight Chapter 11 Cases in the Bankruptcy Court.  Further information regarding our bankruptcy filing under Chapter 11 of the Bankruptcy Code, as well as information on our liquidity, capital resources, debt obligations and going concern matters, are disclosed in Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.

 

Pushdown Accounting

 

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

 

As it relates to the results of operations, references to "Successor" are in reference to reporting dates on or after April 1, 2017, and references to "Predecessor" are in reference to reporting dates prior to and including March 31, 2017. While the 2017 Successor period and the 2017 Predecessor period are distinct reporting periods, the effects of the change of control did not have a material impact on the comparability of our results of operations between the periods, unless otherwise noted related to the impact from pushdown accounting.  References to the combined 2017 period from January 1, 2017 to December 31, 2017 combine the period from January 1, 2017 to March 31, 2017 (Predecessor) and the period from April 1, 2017 to December 31, 2017 (Successor) (“the Combined 2017 Period”) to enhance the comparability of such information to the prior year.

 

Also, the assets and liabilities of FELP were recorded at the their estimated fair value as of the Acquisition Date, which in certain cases was significantly different than the carrying value immediately prior to the Acquisition Date. See “Item 8. Financial Statements and Supplementary Data – Note 3. Recent Transactions and Events” of this Annual Report on Form 10-K for additional discussion on those changes. Adjustments to the fair value of FELP’s asset and liabilities as of the Acquisition Date were recorded during the period in which the adjustment was determined, including the effect on earnings of any amounts we would have recorded in previous periods if the accounting had been completed at the Acquisition Date (i.e., the historical reported financial statements will not be retrospectively adjusted).

 

Debt Refinancing

 

On March 28, 2017 (the “2017 Refinancing Closing Date”), we completed a series of transactions to refinance certain previously outstanding indebtedness (the “March 2017 Refinancing Transactions”). See “Item 8. Financial Statements and Supplementary Data – Note 11. Long-Term Debt and Finance Lease Obligations” and “Item 8. Financial Statements and Supplementary Data – Note 16. Related-Party Transactions” for additional discussion of the March 2017 Refinancing Transactions.

 

Factors That Affect Our Results

 

Coal Sales. The thermal coal markets that we traditionally serve have been meaningfully challenged over the past three to four years, and deteriorated significantly in the last several months. This sector-wide decline has been driven largely by (a) the closure of approximately 93,000 megawatts of coal-fired electric generating capacity in the United States, (b) a record production of inexpensive natural gas, and (c) the growth of wind and solar energy, with gas and renewables, displacing coal used by U.S. power plants. During its peak in 2007, coal was the power source for half of electricity generation in the United States and by early 2019, coal-fired electricity generation fell to approximately 27 percent. These challenges have intensified recently as (i) certain electric utility companies have filed for bankruptcy protection and others have sought, and received, subsidies for their nuclear generation capacity to avoid bankruptcy, at the expense of coal-fired facilities, (ii) domestic natural gas prices hit 20-year lows this past summer, and (iii) overall demand for electricity in the United States has declined two percent in 2019, further depleting demand for coal at domestic utilities. At the same time, demand for U.S. coal from international utilities has been subject to its own set of negative forces, and the European benchmark price for thermal coal has halved in the last year. The impact of depressed demand and pricing in both domestic and international markets has impacted us significantly in recent months: customers with pre-existing commitments have refused to accept delivery, and with export markets depressed there is simply no alternative market to place product.

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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 into 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.

 

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. During 2019, we generally sold our coal to customers at three distinct delivery points: either at our mines, at river terminals on the Ohio River, or at 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 entering into minimum annual volume commitments is to secure long-term access to international markets and provide optionality between the domestic and international coal markets. To the extent coal pricing to international markets does not remain at economically sustainable levels, we may incur substantial expenses for shortfalls on minimum contractual throughput volume requirements related to the export market.

 

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. Accordingly, the cost of transporting our coal to international buyers can be significantly higher than 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 certain professional fees. 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 (currently $5.2 million per quarter as of December 31, 2019), which is subject to future contractual escalations and 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, 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.

 

Key Metrics

 

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

 

We define Adjusted EBITDA as net income (loss) attributable to controlling interests before interest, income taxes, depreciation, depletion, amortization and accretion. Adjusted EBITDA is also adjusted for equity-based compensation, losses/gains on commodity derivative contracts, settlements of derivative contracts, contract amortization and write-off, restructuring costs, changes in the fair

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value of the warrants and material nonrecurring or other items which may not reflect the trend of future results. As it relates to derivatives, the Adjusted EBITDA calculation removes the total impact of derivative gains/losses on net income (loss) during the period and then adds/deducts to Adjusted EBITDA the aggregate settlements during the period. Adjusted EBITDA also includes any insurance recoveries received, regardless of whether they relate to the recovery of mitigation costs, the receipt of business interruption proceeds, or the recovery of losses on machinery and equipment.

 

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

 

The following discusses the results of operations for the year ended December 31, 2019 as compared to the year ended December 31, 2018.  The results of operations for the year ended December 31, 2018 compared to the Combined 2017 Period was included in the Annual Report on Form 10-K for the year ended December 31, 2018 under Part II. “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” filed with the SEC on February 27, 2019.

 

Comparison of the Year Ended December 31, 2019 (Successor) to the Year Ended December 31, 2018 (Successor)

 

Coal Sales. The following table summarizes coal sales information during the years ended December 31, 2019 and 2018 (in thousands, except per ton data).

 

 

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

 

Other Revenues. Other revenues of $7.1 million and $7.6 million for the years ended December 31, 2019 and 2018, respectively, were 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 during the years ended December 31, 2019 and 2018 (in thousands, except per ton data).

 

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The decrease in cost of coal produced (excluding depreciation, depletion and amortization) from the prior year was due to an overall decrease in produced tons sold, offset by a higher cash cost per ton sold.  The increase in cash cost per ton sold resulted primarily from reduced production at our Williamson complex during the fourth quarter in response to challenging export market conditions.  

 

Cost of Coal Purchased. From time to time, we purchase coal from Murray Energy and its affiliates to, among other things, meet customer contractual obligations.  Such purchases totaled $8.3 million and $14.6 million during the years ended December 31, 2019 and 2018, respectively.

 

Transportation. Our cost of transportation for the year ended December 31, 2019 decreased $52.5 million as compared to the year ended December 31, 2018 due to a decrease in produced tons sold and a larger percentage of our sales going to the export market during the prior year, which have higher associated transportation and transloading costs.  These decreases were slightly offset by additional transloading-related costs in the current year due to high river levels at the export facilities near New Orleans.

 

Depreciation, Depletion and Amortization. The decrease in depreciation, depletion and amortization expense for the current year as compared to the prior year was primarily due to a lower depreciable asset base resulting from the aggregate impairment charge at our Hillsboro complex in the prior year, as well as $12.6 million of depreciation, depletion and amortization capitalized into development cost associated with our Hillsboro complex during the current period.  

 

Contract Amortization and Write-off. During the years ended December 31, 2019 and 2018, we recorded amortization benefit of $7.4 million and $86.5 million, respectively, on the favorable/unfavorable sales and royalty contract assets and liabilities recorded as part of our pushdown accounting. The prior year includes a benefit of $69.1 million associated with the write-off of an unfavorable royalty agreement associated with our Hillsboro complex.

 

Accretion and Changes in Estimates on Asset Retirement Obligations. The total expense (benefit) was $2.2 million and $(8.5) million for the years ended December 31, 2019 and 2018, respectively.  Because of the Hillsboro impairment (see “Item 8. Financial Statements and Supplementary Data – Note 3. Recent Transactions and Events”) and subsequent changes in estimate of the Hillsboro asset retirement obligations, included in the prior year is a benefit due to a change in estimate of $(10.9) million that is recognized in the consolidated statement of operations.

 

Selling, General and Administrative. The decrease in selling, general and administrative expense for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily due to decreased sales and marketing expenses resulting from lower export sales volumes and legal expenses incurred in the prior year associated with the Hillsboro and Macoupin litigation matters settled in October of 2018.

 

Long-lived Asset Impairments. During the year ended December 31, 2019, we recognized an aggregate impairment charge of $143.6 million related to certain long-lived assets and mineral reserves associated with our Macoupin complex.  During the year ended December 31, 2018, we recognized an aggregate impairment charge of $110.7 million related to certain long-lived assets and mineral reserves associated with our Hillsboro complex.  

 

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Reserve on financing receivables - affiliate. During the year ended December 31, 2019, we recorded a reserve of $60.4 million on our financing receivables as a result of uncertainty in collection due to the Murray Chapter 11 Cases (defined below).

 

Other Operating (Income) Expense, Net. In 2019, other operating (income) expense, net consisted primarily of $25.4 million in payments from insurance companies related to the final settlement of claims associated with the Hillsboro combustion event.  In 2018, other operating (income) expense, net consisted of $43.0 million in payments from insurance companies offset by $25.0 million for the settlement of litigation related to the Hillsboro and Macoupin matters.

 

Interest Expense, Net. Interest expense, net for the current year was comparable to the prior year primarily as a result of lower overall outstanding principal balances on our Term Loan due 2022 and longwall financing arrangements, offset by additional outstanding borrowings on our revolving credit facility.

 

Interest (Benefit) Expense, Net – Sale-Leaseback Financing Arrangements. Revisions to the mine plans resulted in a net benefit of $9.7 million in the 2019 consolidated statement of operations.  We account for such changes in mine plans by adjusting, in the period of the change, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied).

 

Debt Restructuring Costs. The $7.7 million of debt restructuring costs consist of legal and financial advisor fees related to our debt restructuring efforts and our bankruptcy filing under Chapter 11 of the Bankruptcy Code.  We expect debt restructuring costs to continue to be substantial until such time that these issues are remediated, if at all.

 

Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2019 decreased $128.6 million from the year ended December 31, 2018 due primarily to the overall decreased sales volumes and lower coal sales realization per ton in the current year. The table below reconciles net loss to Adjusted EBITDA for the years ended December 31, 2019 and 2018 (in thousands).

 

 

 

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.”

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Liquidity and Capital Resources

 

Our primary cash requirements include, but are not limited to, working capital needs, capital expenditures, and debt service costs (interest and principal). Our primary sources of operating liquidity consist of cash generated from operations, cash on hand, and a $170.0 million revolving credit facility (the “Revolving Credit Facility”).  As of December 31, 2019, we had $33.9 million of cash on hand and no meaningful borrowing availability under the Revolving Credit Facility.  Outstanding borrowings and letters of credit under the Revolving Credit Facility were $157.0 million and $12.3 million, respectively, as of December 31, 2019.

Our liquidity has been significantly impacted by the Foresight Chapter 11 Cases.  For additional information, refer to Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.

 

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

 

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

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

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

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

 

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

 

Further information regarding our Credit Facilities is disclosed in Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.

 

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 development capital expenditures.

 

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

 

Development capital expenditures are cash expenditures made to increase, over the long-term, our operating capacity or net income as it exists at such time as the capital expenditures are made. Development capital expenditures consist of current and potential future capital expenditures at our Hillsboro complex. Future longwall development and the associated capital expenditures will be dependent upon several factors, including permitting, demand, access to capital, equipment availability and the committed sales position at our existing mining operations.

 

Murray Energy Bankruptcy

 

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

 

As of December 31, 2019, the Partnership had amounts receivable from Murray Energy and its subsidiaries (excluding Javelin) of $8.7 million included in due from affiliates on the consolidated balance sheet.  The Partnership also had amounts payable to Murray Energy and its subsidiaries (excluding Javelin) of $6.5 million included in due to affiliates on the consolidated balance sheet at

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December 31, 2019.  In addition, the Partnership has two long-term financing arrangements with subsidiaries of Murray Energy totaling $60.7 million.

 

In its filings with the Murray Bankruptcy Court, the Murray Debtors have indicated that they intend to continue performing their obligations under the various agreements with FELP and certain of its direct and indirect subsidiaries during the pendency of the Murray Chapter 11 Cases. On October 31, 2019, the Bankruptcy Court approved an order permitting the Murray Debtors to continue performing their intercompany transactions with FELP. In addition, the board of directors of FELP GP LLC has appointed a conflicts committee composed of independent directors tasked with closely monitoring the Murray Chapter 11 Cases and protecting FELP’s interests with respect to the Murray Debtors.  Although FELP and the Murray Debtors currently intend to continue performing their respective obligations under the agreements among FELP and the Murray Debtors, there can be no assurance that FELP or the Murray Debtors will not, in the future, reject, repudiate, renegotiate or terminate any or all of such agreements. As a result, our ability to receive payments on our arrangements with the Murray Debtors may be impaired pending the outcome of the Murray Chapter 11 Cases, if the operation of any Murray Energy mines were to cease, or if Murray Energy’s creditworthiness was to deteriorate further.    The Partnership would bear the risk for any Murray Energy payment default. The failure to collect payment under these receivables and financing arrangements may materially adversely affect our results of operations, business and financial condition, as well as our ability to meet our debt obligations and pay distributions to our unitholders.  Considering these factors, the Partnership has recorded a reserve of $60.4 million as of December 31, 2019, on the two long-term financing arrangements with subsidiaries of Murray Energy.

 

Distributions

 

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

 

Changes in Cash Flows

 

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

 

For the year ended December 31, 2019, net cash provided by operating activities decreased $58.5 million compared to the year ended December 31, 2018.  The decrease in cash provided by operating activities for the current year is primarily the result of decreased coal sales revenues and lower coal sales realization per ton, offset by various working capital variances.  Significant working capital variances as compared to the prior year included:

Cash used in investing activities in the current year consisted primarily of $90.7 million of capital expenditures associated with land purchases from New River Royalty, a new portal at our Sugar Camp complex, and development of our Hillsboro complex.  Cash used in investing activities in the prior year was the result of the receipt of $43.0 million of insurance recoveries offset by $84.1 million in capital expenditures.

 

For the year ended December 31, 2019, net cash provided by financing activities was $46.1 million compared to $97.2 million used in financing activities for the year ended December 31, 2018.  Cash provided by financing activities in the current year resulted from $120.0 million in net borrowings on the Revolving Credit Facility offset by $53.4 million in payments on long-term debt and finance lease obligations, $15.7 million in payments on sale-leaseback and short-term financing arrangements, and $4.9 million in

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distributions paid to common unitholders.  In the prior year, cash used in financing activities primarily related to $106.1 million in payments on long-term debt and finance lease obligations, $18.1 million in distributions paid to common unitholders, and $9.9 million in payments on sale-leaseback and short-term financing arrangements, offset by $27.0 million in net borrowings on the Revolving Credit Facility.

 

Insurance Recoveries

 

On November 12, 2019, we reached a resolution with our insurers regarding the remaining recoveries under our policies related to the Hillsboro Combustion Event. In consideration for the resolution of all claims, we received final payments totaling $25.4 million during the fourth quarter of 2019.

 

Long-Term Debt and Sale-Leaseback Financing Arrangements

 

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

 

The Foresight Chapter 11 Cases are funded in part by the DIP Facility. Subject to final approval form the Bankruptcy Court, the DIP Facility consists of a $100 million new money, multi-draw term loan facility and a $75 million term loan facility which shall roll-up certain first-priority pre-petition claims of the DIP Facility lenders.  The DIP Facility bears interest at LIBOR (subject to a floor of 1.00%) plus 11.00% per annum and is subject to customary fees, covenants, and milestones.  The initial funding of $55 million under the DIP Facility occurred on March 11, 2020.  For additional information on the DIP Facility, refer to Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.

 

Summary of Refinancing Transactions

 

On March 28, 2017 (the “Refinancing Closing Date”), FELP, together with its wholly-owned subsidiaries FELLC (the “Borrower”) and Foresight Energy Finance Corporation (the “Co-Issuer” and together with FELLC, the “Issuers” and certain of the Issuers’ subsidiaries, completed a series of transactions to refinance certain previously outstanding indebtedness (the “Refinancing Transactions”). The new debt consisted of the Senior Secured First-Priority Credit Facility and the 11.50% Second Lien Senior Secured Notes due 2023, which are further described below.

 

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

 

The Credit Facilities consist of a senior secured first-priority $825.0 million term loan with a five-year maturity (the “Term Loan due 2022”) and the Revolving Credit Facility, which is a senior secured first-priority $170.0 million revolving credit facility with a maturity of four years, including both a letter of credit sub-facility and a swing-line loan sub-facility.  The Term Loan due 2022 was issued at an initial discount of $12.4 million, which is being amortized using the effective interest method over the term of the loan. Amounts outstanding under the Credit Facilities bear interest as follows:

 

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

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

 

In addition to paying interest on the outstanding principal under the Credit Facilities, we are required to pay a quarterly commitment fee with respect to the unused portions of our Revolving Credit Facility and customary letter of credit fees. The Credit Facilities originally required scheduled quarterly amortization payments on the Term Loan due 2022 in an aggregate annual amount equal to 1.0% of the original principal amount of the Term Loan due 2022, with the balance to be paid at maturity. However, the prepayments required pursuant to the Excess Cash Flow Provisions are to be applied against the future scheduled quarterly amortization payments on the Term Loan due 2022. Accordingly, no additional amortization payments on the Term Loan due 2022 are required prior to maturity.

 

The credit agreement governing our Credit Facilities requires us to prepay outstanding borrowings, subject to certain exceptions, pursuant to the Excess Cash Flow Provisions as described under “Liquidity and Capital Resources” above. We may also voluntarily repay outstanding loans under the Credit Facilities at any time, without prepayment premium or penalty, except in connection with a repricing transaction in respect of the Term Loan due 2022, in each case subject to customary “breakage” costs with respect to Eurodollar Rate loans. All obligations under the Credit Facilities are guaranteed by FELP on a limited recourse basis (where recourse

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is limited to its pledge of stock of FELP) and are or will be unconditionally guaranteed, jointly and severally, on a senior secured first-priority basis by each of the Partnership’s existing and future direct and indirect, wholly-owned domestic restricted subsidiaries (which do not currently include Hillsboro Energy LLC), subject to certain exceptions.

 

The credit agreement governing our Credit Facilities requires that we comply on a quarterly basis with a maximum net first lien secured leverage ratio, currently 3.50:1.00 and stepping down by 0.25x in the first quarter 2021, which financial covenant is solely for the benefit of the lenders under the Revolving Credit Facility. The Credit Facilities also contain certain customary affirmative covenants and events of default, including relating to a change of control.  We were not in compliance with the maximum net first lien secured leverage ratio as of December 31, 2019.

 

As of December 31, 2019, $743.3 million in principal was outstanding under the Term Loan due 2022 and there was $157.0 million in borrowings outstanding under the Revolving Credit Facility. During the year ended December 31, 2019, we prepaid $19.6 million of outstanding borrowings pursuant to the Excess Cash Flow Provisions under the Credit Facilities for the annual period ending December 31, 2018.  The prepayment was payable 95 days after year-end.  

 

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

 

Further information regarding our Credit Facilities is disclosed in Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.

 

Description of the 11.50% Second Lien Senior Secured Notes due 2023 (the “Second Lien Notes due 2023”)

 

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

 

Prior to April 1, 2020, the Second Lien Notes due 2023 may be redeemed in whole or in part at a price equal to 100% of the aggregate principal amount thereof plus accrued and unpaid interest, if any, plus the applicable “make-whole” premium. In addition, prior to April 1, 2020, the Partnership may redeem up to 35% of the aggregate principal amount of the Second Lien Notes due 2023 at a price equal to 111.50% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed with the proceeds from a qualified equity offering, subject to at least 50% of the aggregate principal amount of the Second Lien Notes due 2023 remaining outstanding after giving effect to any such redemption. On or after April 1, 2020, the Second Lien Notes due 2023 may be redeemed at a price equal to: (i) 105.750% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed prior to April 1, 2021; (ii) 102.875% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed on or after April 1, 2021 but prior to April 1, 2022; and (iii) 100.000% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed thereafter.

 

As of December 31, 2019, $425.0 million in principal was outstanding under the Second Lien Notes due 2023.

 

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

 

Further information regarding our Second Lien Notes due 2023 is disclosed in Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.

 

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Longwall Financing Arrangements and Finance Lease Obligations

 

In November 2014, we entered into a sale-leaseback financing arrangement with a financial institution under which we sold a set of longwall shields and related equipment for $55.9 million and leased the shields back under three individual leases. We account for these leases as finance lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases. Principal and interest payments were due monthly over the five-year terms of the leases. The maturity date of the finance lease obligations was November 2019. An aggregate termination payment of $2.8 million was due at the end of the lease terms. There was no outstanding balance as of December 31, 2019, and all amounts associated with the finance lease obligations have been repaid.

 

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 was collateralized by the longwall equipment. Interest accrued on the note at a fixed rate per annum of 5.555% and was due semiannually in March and September until maturity. Principal was due in semiannual payments through maturity. The maturity date of the 5.555% longwall financing arrangement was September 2019.  In addition, certain covenants and definitions in the credit agreements and guaranty agreements conformed to the covenants and definitions in the Credit Facilities. There was no outstanding balance as of December 31, 2019, and all amounts associated with the 5.555% longwall financing arrangement have been repaid.    

 

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 was collateralized by the longwall equipment. Interest accrued on the note at a fixed rate per annum of 5.78% and was due semiannually in June and December until maturity. Principal was due in semiannual payments through maturity. The maturity date of the 5.78% longwall financing arrangement was June 2019. In addition, certain covenants and definitions in the credit agreements and guaranty agreements conformed to the covenants and definitions in the Credit Facilities. There was no outstanding balance as of December 31, 2019, and all amounts associated with the 5.78% longwall financing arrangement have been repaid.

 

Sale-Leaseback Financing Arrangements

 

In 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP, a subsidiary of Natural Resource Partners LP (“NRP”), and leased them back. The gross proceeds from this transaction were $143.5 million. As Macoupin has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. The Macoupin financing arrangement had a carrying value of $104.8 million as of December 31, 2019 and an effective interest rate of 8.1%. As a result of revisions to the Macoupin mine plan, there were significant changes to the effective interest rate and associated carrying value of the Macoupin financing arrangement during 2019.  Refer to “Critical Accounting Policies and Estimates” below for additional information.

 

In 2012, Sugar Camp sold certain rail facility assets to HOD LLC (“HOD”), a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million. As Sugar Camp has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. The Sugar Camp financing arrangement has been adjusted to fair value as part of pushdown accounting. The Sugar Camp financing arrangement had a carrying value of $55.3 million as of December 31, 2019 and an effective interest rate of 3.5%. As a result of revisions to the Sugar Camp mine plan, there were significant changes to the effective interest rate and associated carrying value of the Macoupin financing arrangement during 2019.  Refer to “Critical Accounting Policies and Estimates” below for additional information.

 

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, 2019, we had $12.3 million in letters of credit outstanding.

 

Regulatory authorities require us to provide financial assurance to secure, in whole or in part, our future reclamation projects. We had active outstanding surety bonds with third parties of $97.4 million as of December 31, 2019 to secure reclamation and other performance commitments.

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Contractual Obligations

The following is a summary of our significant contractual obligations as of December 31, 2019, by year. The table reflects the impacts of the events of default on our long-term debt obligations as a result of the Foresight Chapter 11 Cases and also includes the effects of various support agreements with certain of our principal commercial counterparties as more fully described in Part II. “Item 8. Financial Statements and Supplementary Data – Note 1. Organization, Nature of Business and Basis of Presentation” of this Annual Report on Form 10-K.  The table does not include any effects resulting from the potential settlement or discharge of our significant contractual obligations as a result of the Foresight Chapter 11 Cases.

 

 

 

We lease certain surface rights, mineral reserves, mining, transportation, and other equipment under various lease agreements with related entities under common ownership 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 agreements with affiliated parties.

 

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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 2009, Macoupin sold certain of its coal reserves to WPP LLC, an affiliate of Natural Resource Partners LP (“NRP”), 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 2012, Sugar Camp sold certain rail facilities to HOD LLC, an affiliate of NRP, 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 failed 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 8.1% and 14.8% as of December 31, 2019 and 2018, respectively, on the Macoupin sale-leaseback financing arrangement. The implied effective interest rate was 3.5% and 8.1% as of December 31, 2019 and 2018, respectively, on the Sugar Camp sale-leaseback financing arrangement. Owing to material changes to the mine plans during the current year and the resulting changes to the implied effective interest rates, we recorded a net benefit of $9.7 million on the consolidated statement of operations during the year ended December 31, 2019. If there are future material changes to the mine plans, the impact of such 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. The contractual recoupment periods are generally five to ten years from the payment date. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, assessing mine production plans, our access to capital markets, sales commitments, current and forecasted future coal market conditions, the time necessary to obtain required permits and the remaining years available for recoupment. As of December 31, 2019, we had recorded on the consolidated balance sheet prepaid royalties of $11.4 million, net of reserves.

 

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 22.7%, 11.4%, and 9.8% at December 31, 2019, 2018, and 2017, 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

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the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled. At December 31, 2019, our consolidated balance sheet reflected asset retirement obligations of $59.0 million, including amounts classified as a current liability. We estimate the aggregate undiscounted cost of final mine closures, at 2019 costs, to be approximately $99.5 million as of December 31, 2019.

 

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.

 

Interest Rate Risk

 

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2019, of our $1.3 billion in long-term debt obligation principal outstanding, $900.3 million of outstanding borrowings have interest rates that fluctuate based on changes in market interest rates. We currently do not hedge the interest on portions of our borrowings with variable interest rates, although we may do so from time to time in order to manage risks associated with floating 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 $9.0 million.

 

As of December 31, 2019, we had cash and cash equivalents of $33.9 million. Due to the short-term duration and the low risk profile of interest bearing cash accounts, we do not believe that a one percent change in interest rates would have a material impact on our interest income.

 

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, 2019, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

 

 

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Item 8. Financial Statements and Supplementary Data

 

Report of Independent Registered Public Accounting Firm

To the Unitholders of Foresight Energy LP and the Board of Directors of Foresight Energy GP LLC

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Foresight Energy LP (the “Partnership”) as of December 31, 2019 and 2018 (Successor), the related consolidated statements of operations, partners’ capital (deficit) and cash flows for the years ended December 31, 2019 and 2018 (Successor), the period from April 1, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through March 31, 2017 (Predecessor), and the related notes and the financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018 (Successor), and the results of its operations and its cash flows for the years ended December 31, 2019 and 2018 (Successor), the period from April 1, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through March 31, 2017 (Predecessor), in conformity with U.S. generally accepted accounting principles.

 

The Partnership’s Ability to Continue as a Going Concern

 

The accompanying consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 1 to the financial statements, the Partnership has suffered recurring operating losses, has a working capital deficiency and has stated that substantial doubt exists about the Partnership’s ability to continue as a going concern. In addition, the Partnership has not complied with certain covenants of loan agreements with banks. Management’s evaluation of the events and conditions and management’s plans regarding this matter are also described in Note 1. The 2019 consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.

 

Basis for Opinion

 

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

 

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

 

/s/ Ernst & Young LLP

 

We have served as the Partnership’s auditor since 2005.

 

St. Louis, Missouri

April 6, 2020

 

 

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Foresight Energy LP

Consolidated Balance Sheets

(In Thousands)

 

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Foresight Energy LP

Consolidated Statements of Operations

(In Thousands, Except per Unit Data)

 

 

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Foresight Energy LP

Consolidated Statements of Partners’ Capital (Deficit)  

 

 

 

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Foresight Energy LP

Consolidated Statements of Cash Flows

(In Thousands)

 

 

 

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Foresight Energy LP

Notes to Consolidated Financial Statements

 

1. Organization, Nature of Business and Basis of Presentation

 

Foresight Energy LLC (“FELLC”), a perpetual-term Delaware limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves, LP (“Foresight Reserves”) owned 99.333% of FELLC and a member of FELLC’s management owned 0.667%. On June 23, 2014, in connection with the initial public offering (“IPO”) of Foresight Energy LP (“FELP”), Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common and subordinated units in FELP. FELP has been managed by Foresight Energy GP LLC (“FEGP”) since the IPO.

 

On April 16, 2015, Murray Energy Corporation (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% noncontrolling economic interest in FEGP and all of the outstanding subordinated units of FELP, representing a 50% ownership percentage of the Partnership’s limited partner units. On March 28, 2017, Murray Energy acquired an additional 46% voting interest in FEGP, thereby increasing Murray Energy’s voting interest in FEGP to 80%.

 

Murray Energy’s acquisition of the incremental ownership in FEGP resulted in its obtaining control of FELP. Under Accounting Standards Codification (“ASC”) 805-50-25-4, Murray Energy, as the acquirer of FELP through FEGP, has the option to apply pushdown accounting in the separate financial statements of the acquiree. Murray Energy elected to adopt pushdown accounting in our stand alone financial statements and therefore we have reflected the required pushdown accounting adjustments in our consolidated financial statements (see Note 3).

 

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

 

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

 

The Partnership operates in a single reportable segment and currently has four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). Mining operations at our Hillsboro complex had been idled since March 2015 due to a combustion event (the “Hillsboro combustion event”). In January 2019, we resumed production at our Hillsboro complex with one continuous miner unit.  In March 2020, longwall production at our Hillsboro complex resumed.  Our mined coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern half of the United States, as well as overseas markets. Intercompany transactions are eliminated in consolidation.

 

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

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

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On March 10, 2020 (the “Petition Date”), the Partnership, including FEGP, FELP, and its direct and indirect subsidiaries (collectively, the “Foresight Debtors”) filed voluntary petitions for relief under chapter 11 (the “Bankruptcy Petitions”) of the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Missouri (the “Bankruptcy Court”).  The Foresight Debtors sought, and received, Bankruptcy Court authorization to jointly administer the Chapter 11 cases (the “Foresight Chapter 11 Cases”) under the caption “In re: Foresight Energy LP, et al.” Case No. 20-41308.  The Foresight Debtors will continue to manage their properties and operate their business as a “debtor in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provision of the Bankruptcy Code and the orders of the Bankruptcy Court.  

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

The Foresight Debtors also entered into support agreements with certain of its principal commercial counterparties. These agreements are subject to termination under certain circumstances, including, in the case of the Foresight Debtors, if the board of directors, board of managers or such similar governing party of the Foresight Debtors determines in good faith that performance under the support agreements would be inconsistent with its fiduciary duties. Accordingly, no assurance can be given that the support agreements will be consummated.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

 

During the year ended December 31, 2019, we incurred legal and financial advisor fees of $7.7 million related to the above issues, which have been recorded as debt restructuring costs in the condensed consolidated statements of operations.  We expect legal and financial advisor fees to continue to be substantial until such time as the above issues are remediated, if at all.

 

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

 

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.

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Revenue Recognition

Coal sales include sales to customers of coal produced and, from time to time, the re-sale of coal purchased from third parties or from one of our affiliates.  Revenue is measured based on consideration specified in a contract with a customer.  The Partnership recognizes revenue when it satisfies a performance obligation by transferring control over goods and services to a customer.

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

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.

Accounts Receivable 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, 2019 and 2018, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

Inventories, Net

Inventories are valued at the lower of average cost or net realizable value. Parts and supplies inventory consists of spare parts for equipment and supplies used in the mining process. A reserve is established for items determined to be obsolete or in excess of quantities needed. 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, labor and supply costs to perform the move 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.

Murray Energy Transport Lease and Overriding Royalty Agreements

 

In April 2015, American Century Transport LLC (“American Transport”), a subsidiary of the Partnership, entered into a purchase and sale agreement (the “PSA”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, pursuant to which American Energy sold to American Transport certain mining and transportation assets for $63.0 million. Concurrent with the PSA, American Transport entered into a lease agreement (the “Transport Lease”) with American Energy pursuant to which (i) American Transport leased to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at American Energy’s Century Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport receives from American Energy a fee ranging from $1.15 to $1.75 for every ton of coal mined, processed and/or transported using such assets,

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subject to a quarterly recoupable minimum fee of $1.7 million. The Transport Lease is being accounted for as a direct financing lease. The unearned income is reflected as other revenue over the term of the lease using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned. Refer to Note 16 for additional information on the Transport Lease.

 

Also, in April 2015, American Century Minerals LLC (“American Century Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement (“ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company (collectively, “AEC”), pursuant to which AEC granted to American Century Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The ORRA is subject to a minimum recoupable quarterly fee of $0.5 million. This overriding royalty was accounted for as a financing arrangement. The payments the Partnership receives with respect to the ORRA are reflected partially as a return of the initial investment (reduction in the affiliate financing receivable) and partially as other revenue over the life of the agreement using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned. Refer to Note 16 for additional information on the ORRA.

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. 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, 2019 and 2018, for the period January 1, 2017 to March 31, 2017, and for the period from April 1, 2017 to December 31, 2017, were not significant. 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:

 

 

Costs of developing new mines or 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.

Impairment of Depreciable and Depletable 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. During years ended December 31, 2019 and 2018 and the period from April 1, 2017 to December 31, 2017, there was $143.6 million, $110.7 million, and $42.7 million, respectively, in impairment losses recorded on depreciable assets associated with our Macoupin and Hillsboro mines (see Note 3). There were no impairment losses recorded on depreciable assets during the period January 1, 2017 to March 31, 2017.

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. Debt financing costs related to revolving credit facilities are recorded as an asset in our consolidated balance sheets and deferred issuance costs related to non-revolving facilities is recorded as a contra to the debt balance. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using either the effective interest method or straight-line method, as applicable. The debt financing costs have been adjusted to a fair value of zero as part of pushdown accounting.  Accordingly, there was no amortization expense for the years ended December 31, 2019 and 2018 and for the period from April 1, 2017 to December 31, 2017 and the unamortized debt issuance costs were $0 as of December 31, 2019 and 2018.  Amortization expense of $2.5 million is included in interest expense for the period January 1, 2017 to March 31, 2017.

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Sale-Leaseback Financing Arrangements

The Partnership is party to two arrangements in which it sold assets, to what was at the time 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). The sale-leasebacks were adjusted to fair value as part of pushdown accounting. Given material changes to the mine plans during the current year and the resulting changes to the implied effective interest rates, we recorded a net benefit of $9.7 million on the consolidated statement of operations during the year ended December 31, 2019. If there are future material changes to the mine plans, the impact of such 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.

Contract-Based Intangibles

The Partnership’s contract-based intangibles, consisting of favorable and unfavorable sales contract assets and liabilities and unfavorable royalty agreement liabilities, are amortized into contract amortization in the consolidated statement of operations. Coal sales contracts are amortized on a per ton basis as coal is sold throughout the term of each individual sales contract, which range from one to three years. Royalty agreements are amortized over a weighted average period of 15.2 years.

 

Net unfavorable contract-based intangibles were $66.2 million (net of accumulated amortization of $20.9 million) as of December 31, 2019.  The estimated aggregate amortization expense (benefit), net, related to contract-based intangibles to be recognized in each of the years ending December 31 is as follows (in thousands):

 

 

Derivative Financial Instruments

The Partnership from time to time utilizes derivative financial instruments principally to manage exposures to non-domestic coal 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 in the consolidated balance sheets.

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Warrant Liability

Our warrant liability was required to be accounted for at fair value and the fair value must be revalued at each balance sheet date until the earlier of the exercise of the warrants, their expiration, or until any of the features requiring liability treatment expires or is modified. The resulting non-cash gain or loss on the fair value revaluation at each balance sheet date is recorded as non-operating expense (income) in our consolidated statements of operations. Upon the 2017 Refinancing Closing Date (as defined in Note 3), the establishment of an exchange rate for the conversion of the warrants to a number of common units resulted in the warrants meeting the “indexed to its own stock exception” under ASC 815-40-15-7C; and therefore, the warrant liability was reclassified to partners’ capital and will not be remeasured prospectively.

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.

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. Therefore, no provision for income taxes was included in the consolidated financial statements. 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.

 

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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. The Tax Cuts and Jobs Act of 2017 signed into law on December 22, 2017, did not have a material impact on our consolidated financial statements.

 

Newly Adopted Accounting Standards

 

In February 2016, the FASB updated guidance regarding the accounting for leases (the “New Lease Guidance”). The New Lease Guidance requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The New Lease Guidance also expands the required quantitative and qualitative disclosures surrounding leases. The New Lease Guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years.

 

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

 

The adoption of the New Lease Guidance resulted in the addition of $7.6 million in lease right-of-use assets and lease liabilities on our consolidated balance sheet at January 1, 2019. The adoption of the New Lease Guidance did not have a material effect on our results of operations and had no impact on cash flows. Additionally, there was no cumulative adjustment to partners’ capital. Refer to Note 12 for the additional financial statement disclosures required by the New Lease Guidance.

 

3. Recent Transactions and Events

 

March 2017 Refinancing Transactions

 

On March 28, 2017 (the “2017 Refinancing Closing Date”), FELP completed a series of transactions to refinance certain previously outstanding indebtedness (the “March 2017 Refinancing Transactions”). See Notes 11 and 16 for additional discussion on the debt restructuring and certain governance and other matters impacted by the March 2017 Refinancing Transactions.

 

During the period January 1, 2017 to March 31, 2017, we incurred charges of $95.5 million related to the above transactions, which have been recorded in loss on early extinguishment of debt in the consolidated statements of operations.

 

Pushdown Accounting

 

Pursuant to the acquisition by Murray Energy of the controlling interest in FEGP, management (see Note 1 and Note 16), with the assistance of a third-party valuation firm, has estimated the fair value of FELP’s assets and liabilities as of the Acquisition Date. Given that the valuation performed by the third-party valuation firm was not complete as of the Acquisition Date, the values of certain assets and liabilities were preliminary in nature and were adjusted as additional analysis was performed and as additional information was obtained about the facts and circumstances that existed at the Acquisition Date. As a result, adjustments to this allocation occurred as the valuation and the related pushdown accounting was finalized (such finalization to be completed within one year of the Acquisition Date, per the terms of ASC 805-50-25-4). Adjustments to the fair value of FELP’s asset and liabilities as of the Acquisition Date were recorded during the period in which the adjustment is determined, including the effect on earnings of any amounts we would have

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recorded in previous periods if the accounting had been completed at the Acquisition Date (i.e. the historical reported financial statements will not be retrospectively adjusted). Pushdown accounting was finalized during the fourth quarter of 2017.

 

The fair value of our mineral rights, which are controlled through private coal leases, were established utilizing discounted cash flow (“DCF”) models. The DCF models were based on assumptions market participants would use in the pricing of these assets as well as projections of revenues and expenditures that would be incurred to mine or maintain these coal reserves through the life of mine. Our DCF models assumed that the combustion event at our Hillsboro mine will subside and that production would resume at this mine.  The tax-effected discount rates utilized in the DCF models ranged from 11.5% to 15.5% and the future cash flows were based on our forecast models, which included a variety of estimates and assumptions, such as pricing and demand for coal and expected future capital expenditures. Coal pricing was based principally on third-party forward pricing curves, adjusted for the quality and expected sales point of our coal.

 

The fair value of plant and equipment was established with the assistance of a third-party valuation firm utilizing both market and cost approaches. The market approach was used to estimate the value of assets where detailed product specification data and maintenance history for the asset was available and an active market was identified for comparable property. The cost approach was utilized where there were limitations in the secondary equipment market. Under the cost approach, an estimate of the replacement cost of the asset was made adjusting for depreciation due to physical deterioration and also contemplated functional and economic obsolescence, where appropriate. Useful lives were assigned to all assets based on remaining future economic benefit of each asset.

 

The carrying values of certain of FELP's assets and liabilities in this estimate were assumed to approximate their fair values.

 

Due to the unobservable inputs used in the valuation, the fair values of the assets and liabilities of FELP as of the Acquisition Date are considered Level 3 fair value measurements.

 

The net pushdown accounting adjustments to record the assets and liabilities of FELP to fair value as of the Acquisition Date resulted in a $952 million net increase to net assets, and was comprised of the following adjustments from carrying value as of the Acquisition Date (in thousands):

 

 

(1) – Working capital and other long-term liabilities included liabilities of $16.9 million and $38.9 million, respectively, for certain royalty and transportation executory contracts under which we have contractual future minimum required payments but we did not expect to receive any future economic benefits at the time of the application of pushdown accounting.

(2) – The development costs of the mine were reduced to zero as part of the fair value adjustment and the corresponding value of mineral rights assets was increased to reflect the future cash flows that the developed mines are expected to generate. As a result, the value of the plant, equipment and development asset category decreased significantly and the value of the mineral rights category increased significantly.

 

The following table presents each major class of intangible assets identified as of the Acquisition Date (in thousands):

 

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The fair values of unfavorable sales contracts, net and unfavorable royalty agreements were determined using a DCF model based on the difference between estimated market rates and actual contract rates for each of the respective contracts. The favorable and unfavorable sales contract assets and liabilities are amortized into contract amortization in the consolidated statement of operations on a per ton basis as the coal is sold throughout the term of each individual sales contract, which range from one to three years.  The unfavorable royalty agreement liabilities were originally amortized into contract amortization in the consolidated statement of operations over a weighted average period of 17.2 years.

 

Hillsboro Impairment

 

Our Hillsboro mine experienced an underground combustion event beginning in March 2015. Since that time, we have worked closely with the Mine Safety and Health Administration (“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 safely resolve any issues associated with the combustion event.  

 

On December 20, 2017, the Partnership submitted a re-entry plan to MSHA for our Hillsboro mine.  The re-entry submission contained a plan for the permanent sealing of the current longwall district immediately upon MSHA’s approval.  In connection with the re-entry plan, certain longwall equipment and other related assets were permanently sealed within and were not recovered from the Hillsboro mine. As a result, the Partnership recorded $42.7 million in impairment losses on these assets during the period from April 1, 2017 to December 31, 2017.

 

As a result of litigation matters associated with the combustion event and additional facts and circumstances arising in early April, on April 11, 2018, we announced that our Hillsboro operation would be closed and certain long-lived assets consisting primarily of mineral reserves and certain buildings and structures, machinery and equipment, and other related assets were not expected to generate future positive cash flows. As the expected future cash flows were projected to be immaterial and not sufficient to support the recoverability of the assets’ carrying values, the assets were reduced to their estimated fair values.  As such, we recorded an aggregate impairment charge of $110.7 million during the year ended December 31, 2018.  The fair values were measured primarily based on an estimate of discounted future cash flows, which are considered Level 3 fair value inputs.

 

The closure of our Hillsboro operation also resulted in the write-off of the liability associated with the unfavorable royalty agreement included within long-term contract-based intangibles on the consolidated balance sheets.  As a result, we recorded a benefit of $69.1 million during the year ended December 31, 2018.

 

In January 2019, we resumed production at Hillsboro with one continuous miner unit and in March 2020, longwall production at Hillsboro resumed.  

 

Macoupin Impairment

 

In March 2020, we idled operations at our Macoupin complex, owing to the significant challenges in the thermal coal markets. As a result, certain long-lived assets consisting primarily of mineral reserves and certain buildings and structures, machinery and equipment, and other related assets were not expected to generate future positive cash flows. As the expected future cash flows were projected to be immaterial and not sufficient to support the recoverability of the assets’ carrying values, the assets were reduced to their estimated fair values.  As such, we recorded an aggregate impairment charge of $143.6 million during the year ended December 31, 2019.  The fair values were measured primarily based on an estimate of discounted future cash flows, which are considered Level 3 fair value inputs.

 

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

 

Refer to Note 1 for information and disclosures related to our filing under Chapter 11 of the Bankruptcy Code, liquidity, capital resources, debt obligations and going concern considerations.

 

4. Revenue from Contracts with Customers

 

Significant Accounting Policy

 

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

 

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

 

Nature of Goods and Services

 

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

 

The Partnership’s coal sales contracts typically range in length from one to three years, however some agreements have terms of as little as one month. Coal sales contracts generally provide for either a fixed base price or a base price determined by a market index. The base price is subject to quality and weight adjustments. Quality and weight adjustments are recorded as necessary based on coal sales contract specifications as a reduction or increase to coal sales revenue. The coal sales contracts also may give the customer the option to vary volumes, subject to certain minimums. Coal sales are generally invoiced upon shipment and payment is due from customers within standard industry credit timeframes.  

 

Disaggregation of Revenue

 

The following table disaggregates revenue by domestic and international markets:

 

 

Contract Balances

 

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

 

 

Contract Costs

 

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

 

Other Revenues

 

Other revenues consist primarily of the Transport Lease and the ORRA with Murray Energy (see Note 2 and Note 16). These arrangements are accounted for under guidance contained in ASC 310 Receivables, ASC 360 Property, Plant, and Equipment, and ASC 842 Leases and therefore are outside the scope of ASC 606.

 

 

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5. Supplemental Cash Flow Information

 

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

 

 

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

 

 

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

 

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

 

 

6. 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 may enter into long-term, fixed price coal supply sales agreements and coal derivative swap contracts.

 

During the period January 1, 2017 to March 31, 2017, the period from April 1, 2017 to December 31, 2017, and the year ended December 31, 2016, we had outstanding coal derivative swap contracts with financial institutions to fix the selling price on future coal sales. Coal derivative 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 future sales. The coal derivative swap 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. As of and during the years ended December 31, 2019 and 2018, we had no coal derivative swap agreements outstanding.  

 

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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 settlements of commodity derivative contracts and loss on commodity derivative contracts for the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, are as follows:

 

 

We received $0 million, $0 million, $3.5 million, and $0 million in proceeds in the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, respectively, from the settlement of derivatives that were reclassified from an operating cash flow activity to an investing activity in the consolidated statements 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.

 

 

7. Accounts Receivable

Accounts receivable consists of the following:

 

 

8. Inventories, Net

Inventories, net consist of the following:

 

 

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9. Property, Plant, Equipment and Development, Net

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

 

 

 

 

10. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following:

 

 

 

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11. Long-Term Debt and Finance Lease Obligations

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

 

 

March 2017 Refinancing Transactions

 

On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to FELP in exchange for 9.6 million common units of FELP. The cash was utilized to redeem, pursuant to an equity claw redemption provision, $54.5 million of certain previously outstanding second lien notes.

 

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

 

 

We incurred third-party professional fees totaling $27.3 million related to the new indebtedness.

 

As a result of the March 2017 Refinancing Transactions, a loss on the early extinguishment of debt of $95.5 million was recognized during the period from January 1, 2017 to March 31, 2017 for the incurrence of $57.6 million in make-whole/equity-claw premiums and other cash costs to retire certain previously outstanding second lien notes and the write-off of $37.9 million of unamortized debt discounts and debt issuance costs related to the retired indebtedness.

 

Description of the Credit Facilities

 

On the 2017 Refinancing Closing Date, the Borrower entered into a Credit Agreement providing for new senior secured first-priority credit facilities consisting of a new senior secured first-priority $825.0 million term loan with a maturity of five years and a new senior secured first-priority $170.0 million revolving credit facility with a maturity of four years, including both a letter of credit sub-facility and a swing-line loan sub-facility. The Term Loan due 2022 was issued at an initial discount of $12.4 million, which is being amortized using the effective interest method over the term of the loan. Amounts outstanding under the Credit Facilities bear interest as follows:

 

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

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

 

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

 

The Credit Facilities also require us to prepay outstanding borrowings (the “Excess Cash Flow Provisions”), subject to certain exceptions, with:

 

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

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

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

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

 

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

 

The Credit Facilities require that we comply on a quarterly basis with a maximum net first lien secured leverage ratio, currently 3.50:1.00 and stepping down by 0.25x in the first quarter of 2021, which financial covenant is solely for the benefit of the lenders under the Revolving Credit Facility. The Credit Facilities also contain certain customary affirmative covenants and events of default, including relating to a change of control. We were not in compliance with the maximum net first lien secured leverage ratio as of December 31, 2019.

 

As of December 31, 2019, $743.3 million in principal was outstanding under the Term Loan due 2022, there was $157.0 million in borrowings outstanding under our Revolving Credit Facility, and $12.3 million of outstanding letters of credit secured by the Revolving Credit Facility.

 

During the year ended December 31, 2019, we prepaid $19.6 million of outstanding borrowings under the Excess Cash Flow Provisions of the Credit Facilities from cash flow generated in 2018.  

 

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

 

Description of the Second Lien Notes due 2023

 

On the 2017 Refinancing Closing Date, the Issuers issued $425.0 million aggregate principal amount of Second Lien Notes due 2023 pursuant to an indenture (the “Indenture”), dated as of the Closing Date, by and among the Issuers, the guarantors party thereto and the trustee. The Second Lien Notes due 2023 have a maturity date of April 1, 2023 and bear interest at a rate of 11.50% per annum, payable in cash semi-annually on April 1 and October 1 (commencing on October 1, 2017). The Second Lien Notes due 2023 were issued at an initial discount of $3.2 million, which is being amortized using the effective interest method over the term of Second Lien Notes due 2023. The obligations under the Second Lien Notes due 2023 are unconditionally guaranteed, jointly and severally, on a senior secured second-priority basis by each of the wholly-owned domestic subsidiaries of the Issuers that guarantee the Credit

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Facilities (which do not include Hillsboro Energy LLC). The Indenture contains certain usual and customary negative covenants and events of default, including related to a change in control.

 

Prior to April 1, 2020, the Issuers may redeem the Second Lien Notes due 2023 in whole or in part at a price equal to 100% of the aggregate principal amount thereof plus accrued and unpaid interest, if any, plus the applicable “make-whole” premium. In addition, prior to April 1, 2020, the Issuers may redeem up to 35% of the aggregate principal amount of the Second Lien Notes due 2023 at a price equal to 111.50% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed with the proceeds from a qualified equity offering, subject to at least 50% of the aggregate principal amount of the Second Lien Notes due 2023 remaining outstanding after giving effect to any such redemption. On or after April 1, 2020, the Issuers may redeem the Second Lien Notes due 2023 at a price equal to: (i) 105.750% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed prior to April 1, 2021; (ii) 102.875% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed on or after April 1, 2021 but prior to April 1, 2022; and (iii) 100.000% of the aggregate principal amount of the Second Lien Notes due 2023 redeemed thereafter.

 

As of December 31, 2019, $425.0 million in principal was outstanding under the Second Lien Notes due 2023.

 

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

 

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

 

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

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

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

Amendments to the Indenture.

 

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

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

 

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

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

 

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

 

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

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

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

Second Amendments to the Indenture.

 

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

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

 

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

 

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

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

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

Third Amendment to the Indenture.

 

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

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

 

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

 

Longwall Financing Arrangements and Finance Lease Obligations

 

In January 2010, Sugar Camp Energy LLC 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 was due semiannually in June and December until maturity. The maturity date of the 5.78% longwall financing arrangement was June 2019. In addition, certain covenants and definitions in the credit agreements and guaranty agreements conformed to the covenants and definitions in the Credit Facilities. There was no outstanding balance as of December 31, 2019, and all amounts associated with the 5.78% longwall financing arrangement have been repaid.

 

In May 2010, Hillsboro Energy LLC 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 was due semiannually in March and September until maturity. The maturity date of the 5.555% longwall financing arrangement was September 2019. In addition, certain covenants and definitions in the credit agreements and guaranty agreements conformed to the covenants and definitions in the Credit Facilities. There was no outstanding balance as of December 31, 2019, and all amounts associated with the 5.555% longwall financing arrangement have been repaid.

 

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 finance lease obligations since ownership of the longwall shields and related equipment transfer back to us upon the completion of the leases. Principal and interest payments are due monthly over the five-year terms of the leases. An aggregate termination payment of $2.8 million was due at the end of the lease terms in November 2019. There was no outstanding balance as of December 31, 2019, and all amounts associated with the finance lease obligations have been repaid.

 

Trade Accounts Receivable Securitization Program

 

In January 2015, Foresight Energy LP and certain of its wholly-owned subsidiaries, entered into a receivables securitization program (the “Securitization Program”). Under this Securitization Program, our subsidiaries sold 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 pledged its interests in the Receivables to the securitization program lenders, which made loans to the SPV. When cash was collected from customers on the Receivables, it was temporarily held in a restricted cash account for a short duration and then was transferred to an unrestricted cash account, subject to the sufficiency of our borrowing base and certain other contractual provisions. The Securitization Program had an original three-year maturity scheduled to expire on January 12, 2018. The borrowings under the Securitization Program were variable-rate and also carried commitment fee for unutilized commitments. The Securitization Program was terminated in December 2017.

 

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Maturity Tables

 

The following summarizes the contractual principal maturities of long-term debt obligations as of December 31, 2019 (note that any efforts to enforce such payment obligations under the long-term debt obligations are automatically stayed as a result of the Foresight Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the long-term debt obligations are subject to the applicable provisions of the Bankruptcy Code):

 

 

 

12. Leases

 

Lease Overview

 

The Partnership leases certain mineral reserves. The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The lease agreements typically require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. Certain of these minimum royalties are recoupable against production royalties over a contractually defined period of time (typically five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Mineral reserve leases are exempt from the balance sheet recognition requirements of the New Lease Standard. Refer to Note 13 for additional information regarding the Partnership’s mineral reserve leases.

 

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

 

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Total rental expense from operating leases for the year ended December 31, 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, was $15.6 million, $2.6 million, and $10.7 million, respectively. Included in rental expense is $11.4 million, $2.1 million, and $7.6 million for the year ended December 31, 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, respectively, of contingent rental payments related to the rail loadout facility at Williamson Energy.

 

 

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The following presents future minimum lease payments, by year, with initial terms greater than one year, as of December 31, 2019:

 

 

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 was deemed an affiliate of the Partnership at that time. 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-

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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.

 

The Macoupin Sale-Leaseback was adjusted to fair value as of the Acquisition Date as part of pushdown accounting (see Note 3). At December 31, 2019 and 2018, the carrying value of the Macoupin Sale-Leaseback was $104.8 million and $131.4 million, respectively. The effective interest rate on the financing obligation was 8.1% and 14.8% as of December 31, 2019 and 2018, respectively. Interest (benefit) expense was $(6.4) million, $18.4 million, $4.6 million, and $14.0 million for the years ended December 31, 2019 and 2018, the period from January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, respectively. As of December 31, 2019 and 2018, interest of $0.2 million and $0.5 million, respectively, was accrued in the consolidated balance sheets for the Macoupin Sale-Leaseback. The interest benefit recognized during the year ended December 31, 2019, was the due to revisions to the Macoupin mine plan (see Note 3), which resulted in significant changes to the effective interest rate and associated carrying value of 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”).

 

The Sugar Camp Sale-Leaseback was adjusted to fair value as of the Acquisition Date as part of pushdown accounting (see Note 3). At December 31, 2019 and 2018, the carrying value of the Sugar Camp Sale-Leaseback was $55.3 million and $65.1 million, respectively. The effective interest rate on the financing, which is derived from the timing and tons of coal to be mined as set forth in the current mine plan and the related cash payments, was 3.5% and 8.1% at December 31, 2019 and 2018, respectively. Interest (benefit) expense recorded on the Sugar Camp Sale-Leaseback was $(3.3) million, $5.1 million, $1.7 million, and $4.1 million for the years ended December 31, 2019 and 2018, the period from January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, respectively. As of December 31, 2019 and 2018, interest of $0.1 million and $0.2 million, respectively, was accrued in the consolidated balance sheets for the Sugar Camp Sale-Leaseback. The interest benefit recognized during the year ended December 31, 2019, was the due to revisions to the Sugar Camp mine plan, which resulted in significant changes to the effective interest rate and associated carrying value of the Sugar Camp Sale-Leaseback.

 

Sale-Leaseback Maturity Tables

 

The following summarizes the maturities of expected principal payments, based on current mine plans, on the Partnership’s sale-leaseback financing arrangements, and accrued interest at December 31, 2019:

 

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The aggregate amounts of remaining minimum lease payments on the Partnership’s sale-leaseback financing arrangements are $205.3 million. Minimum payments from 2020 through 2024 are as follows:

 

Murray Energy Transport Lease and Overriding Royalty Agreements

 

Refer to Note 16 for information and disclosures related to the Transport Lease and the ORRA.

 

13. Contractual Arrangements

 

As described in Note 12, the Partnership leases certain mineral reserves.  In addition, the Partnership has various transportation throughput agreements with various railroads, barge companies, and bulk terminals which generally require a per ton fee amount for coal transported and contain certain escalation clauses and/or renegotiation clauses.

 

The following table presents future minimum payments, by year, required under contractual mineral reserve royalty and transportation throughput arrangements with related entities and third parties as of December 31, 2019. The table includes the effects of the RSA and of the support agreements with certain of our principal commercial counterparties as more fully described Note 1. The table does not include any effects resulting from the potential settlement or discharge of our significant contractual obligations as a result of the Foresight Chapter 11 Cases.

 

 

 

 

14. Asset Retirement Obligations

The change in the carrying amount of asset retirement obligations was as follows:

 

 

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The credit-adjusted, risk-free interest rates used in determining the asset retirement obligations were 22.7%, 11.4%, 9.8% and 7.5% at December 31, 2019, December 31, 2018, December 31, 2017, and March 31, 2017, respectively.

 

15. 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 July 1, 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, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, we recorded CWP expense of $1.0 million, $0.4 million, $0.2 million, and $0.1 million, respectively, and have an aggregate CWP liability of $3.5 million and $2.7 million recorded in the consolidated balance sheets as of December 31, 2019 and 2018, 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 and claims incurred but not yet reported. For the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, we recorded workers’ compensation claim expense of $5.7 million, $4.2 million, $0.7 million, and $2.3million, respectively, and have a workers’ compensation liability of $7.5 million and $5.8 million recorded in accrued expenses and other current liabilities in the consolidated balance sheets as of December 31, 2019 and 2018, respectively.

 

 

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16. Related-Party Transactions

 

Overview

 

Affiliated entities of FELP principally include: (a) Murray Energy, owner of a 80% interest in our general partner (effective March 28, 2017), owner of all of the outstanding subordinated limited partner units, and owner of approximately 12% of the outstanding common limited partner units and (b) Foresight Reserves, its affiliates, and other entities owned and controlled by the estate of Chris Cline, the former majority owner and former chairman of our general partner. We routinely engage in transactions in the normal course of business with Murray Energy and its subsidiaries and Foresight Reserves and its affiliates. These transactions include, among others, production royalties, transportation services, administrative arrangements, coal handling and storage services, supply agreements, service agreements, land leases, land purchases, and sale-leaseback financing arrangements. We also acquire mining equipment from subsidiaries of Murray Energy.

 

Limited Partnership Agreement

 

FEGP manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. Murray Energy and Foresight Reserves have the right to select the directors of the general partner. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to reelection by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership’s business. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses incurred or payments made by the general partner on behalf of the Partnership. No amounts were incurred by the general partner or reimbursed under the partnership agreement from the IPO date to December 31, 2019.

 

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

 

Murray Energy Investments

 

In April 2015, Murray Energy and Foresight Reserves 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. On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to us in exchange for 9,628,108 common units of FELP. On March 28, 2017, following completion of the Refinancing Transactions, Murray Energy exercised its FEGP Option to acquire an additional 46% voting interest in FEGP from Foresight Reserves and a former member of management pursuant to the terms of an option agreement, dated April 16, 2015, among Murray Energy, Foresight Reserves and a former member of management, as amended, thereby increasing Murray Energy’s voting interest in FEGP to 80%. The aggregate exercise price of the FEGP Option was $15 million. FEGP has continued to govern the Partnership subsequent to this transaction. Murray Energy was also a holder of 17,556 of FELP’s outstanding warrants. All outstanding warrants held by Murray Energy were exercised during the period from April 1, 2017 to December 31, 2017.

 

Following the exercise of the FEGP Option, certain changes to the operating agreement of FEGP went into effect, pursuant to which Murray Energy is entitled to appoint a majority of the board of directors of FEGP (the “Board”). All members of the Board, aside from one who is appointed by Foresight Reserves, are deemed appointed by Murray Energy and can be removed and replaced by Murray Energy at its sole discretion.

  

Murray Energy Management Services Agreement

 

In April 2015, a management services agreement (“MSA”) was executed between FEGP and Murray American Coal, Inc. (the ”Manager”), a wholly-owned subsidiary of Murray Energy, pursuant to which the Manager provided certain management and administration services to FELP for a quarterly fee of $3.5 million ($14.0 million on an annual basis), subject to contractual adjustments. To the extent that FELP or FEGP directly incurs costs for any services covered under the MSA, then the Manager’s quarterly fee is reduced accordingly. Also, to the extent that the Manager utilizes outside service providers to perform any of the services under the MSA, then the Manager is responsible for those outside service provider costs. The initial term of the MSA extends through December 31, 2022 and is subject to termination provisions. Upon the exercise of the FEGP Option, the General Partner entered into an amended and restated MSA pursuant to which the quarterly fee for the Manager to provide certain management and administration services to FELP was increased to $5.0 million ($20.0 million on an annual basis) and is subject to future contractual escalations and adjustments (currently $5.2 million per quarter as of December 31, 2019).

 

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Murray Energy Transport Lease and Overriding Royalty Agreements

 

In April 2015, a subsidiary of FELP, American Transport, entered into a purchase and sale agreement with a subsidiary of Murray Energy pursuant to which certain mining and transportation assets were sold to American Transport for $63.0 million.  Concurrent with the purchase and sale agreement, American Transport entered into the Transport Lease with the subsidiary of Murray Energy in which American Transport receives a fee for every ton of coal mined, processed and/or transported using the leased assets.  Refer to Note 2 for additional information on the Transport Lease.  The total remaining minimum payments under the Transport Lease was $71.0 million at December 31, 2019, with unearned income equal to $21.3 million. As of December 31, 2019, the outstanding Transport Lease financing receivable was $49.7 million, of which a reserve of $49.4 million was recorded during the year ended December 31, 2019, owing to the uncertainty arising from the Murray Energy bankruptcy.

 

In April 2015, a subsidiary of FELP, American Century Minerals, entered into the ORRA with subsidiaries of Murray Energy in which the subsidiaries of Murray Energy granted American Century Minerals an overriding royalty interest for each ton of coal mined, removed, and sold from certain coal reserves for $12.0 million.  Refer to Note 2 for additional information on the ORRA.  The total remaining minimum payments under the ORRA was $26.2 million at December 31, 2019, with unearned income equal to $15.1 million. As of December 31, 2019, the outstanding ORRA financing receivable was $11.0 million, of which a reserve of $11.0 million was recorded during the year ended December 31, 2019, owing to the uncertainty arising from the Murray Energy bankruptcy.

 

Coal Sales and Purchases with Murray Energy and Affiliates

 

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

 

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

 

Murray Energy Transportation Arrangements

 

Murray Energy may transport and transload coal under our transportation and transloading agreements with third-party rail, barge, and terminal companies, resulting in usage fees owed to the third-party companies by the Partnership.  These usage fees are billed to Murray Energy, resulting in no impact to our consolidated statements of operations. The usage of the railway lines, barges, and terminal facilities with these third-party companies by Murray Energy counts towards the minimum annual throughput volumes with these third-parties, thereby reducing the Partnership’s exposure to contractual liquidated damage charges.  There was $1.2 million of such usage fees during the year ended December 31, 2019. There were no usage fees during the year ended December 31, 2018.  During the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, such usage fees totaled $0.2 million and $1.0 million, respectively.

 

We have an arrangement with Murray Energy whereby we utilized capacity on a Murray Energy transloading contract with a third-party, thereby allowing Murray Energy to reduce its exposure to certain contractual liquidated damage charges. To compensate the Partnership for the reduced contractual liquidated damages, Murray Energy reimbursed the Partnership $3.8 million, $12.6 million and $0.8 million for the years ended December 31, 2019 and 2018 and the period April 1, 2017 to December 31, 2017, respectively. The amounts are included in transportation on the consolidated statements of operations.

 

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

 

Other Murray Energy Transactions

 

We regularly purchase equipment, supplies, rebuild, and other services from affiliates of Murray Energy. On occasion, our subsidiaries provide similar services to affiliates of Murray Energy.  We also enter into combined procurement transactions with Murray Energy to combine scale and increase purchasing leverage.  

 

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

 

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Transactions with Foresight Reserves and Affiliates

 

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 a per ton amount or a percentage of the gross sales price, as defined in the respective agreements, of such coal. We also have overriding royalty agreements with Ruger pursuant to which we pay royalties equal to a percentage of the gross selling prices, as defined in the agreements. Each of these mineral reserve leases generally require a minimum annual royalty payment, which is recoupable only against actual production royalties from future tons mined during the period of ten years following the date on which any such royalty is paid.

 

Other Foresight Reserves Transactions

 

We are party to two surface leases in relation to the coal preparation plant and rail loadout facility at Williamson with New River Royalty, a subsidiary of Foresight Reserves. The primary terms of the leases expire on October 15, 2021, but may be extended by New River Royalty for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases.

 

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

 

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

 

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

 

During the period January 1, 2017 to March 31, 2017, we purchased $1.7 million in mining supplies from an affiliated joint venture under a supply agreement entered into in May 2013. The joint venture was no longer an affiliate subsequent to March 31, 2017.

 

Reserves Investor Group

 

The Reserves Investor Group includes the estate of Christopher Cline, the Cline Resource and Development Company (“CRDC”), the four trusts established for the benefit of Mr. Cline’s children (the “Cline Trust”), and certain other limited liability companies owned or controlled by individuals with limited partner interests in Foresight Reserves through indirect ownership. Concurrent with and subsequent to the March 2017 Refinancing Transactions, CRDC and the Cline Trust acquired investments in our Term Loan due 2022 and our Second Lien Notes due 2023 on consistent terms as the unaffiliated owners of these notes. In the fourth quarter of 2018, CRDC purchased the Second Lien Notes due 2023 previously held by the Cline Trust.

 

As of December 31, 2019, CRDC owned $9.9 million and $29.1 million of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023, respectively. In February 2020, CRDC divested its holdings of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023.

 

As of December 31, 2019, the Cline Trust owned $9.9 million of the outstanding principal on our Term Loan due 2022. The Cline Trust is also a holder of 17,556 of FELP’s outstanding warrants as of December 31, 2019. In February 2020, The Cline Trust divested its holdings of the outstanding principal on our Term Loan due 2022.

 

 

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The following table presents the affiliate amounts included in our consolidated balance sheets:

 

 

Murray Energy Bankruptcy

 

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

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

 

 

 

 

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A summary of (income) expenses incurred with affiliated entities is as follows for the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017:

 

 

 

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) expense, net

The contractual commitment tables for leases with affiliated parties are disclosed in Note 12. The contractual commitment tables for royalty agreements with affiliated parties are disclosed in Note 13.

 

 

17. Fair Value of Financial Instruments

 

The Partnership has no financial assets and liabilities for which fair value is measured on a recurring basis as of December 31, 2019 and 2018, respectively.  The Partnership’s commodity derivative contracts were valued based on direct broker quotes and corroborated with market pricing data. During the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, there were no assets or liabilities that were transferred between Level 1 and Level 2.

 

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Warrants

 

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):

 

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

 

As a result of a series of refinancing transactions in March 2017, the establishment of a fixed exchange rate for the conversion of the Warrants to a number of common units resulted in the warrant liability being reclassified to partners’ capital. Therefore, the Warrants are no longer remeasured to fair value. As of December 31, 2019, there are 50,480 Warrants outstanding and exercisable into 14.3 common units of FELP at an exercise price of $0.7983 per common unit.

 

Long-Term Debt

The fair value of long-term debt as of December 31, 2019 and 2018 was $398.4 million and $1,166.6 million, respectively. The fair value of long-term debt was calculated based on (i) quoted prices in markets that are not active and (ii) the amount of future cash flows associated with each debt instrument discounted at the Partnership’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms. These are considered Level 2 and Level 3 fair value measurements, respectively.

 

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. Given that the MQD not been paid beginning with the quarter ended December 31, 2015 arrearages have accrued to the benefit of common unitholders, should future distributions be paid. Our partnership agreement provides that our general partner will make a determination as to whether a distribution will be made, subject to, among other factors, compliance with our debt agreements. 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.

 

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Incentive Distribution Rights (“IDRs”)

 

Our IDRs are held by Murray Energy, and Foresight Reserves. 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. The IDRs may transfer separately from any 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 following table summarizes the quarterly distribution paid per limited partner unit (except as noted) during the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017:

 

 

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On March 27, 2017, Murray Energy contributed $60.6 million in cash to us in exchange for 9,628,108 common units of FELP. In addition, the application of pushdown accounting (see Note 3) increased the Partnership’s limited partners’ capital by $952 million.

 

19. Equity-Based Compensation

 

Long-Term Incentive Plan

 

The Partnership had a Long-Term Incentive Plan ("LTIP" or the “Plan”) for employees, directors, officers and certain key third-parties (collectively, the "Participants"). The Plan allowed 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 had been for phantom units, which upon satisfaction of vesting requirements, entitled 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. Grant levels and vesting requirements for the Partnership’s chief executive officer were determined by the Board of Directors. Grant levels and vesting requirements for all other Participants were recommended by the Partnership's chief executive officer, subject to the review and approval by the Board of Directors. On December 10, 2019, the Board of Directors terminated the LTIP and individuals holding unvested awards under the LTIP were cancelled without payment. Accordingly, no units are available for grant as of December 31, 2019.

LTIP Awards

During the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, the Partnership granted 0, 287,484, 136,799, and 5,400 phantom units, respectively, to employees under the LTIP. The awards were considered time-based unit awards and vested ratably over a three-year period, subject to continued employment. Compensation expense for these awards was recognized on a straight-line basis over the requisite service period. As of December 31, 2019, no phantom units granted to employees under the LTIP were non-vested owing to the termination of the LTIP and the cancellation of outstanding unvested awards.

Director Awards

During the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, the Partnership granted 538,268, 58,267, 0, and 5,554, phantom units, respectively, to non-employee directors under the LTIP. These awards were considered time-based unit awards and vested ratably over a three-year period. Compensation expense for these awards was recognized on a straight-line basis over the requisite service period. As of December 31, 2019, no phantom units granted to nonemployee directors under the LTIP were non-vested owing to the termination of the LTIP and the cancellation of outstanding unvested awards.

Summary

For the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, our equity-based compensation expense was $0.2 million, $0.7 million, $0.3 million, and $0.6 million, respectively, net of forfeitures. During the years ended December 31,  2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, the Partnership’s equity-based compensation is recorded in the consolidated statements of operations as follows:

 

 

As of December 31, 2019, there was no unrecognized compensation expense for phantom unit awards owing to the termination of the LTIP and the cancellation of outstanding unvested awards. All previously non-vested phantom units included tandem distribution incentive rights, which provided for the right to accrue quarterly cash distributions in an amount equal to the cash distributions the Partnership made to unitholders during the vesting period and would have been settled in cash upon vesting. Prior to the termination of

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the LTIP and the cancellation of outstanding unvested awards, the Partnership had $0.1 million accrued for this liability. These distributions that accrued to a Participants’ account were forfeited.

A summary of LTIP award activity for the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017 is as follows:

 

During the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, the Partnership settled 0, 619, 157, and 77,268 units, 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 (loss) 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. Diluted EPU reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.

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

 

 

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21. Risk Concentrations

 

Sales and Credit Risk

We determine creditworthiness for trade customers based on an evaluation of the customer’s financial condition. Credit losses have historically been minimal. The aggregate outstanding receivable balance as of December 31, 2019 from customers representing greater than 10% of our total sales was $16.4 million, which includes $14.5 million of accounts receivable from Javelin included in “Due from affiliates” on the consolidated balance sheet. As of December 31, 2019, total outstanding accounts receivable and financing receivables with Murray Energy, Javelin, and their affiliates are $23.1 million and $60.7 million, respectively (see Note 16).

 

For the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, 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, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, export tons represented 31%, 38%, 19%, and 29% of tons sold, respectively. Tons exported into Europe/U.K. during the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, represented approximately 22%, 26%, 18%, and 23%, respectively, of total tons sold during those periods. No other international geographic regions exceeded 10% of tons sold during the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017. 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

 

Litigation Matters

 

We are 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, 2019, we have $1.3 million accrued, in aggregate, for various litigation matters.

 

Insurance Recoveries

 

On November 12, 2019, we reached a resolution with our insurers regarding the remaining recoveries under our policies related to the Hillsboro combustion event. In consideration for the resolution of all claims, we received final payments totaling $25.4 million in the fourth quarter of 2019. From the date of the combustion event through December 31, 2019, we have recognized $116.5 million of insurance recoveries related to the recovery of mitigation costs, losses on machinery and equipment, and business interruption insurance proceeds.

 

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Insurance proceeds for the recovery of mitigation costs are recognized in cost of coal produced (excluding depreciation, depletion and amortization).  Insurance proceeds related to the recovery of losses on machinery and equipment and business interruption insurance are recorded to other operating (income) expense, net. The following table presents the location of insurance proceeds included in our consolidated statements of operations:

 

 

Performance Bonds

 

We had active outstanding surety bonds with third parties of $97.4 million as of December 31, 2019 to secure reclamation and other performance commitments.

 

 

23. Employee Benefit Plans

 

The Partnership offers a safe harbor 401(k) plan (the “Plan”) 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 Plan allows for the deferral of all or part of a participant’s compensation, as defined by the Plan, 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 Plan for the years ended December 31, 2019 and 2018, the period January 1, 2017 to March 31, 2017, and the period from April 1, 2017 to December 31, 2017, were $3.1 million, $3.2 million, $0.9 million, and $2.2 million, respectively.

 

24. Selected Quarterly Financial Information

 

A summary of the unaudited quarterly results for the years ended December 31, 2019 and 2018, is presented below (in thousands, except per unit data):

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Fourth quarter 2019 results reflect the aggregate impairment charge of $143.6 million associated with certain long-lived assets at our Macoupin operations and a charge of $60.4 million associated with a reserve on our financing receivables - affiliate.

 

The fourth quarter of 2018 includes a benefit of $10.9 million resulting from changes in estimate of the Hillsboro asset retirement obligation (see Note 15).

 

The third quarter of 2018 includes expense of $25.0 million related to the settlement of litigation related to the Hillsboro and Macoupin matters.  

 

Second quarter 2018 results reflect the aggregate impairment charge of $110.7 million associated with certain long-lived assets at our Hillsboro operations, as well as a benefit of $69.1 million to write-off of the liability associated with Hillsboro’s unfavorable royalty agreement (see Note 3).

 

 

25. Subsequent Events

Refer to Note 1 for information and disclosures related to the Foresight Chapter 11 Cases occurring subsequent to December 31, 2019.

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Item 9. Changes in and Disagreements With Accountant on Accounting and Financial Disclosure

None.

 

Item 9A. Controls and Procedures

 

Evaluation of Disclosure 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, 2019. Based on that evaluation, our management, including our chief executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective in design and operation as of such date.

 

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, 2019, 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

 

This Annual Report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this Annual Report.

 

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, 2019, 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, 2019.

 

Item 9B. Other Information

None.

 

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PART III.

 

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 Murray Energy and Foresight Reserves. 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 Exchange Act. The directors are appointed by Murray Energy and Foresight Reserves in proportion to their respective voting interests in our general partner: Foresight Reserves’ voting interest is approximately 20% and Murray Energy’s voting interest is approximately 80%. 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 Exchange Act. As a publicly traded limited partnership, we are not required 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 Exchange Act.

 

Robert D. Moore and Jeremy J. Harrison allocate their time between managing our business and affairs and the business and affairs of Murray Energy. The amount of time that they devote to our business and the business of Murray Energy 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 (the “Manager”) provides certain management and administration services to the Partnership for a quarterly fee (the “Management Services Agreement” or “MSA”), 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 20, 2020. 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 of our general partner. 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. Mr. Moore and Mr. Murray are first cousins. There are no other family relationships among any of our directors or executive officers.

 

 

 

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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 29 years of experience in management, operations, finance, accounting, and acquisitions in the coal industry. He has been our President and Chief Executive Officer, and a member of the board of directors of our general partner, since May 2015. Mr. Moore also serves as Murray Energy Corporation’s President and Chief Executive Officer, a position he has held since October 2019, as well as Murray Energy Corporation’s Chief Operating Officer and Chief Financial Officer, positions he has held since August 2012 and September 2007, respectively, and he is a member of Murray Energy’s board of directors. 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 of our general partner on September 9, 2015. Mr. Casey is a retired 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 is the former Treasurer of the American Bar Association and is a member of its Board of Governors. He served as Chief of Staff to the Governor of West Virginia and is currently an appointed member of the West Virgina Workers Compensation Board of Review. He also serves on the board of directors of Security National Trust, Inc and is an adjunct professor of Law at West Virginia University College of Law and an adjunct professor at the University of Charleston College of Pharmacy.  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.

 

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 of our general partner in September 2014. Mr. Hermann is a founding partner of Lechwe Holdings LLC, a family office which is involved in the startup and investing in companies. He 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 Chairman of the Board. He also previously served as a Director of Fifth Third Bank Southern Indiana. Mr. Hermann holds a Bachelor of Science degree from Indiana State University in Evansville and was 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.

 

Robert E. Murray is a member of the board of directors of our general partner. He was appointed to the board of directors of our general partner on March 28, 2017. Since February 2015, Mr. Murray has been the Executive Vice President — Marketing and Sales of Murray Energy Corporation. He previously served as Vice President — Marketing, Sales and Transportation of Murray Energy Corporation from 2012 to 2015, and served as Vice President — Business Development and External Affairs of Murray Energy Corporation from 2007 to 2012. Since 2008, Mr. Murray also served as the President of American Mountaineer Energy, Inc., a wholly-owned subsidiary of Murray Energy Corporation. From 1996 to 2007, Mr. Murray held various management positions within Murray Energy Corporation and its affiliated operations, including General Manager and Superintendent of The Ohio Valley Coal Company and Account Executive and Manager of Transportation and Quality Control for The American Coal Sales Company. Mr. Murray has extensive experience in marketing and sales, quality control, and transportation. Mr. Murray received his Bachelor of Science in Mining Engineering from West Virginia University and an M.B.A. from The Ohio State University  

 

Lesslie H. Ray is a member of the board of directors of our general partner. She was appointed to the board of directors of our general partner on March 25, 2019. Ms. Ray has served as the Chief Executive Officer for Greenway Wealth Management LLC since April of 2017.  From April 2013 to April 2017, Ms. Ray worked on the Foresight Management LLC business development team, spending the majority of her time with various Foresight Energy related commercial and financial transactions. Prior to this, Ms. Ray worked in banking for JPMorgan Chase & Company and Bank of America Securities in capital markets focused on real estate.  Ms. Ray earned her Bachelor of Business Administration from the University of Georgia as well as her Masters of Business Administration from University of North Carolina - Chapel Hill.

 

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Brian D. Sullivan is an independent member of the board of directors of our general partner. He was appointed to the board of directors of our general partner on August 10, 2016. Mr. Sullivan is currently the CEO of Conuma Coal Resources Ltd, a producer of metallurgical coal in Western Canada that exports to Asian steel producers. He has held this position since September 2016. Prior to his current position with Conuma, Mr. Sullivan worked in various roles with Alpha Natural Resources, Inc. (“Alpha”), serving as Chief Commercial Officer, and spent two years working for Alpha in Australia. Mr. Sullivan was also Senior Vice President and General Counsel to The United Company (“United”), a private holding company headquartered in Bristol, Virginia, as well as to United’s subsidiaries in the coal, and oil and gas businesses. Mr. Sullivan was litigation counsel with Paul, Hastings, Janofsky & Walker LLP, and with Arent Fox LLP. before his career in the energy sector. Mr. Sullivan is a graduate of Duke University and The State University of New York at Buffalo School of Law. Mr. Sullivan has served on the boards of the Virginia Center for Coal and Energy Research, the Virginia Coal Association, the National Mining Association, Pfeiffer University in Charlotte, Barter Theater (the State Theater of Virginia) and Crossroads Medical Mission. The experience and qualifications that led to the conclusion that Mr. Sullivan should serve as a member of the board of directors of our general partner include his legal background, extensive knowledge of the energy industry and his financial expertise.

 

Jeremy J. Harrison is the Principal Financial Officer and Chief Accounting Officer of our general partner. Mr. Harrison has served as the Chief Accounting Officer since September 30, 2017.  Mr. Harrison has served as the Chief Accounting Officer of Murray Energy Corporation since August 2017.   Mr. Harrison previously served as Corporate Controller of Murray Energy Corporation from 2015 to 2017. Prior to his position at Murray Energy Corporation, Mr. Harrison was employed as a senior manager at a regional public accounting firm. Mr. Harrison is a certified public accountant and holds a Bachelor of Science in Business Administration and Masters of Business Administration from John Carroll University.

 

Director Independence

 

Our board has determined that Messrs. Casey, Hermann and Sullivan are independent 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 meeting of the board of directors of our general partner. 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 established in accordance with the Exchange Act 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 Exchange Act. Messrs. Casey, Hermann and Sullivan 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.

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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 Murray Energy and Foresight Reserves, and must meet the independence standards established by 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 the 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 the 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.  

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Item 11. Executive Compensation

 

Compensation Discussion and Analysis

 

Overview of Compensation Program

 

We seek 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 2019 for our principal executive officer, our principal financial officer, and any other of our 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:

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 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. The principal elements of our executive compensation programs for 2019 was base salary.    

 

Compensation Practices and Procedures

 

Role of the Board of Directors

 

We do not have a compensation committee. Material compensation decisions with respect to our Named Executive Officers are approved by the Board but, where appropriate, decisions are made in conjunction with the advice and recommendations of the Named Executive Officers. The responsibility of the Board may include reviewing base salary and incentive compensation levels, and administering our equity compensation plans.

 

Role of Named Executive Officers in Compensation Decisions in 2019

 

In the role of President and Chief Executive Officer, Mr. Moore assisted in determining executive compensation by making recommendations to the other members of the Board on material compensation decisions for officers other than himself based upon his assessment of the individual performance of each executive officer and overall performance. In addition, in recommending specific levels or components of compensation, Mr. Moore took into account his general business knowledge and experience and specific knowledge of the market in which we compete for talent.

 

Role of Compensation Consultant

 

During 2019, 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 as noted above.

 

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Components of the Compensation Program

 

For the year ended December 31, 2019, the principal component of compensation for the Named Executive Officers was base salary.

 

Base Salary

 

Our Board did not make base salary decisions for Mr. Moore and Mr. Harrison in 2019, as their compensation is generally not paid directly by us. Although Mr. Moore and Mr. Harrison provide employment services to both Murray Energy Corporation and to us, they also have many overlapping roles and duties due to the close relationship that we maintain with Murray Energy Corporation following their investment in us. We pay a predetermined annual fee to Murray Energy Corporation for Mr. Moore’s and Mr. Harrison’s services. While there is not a specific allocation to us with respect to Mr. Moore’s and Mr. Harrison’s services, we have determined that it would be appropriate to allocate a portion of the total compensation that each receives from Murray Energy Corporation to us within the Summary Compensation Table below. The allocated amounts were determined by looking at the time that Mr. Moore and Mr. Harrison spend at each of the respective companies as well as the time spend in their 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. It was determined that allocating $150,000 of Mr. Harrison’s compensation to us was a reasonable estimate of the portion of the payment that we make to Murray Energy Corporation for Mr. Harrison’s services.  

 

Annual Cash Incentives

 

We historically provided our Named Executive Officers with an opportunity to earn an annual cash incentive, with the Board making decisions regarding Mr. Moore’s annual incentive awards. The amount of a Named Executive Officer’s annual cash incentive for any given year is based upon subjective determination of such individual’s respective individual contributions to the Partnership in the area for which they are responsible, to successful mining operations, and to our overall performance during the year. Such annual cash incentives to our Named Executive Officers are discretionary and therefore not formally based upon any pre-established performance metrics or targeted to any specific level of compensation, although the Partnership’s operational and strategic goals are also taken into consideration as appropriate. The Board determined that our Named Executive Officers would not receive an annual incentive bonus in 2019.  

 

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. On December 10, 2019, the Board of Directors terminated the LTIP and individuals holding unvested awards under the LTIP were cancelled without payment. There were no equity compensation awards granted to Named Executive Officers during 2019.

 

Retirement and Other Benefits

 

Our Named Executive Officers are generally 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. However, as Mr. Moore and Mr. Harrison are not employed directly by and we instead pay a predetermined annual fee to Murray Energy Corporation for Mr. Moore’s and Mr. Harrison’s services, no such benefits were provided during the 2019 year.    

 

Perquisites

 

The Partnership may provide a limited amount of perquisites and personal benefits to the current Named Executive Officers, although no such benefits were provided during the 2019 year. 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 and Severance Benefits

 

We did not maintain any other employment agreements or severance plans which covered our Named Executive Officers during the 2019 year.

 

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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 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-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.

 

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.

 

 

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Executive Compensation

 

The following table summarizes the compensation we paid during the years ended December 31, 2019, 2018 and 2017, as applicable, to our Named Executive Officers.

 

Summary Compensation Table

 

 

 

Grants of Plan-Based Awards

On December 10, 2019, the Board of Directors terminated the LTIP and individuals holding unvested awards under the LTIP were cancelled without payment. There were no equity compensation awards granted to Named Executive Officers during 2019.  

 

Outstanding Equity Awards at Fiscal Year-End

 

On December 10, 2019, the Board of Directors terminated the LTIP and individuals holding unvested awards under the LTIP were cancelled without payment.

Option Exercises and Units Vested

 

Mr. Moore had 84,815 units vest during 2019, which resulted in value realized upon vesting of $289,876 based upon the closing price of our common units on the vesting date. No Named Executive Officer held option awards during 2019.  

 

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.

 

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Director Compensation

 

The compensation of the directors of our general partner is set by the Board. Mr. Moore, Mr. Murray, and Ms. Ray 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. Previously, the eligible directors would also receive an annual phantom unit award in the amount of $75,000 which was be designed to vest pro-rata over a three year period. On December 10, 2019, the Board of Directors terminated the LTIP and individuals holding unvested awards under the LTIP, including any annual phantom unit awards granted to eligible directors in 2019, were cancelled without payment.

 

 

CEO Pay Ratio Disclosures

 

As required by Section 953(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) and Item 402(u) of Regulation S-K (17 CFR 229.402), we our providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Robert D. Moore, President and Chief Executive Officer (the “CEO”).

 

 

To identify the median of the annual total compensation of all our employees, we determined that our employee population consisted of approximately 1,030, 982 and 1,020 individuals for the years ended December 31, 2019, 2018, and 2017, respectively.  These individuals were all located in the United States and consisted of all of our full-time, part-time, and temporary employees and includes individuals employed at any time during the year.  We used a consistently applied compensation measure to identify our median employee, in which we compared the amount of salary or wages reflected in our payroll records as reported to the Internal Revenue Service on Form W-2.  After identifying our median employee, we combined all of the elements of such employee’s compensation, which comprised such employee’s Form W-2 compensation and contributions made by the Partnership on the employee’s behalf to our 401(k) plan.  As all of our employees, including the CEO, are located in the United States, we did not make any cost of living adjustments in identifying the median employee.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

 

The following table sets forth certain information as of March 20, 2020 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 80% by Murray Energy Corporation and 20% by Foresight Reserves. The address of Murray Energy Corporation is 46226 National Road, St. Clairsville, OH, 43950. The address of Foresight Energy GP LLC and each of the directors and officers reflected in the table below is 211 North Broadway, Suite 2600, Saint Louis, MO, 63102. The address of each of the Estate of Christopher Cline and the Cline Trust Company is 3825 PGA Blvd., Suite 1101, Palm Beach Gardens, Florida 33410. The percentage of units beneficially owned is based on 80,996,773 common units and 64,954,691 subordinated units outstanding.

 

*    Less than one percent.

 

 

Equity Compensation Plan Information

 

On December 10, 2019, the Board of Directors terminated the LTIP and individuals holding unvested awards under the LTIP were cancelled without payment.

 

 

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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, owner of a 20% interest in our general partner and (b) Murray Energy Corporation and its affiliates, the 80% owner of our general partner, owner of approximately 12% of the outstanding common units and owner of all of the outstanding subordinated units as of March 20, 2020.

 

See Part II. “Item 8. Financial Statements and Supplementary Data, Note 16—Related-Party Transactions” in the notes to our consolidated financial statements in this Annual Report on Form 10-K for a description of certain relationships and related transactions, which are incorporated herein by reference.

 

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 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

 

 

 

 

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.

 

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Transactions with The Cline Group and its Affiliates

 

Coal Leases and Development Agreements

 

Williamson leases coal reserves from Colt, LLC (“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 a per ton amount or a percentage of the gross sales price of such coal. The minimum royalty for the current term of 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, 2019, 2018 and 2017, Williamson paid $16.5 million, $21.0 million, and $10.0 million, respectively, in royalties to Colt under this coal lease.

 

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 a per ton amount or a percentage of the gross sales price of such coal. The minimum royalty for the current term 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 paid, is $4.0 million. Hillsboro paid $8.0 million in each of the years ended December 31, 2019 and 2017 in royalties to Colt under this coal lease. While the advance minimum payments under this agreement remain eligible for recoupment, all amounts have been adjusted to a fair value of zero in the application of pushdown accounting as we do not expect to recoup this balance based on the remaining recoupment period.

 

Sugar Camp leases coal reserves from Ruger, LLC (“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 a per ton amount or a percentage 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, 2019, 2018 and 2017, Sugar Camp paid $13.9 million, $9.8 million and $10.5 million, respectively, in royalties to Ruger under these coal lease and overriding royalty agreements described above.

 

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 a per ton amount or a percentage of the gross sales price of such coal. The minimum royalties for the current term 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.

 

In June 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 a per ton amount or a percentage of the gross sales price of such coal. The minimum royalty for the current term of 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. 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 each of the years ended December 31, 2018 and 2017, Macoupin paid $2.0 million in royalties to Colt under each of these coal leases.  While the advance minimum payments under this agreement remain eligible for recoupment, all amounts have been adjusted to a fair value of zero in the application of pushdown accounting as we do not expect to recoup this balance based on the remaining recoupment period.

 

As of December 31, 2019 and 2018, the mines had $3.0 million and $1.8 million, respectively, in aggregate outstanding payables to Colt and Ruger under all of the leases above. In addition, 2019 minimum annual payments to Colt and Ruger totaling $13.0 million were outstanding at December 31, 2019.  During the years ended December 31, 2019, 2018 and 2017, we paid Colt and Ruger $38.4 million, $36.8 million and $34.6 million, respectively, in aggregate royalty payments under the agreements described herein.

 

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The following presents future minimum royalties, by year, required under noncancelable royalty agreements with Foresight Reserves and its affiliates as of December 31, 2019. The table includes the effects of the restructuring support agreement and of the support agreements with certain of our principal commercial counterparties as more fully described in Part II. “Item 8. Financial Statements and Supplementary Data, Note 1—Organization, Nature of Business and Basis of Presentation” in the notes to our consolidated financial statements in this Annual Report on Form 10-K (in millions).

 

 

 

Hillsboro 2 and 3 Development Agreement

 

Hillsboro has a development agreement with Colt (the “Hillsboro Development Agreement”) pursuant to which Colt has 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

 

Macoupin has a development agreement with Colt (the “Macoupin Development Agreement”) pursuant to which Colt has 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

 

Sugar Camp has a development agreement with Ruger (the “Sugar Camp Development Agreement”) pursuant to which Ruger has 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.

 

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

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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.

 

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

 

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.

 

See Part II. “Item 8. Financial Statements and Supplementary Data, Note 16—Related-Party Transactions” in the notes to our consolidated financial statements in this Annual Report on Form 10-K for a description of additional transactions with The Cline Group and its affiliates, which is incorporated herein by reference.

 

Transactions with Murray Energy Corporation and its Affiliates

 

On April 16, 2015, Foresight Reserves and Murray Energy executed a purchase and sale agreement whereby Murray Energy paid Foresight Reserves $1.37 billion to acquire a 34% voting interest in FEGP, 77.5% of FELP’s incentive distribution rights (“IDR”) and 100% of the outstanding subordinated units in FELP. FEGP has continued to govern the Partnership subsequent to this transaction. Murray Energy also had an option (the “GP Option”), to purchase an additional 46% of the voting interests in FEGP for $15 million.

 

On March 27, 2017, Murray Energy contributed $60.6 million in cash (the “Murray Investment”) to us in exchange for 9,628,108 common units of FELP. On March 28, 2017, following completion of the Refinancing Transactions, Murray Energy exercised its GP Option to acquire an additional 46% voting interest in FEGP thereby increasing Murray Energy’s voting interest in FEGP to 80%. The aggregate exercise price of the FEGP Option was $15 million. FEGP has continued to govern the Partnership subsequent to this transaction. Murray Energy was also a holder of 17,556 of FELP’s outstanding warrants. All outstanding warrants held by Murray Energy were exercised during the year ended December 31, 2017.

 

Following the exercise of the FEGP Option, certain changes to the operating agreement of FEGP went into effect, pursuant to which Murray Energy is entitled to appoint a majority of the board of directors of FEGP (the “Board”). All members of the Board, aside from one who is appointed by Foresight Reserves, are deemed appointed by Murray Energy and can be removed and replaced by Murray Energy at its sole discretion.

 

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See Part II. “Item 8. Financial Statements and Supplementary Data, Note 16—Related-Party Transactions” in the notes to our consolidated financial statements in this Annual Report on Form 10-K for a description of transactions with Murray Energy Corporation and its affiliates, which is incorporated herein by reference.

 

Procedures for Review, Approval and Ratification of Transactions with Related Persons

 

The information appearing under Part III. “Item 10. Directors, Executive Officers and Corporate Governance of the Managing Partner — Conflicts Committee” is incorporated herein by reference.

 

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. 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 2019 and 2018:

 

 

 

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. All of the fees in the table above were approved in advance by the audit committee.

 

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PART IV

 

Item 15. Exhibits and Financial Statement Schedules

 

 

 

 

 

  

 

 

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INDEX TO EXHIBITS

 

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Item 16. Form 10-K Summary

None.

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on April 6, 2020.

  

 

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. 

 

 

 

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