S-1/A 1 d737973ds1a.htm AMENDMENT NO. 12 TO FORM S-1 Amendment No. 12 to Form S-1
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As filed with the Securities and Exchange Commission on June 9, 2014

Registration No. 333-179304

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

AMENDMENT NO. 12

TO

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

FORESIGHT ENERGY LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1220   80-0778894

(State or other jurisdiction of

incorporation)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

211 North Broadway

Suite 2600

Saint Louis, MO 63102

(314) 932-6160

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Oscar Martinez

Chief Financial Officer

211 North Broadway

Suite 2600

Saint Louis, MO 63102

(314) 932-6160

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

William M. Hartnett, Esq.

William J. Miller, Esq.

Kimberly C. Petillo-Décossard, Esq.

Cahill Gordon & Reindel LLP

80 Pine Street

New York, New York 10005

Telephone: (212) 701-3000

Fax: (212) 269-5420

  

Mike Rosenwasser, Esq.

E. Ramey Layne, Esq.

Vinson & Elkins L.L.P.

666 Fifth Avenue

New York, New York 10103

Telephone: (212) 237-0000

Fax: (212) 237-0100

  

Jason R. Lehner, Esq.

Shearman & Sterling LLP

599 Lexington Avenue

New York, New York 10022

Telephone: (212) 848-4000

Fax: (646) 848-7974

  

Joshua Davidson

Douglass M. Rayburn

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

Telephone: (713) 229-1234

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 (the “Securities Act”), check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of each class of
securities to be registered
  

Amount

to be

registered(1)

  

Proposed

maximum
offering price

per unit

  

Proposed

maximum
aggregate

offering price(1)(2)

  Amount of
registration fee(3)

Common units representing limited partner interests

  

20,125,000

  

$21.00

   $422,625,000   $50,174

 

 

(1) Includes 2,625,000 common units that the underwriters have the option to purchase to cover over-allotments, if any.
(2) Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(a) under the Securities Act of 1933.
(3) Of this amount, $34,380 has been previously paid. The previously paid amount was based on a $300,000,000 proposed maximum aggregate offering price and the SEC filing fee at the time of filing of $114.60 per $1,000,000 of aggregate offering amount.

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED JUNE 9, 2014

PRELIMINARY PROSPECTUS

FORESIGHT ENERGY LP

17,500,000 Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of our common units representing limited partner interests. Prior to this offering, there has been no public market for our common units. We are offering 17,500,000 common units in this offering. We currently expect the initial public offering price to be between $19.00 and $21.00 per common unit.

The underwriters have the option to purchase up to 2,625,000 additional common units from us at the initial public offering price, less the underwriting discounts and a structuring fee payable to Barclays Capital Inc., Citigroup Global Markets Inc. and Morgan Stanley & Co. LLC, within 30 days from the date of this prospectus to cover over-allotments, if any.

We have applied to have our common units listed on the New York Stock Exchange under the symbol: “FELP.” The listing is subject to the approval of our application.

 

 

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and, as such, may elect to comply with certain reduced public company reporting requirements. See “Prospectus Summary—Our Emerging Growth Company Status” on page 11. Investing in our common units involves risks. See “Risk Factors” beginning on page 22.

The risks include the following:

 

    We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

 

    A further decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.

 

    We compete in a global coal market and could be negatively impacted by an increase in global coal supply as well as a decrease in global market demand.

 

    Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws, regulations or enforcement could materially increase our operating costs or limit our ability to produce and sell coal.

 

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

 

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, or initially to remove our general partner without its consent.

 

    Unitholders will experience immediate and substantial dilution of $19.35 per common unit.

 

    There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

 

    Our tax treatment depends on our status as a partnership for U.S. 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 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 could be substantially reduced.

 

    Our unitholders will be required to pay taxes on their share of income even if they do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

 

     Per Common Unit      Total  

Public Offering Price

   $                $            

Underwriting Discount(1)

   $         $     

Proceeds to Foresight Energy LP (before expenses)(2)

   $         $     

 

(1) Excludes a structuring fee of 0.75% of the gross proceeds of this offering payable to Barclays Capital Inc., Citigroup Global Markets Inc. and Morgan Stanley & Co. LLC. The underwriters will receive compensation in addition to the underwriting discount. See “Underwriting.”
(2) We intend to use the net proceeds from this offering to repay certain amounts of our Term Facility (as defined herein) and distribute the remaining net proceeds to Foresight Reserves, L.P. and a member of management, pro rata, and we will not retain any proceeds from this offering. Please see “Use of Proceeds.”

The underwriters expect to deliver the common units to purchasers on or about                     , 2014.

 

 

 

Barclays   Citigroup   Morgan Stanley
J.P. Morgan   Goldman, Sachs & Co.   Deutsche Bank Securities

 

Stifel

  Credit Agricole CIB
PNC Capital Markets LLC   Huntington Investment Company

 

                    , 2014


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You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

 

 

TABLE OF CONTENTS

 

     Page  

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     22   

USE OF PROCEEDS

     59   

DILUTION

     60   

CAPITALIZATION

     61   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     63   

HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

     77   

SELECTED HISTORICAL FINANCIAL INFORMATION

     91   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     94   

BUSINESS

     117   

THE COAL INDUSTRY

     141   

ENVIRONMENTAL AND OTHER REGULATORY MATTERS

     159   

MANAGEMENT

     165   

EXECUTIVE COMPENSATION

     169   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     173   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     180   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     193   

DESCRIPTION OF INDEBTEDNESS

     194   

DESCRIPTION OF COMMON UNITS

     200   

THE PARTNERSHIP AGREEMENT

     202   

UNITS ELIGIBLE FOR FUTURE SALE

     216   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     218   

INVESTMENT IN FORESIGHT ENERGY LP BY EMPLOYEE BENEFIT PLANS

     234   

UNDERWRITING

     236   

LEGAL MATTERS

     242   

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

     242   

EXPERTS—COAL RESERVES

     242   

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     242   

MARKET AND INDUSTRY DATA AND FORECASTS

     243   

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

     243   

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

     F-1   

APPENDIX A: FORM OF PARTNERSHIP AGREEMENT

     A-1   

APPENDIX B: CERTAIN DEFINED TERMS—BUSINESS

     B-1   

APPENDIX C: CERTAIN DEFINED TERMS—OFFERING STRUCTURE

     C-1   


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Coal Reserve Information

Reserves are broadly defined as that part of a mineral deposit which could be economically and legally extracted or produced at the time of reserve determination and are further classified as proven or probable according to the degree of certainty of existence. In determining whether our reserves meet this standard, we take into account, among other things, our potential ability to obtain a mining permit, 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 economically recoverable 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 fund our ongoing replacement capital. The reserves in this prospectus are classified by reliability or accuracy in decreasing order of geological assurance as Proven (Measured) and Probable (Indicated). The terms and criteria utilized to estimate reserves for this study are based on United States Geological Survey Circular 891 and in general accordance with the SEC guidelines, and are summarized as follows:

 

    Proven (Measured) Reserves: Tonnages computed from seam measurements as observed and recorded in drill holes, mine workings, and/or seam outcrop prospect openings. The sites for measurement are so closely spaced and the geological extent of the coal is so well defined that the size, shape, depth and mineral contents of the reserves are well-established. This classification has the highest degree of geological assurance.

 

    Probable (Indicated) Reserves: Tonnages computed by projection of data from available seam measurements for a distance beyond the Proven classification. The assurance, although lower than for Proven, is high enough to assume continuity between points of measurement. This classification has a moderate degree of geological assurance. Further exploration is necessary to place these reserves in the Proven classification.

As of January 1, 2014, all of our proven and probable coal reserves were assigned reserves, which are coal reserves that have been designated for mining by a specific or a potential future operation.

The information appearing in this prospectus concerning estimates of our proven and probable coal reserves was prepared by Weir International, Inc. for our existing reserves as of January 1, 2014. Unless otherwise noted, all estimates regarding our proven and probable coal reserves discussed in this prospectus are based on the reserve report discussed immediately above. All Btus per pound are expressed on an as-received basis.

 

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information you should consider before investing in our common units. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover page of this prospectus) and (2) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read the entire prospectus carefully, including the section describing the risks of investing in our common units under “Risk Factors” and the consolidated financial statements contained elsewhere in this prospectus before making an investment decision. Some of the statements in this summary constitute forward-looking statements. See “Special Note Regarding Forward-Looking Statements.” For the definitions of certain terms used in this prospectus, see “Appendix B: Certain Defined Terms—Business” and “Appendix C: Certain Defined Terms—Offering Structure.”

References in this prospectus to “Foresight Energy LP,” “we,” “our,” “us,” or like terms when used in a historical context refer to the business of our predecessor, Foresight Energy LLC and its subsidiaries, which will be our wholly-owned subsidiaries following this offering. When used in the present tense or prospectively, those terms refer to Foresight Energy LP and its subsidiaries, giving effect to the IPO Reorganization (as defined below). References in this prospectus to “Foresight Reserves” refer to Foresight Reserves, L.P., our sponsor, and its affiliates.

Foresight Energy LP

We believe we are the lowest cost and highest margin bituminous thermal coal producer in the United States. This statement is based on a comparison of our cash costs and margins against publicly available information for other bituminous thermal coal producers as of year-end 2013. We operate exclusively in the Illinois Basin, which is the fastest growing coal producing region in the country due to its favorable geology, low costs and growing demand for its coal. Since our inception, we have invested over $2.0 billion to construct a fleet of state-of-the-art, low-cost and high productivity longwall mining operations and related transportation infrastructure. We control over 3 billion tons of coal in the state of Illinois, which, in addition to making us one of the largest reserve holders in the United States, provides significant organic growth. Our reserves are comprised principally of three large contiguous blocks of uniform, thick, high heat content (high Btu) thermal coal, which are ideal for high productivity longwall operations. We currently operate three longwall mines and a continuous miner operation. Our fourth longwall began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. We have submitted permits and made preliminary capital expenditures for our fifth and sixth longwalls. We have sufficient assigned reserves to support up to nine longwalls, with a portion of the existing surface infrastructure, slopes and shafts available to be shared among our existing, and most of our future, longwalls. We produced, and expect to produce, 18.0 million tons and 24.1 million tons in 2013 and the twelve months ending June 30, 2015, respectively. The full productive capacity of our existing mines, including the longwall that is scheduled to begin operations in 2014, is 32.7 million tons of high Btu coal per year, and the potential future productive capacity of our operations if all nine longwalls are constructed would be 67.2 million tons of high Btu coal per year. We believe that, relative to estimated production for the twelve months ending June 30, 2015, our excess existing installed capacity, and potential future capacity, will provide us with the opportunity to significantly grow our production, free cash flow and cash available for distributions to our unitholders.

 

 

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We operated three of the four most productive underground coal mines in the United States during 2013 on a clean tons produced per man hour basis based on MSHA data.

 

LOGO

 

Source: Top 25 most productive underground mines out of 255 mines with over 100,000 tons produced during 2013 on a clean tons produced per man hour basis based on MSHA data. Note: Darker shading denotes mines operated by Foresight Energy.

We have been able to sustain our high productivity and low operating costs since we started operating longwalls in 2008 and the high productivity at the new mines we have developed demonstrates the repeatability of our mine design. The high productivity translates into low costs, and in 2013, our operations had an average cash cost of $19.53 per ton sold, which we believe is significantly below the average cash costs of our competitors in the Illinois, Northern Appalachian and Central Appalachian Basins. Please see footnote 6 under “—Summary Historical Consolidated Financial and Other Information” for a US GAAP reconciliation of cash costs per ton sold. We have developed a transportation and logistics network that provides each of our complexes with two or more competing rail and barge transportation options, which we believe provides us operational and marketing flexibility, reduces the cost to deliver our coal to market and allows us to realize a higher netback to our mines. We believe our low cost structure, the high heat content of our coal, our access to competing transportation options and our location makes our coal the lowest cost option on a delivered and heat content adjusted basis to a large percentage of Eastern United States baseload coal fired power plants. We believe that this in turn provides us with higher margins per ton than our competitors and better positions us to maintain profitability through the commodity cycle.

Our operations are located in the Illinois Basin, which we believe is the best positioned thermal coal basin in the country due to the growing demand in the Eastern United States for high Btu, high sulfur coal from scrubbed power plants and the low cost structure of the Illinois Basin. Due to increasingly stringent restrictions on sulfur emissions under the Clean Air Act and other federal and state regulations, there has been a significant increase in the percentage of coal fired power generation that utilizes pollution abatement technology, or scrubbers. We believe that scrubbed power plants purchase coal largely based on the delivered cost of coal adjusted for heat content. This growing fleet of scrubbed plants represents a growing market for Illinois Basin Coal. According to Wood Mackenzie’s projections, demand for Illinois Basin coal from scrubbed power plants in the Eastern United States will increase from 102 million tons per year to 185 million tons per year from 2013 to 2020.

 

 

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As demand for high sulfur, high Btu coal grows due to increasing scrubber capacity, the Illinois Basin’s low cost, attractive geology, and access to multiple transportation routes have altered the dynamic in the Eastern United States coal market by displacing higher cost supply from the Central Appalachian and Northern Appalachian basins. We believe this dynamic is similar to the manner in which shale gas producing basins have disrupted traditional U.S. energy markets by injecting low cost supply into the U.S. natural gas market. Our reserves of thick, uniform and laterally contiguous seams of high Btu thermal coal result in significantly lower mining costs than the Central Appalachian and Northern Appalachian Basins. Due to the connectivity of the basin via multiple national rail lines and major river systems to coal fired power plants, the relative proximity of the basin to the large and growing market of scrubbed power plants, and the higher heat content of coal, we believe the Illinois Basin has an advantage on a delivered cost of coal adjusted for heat content for much of the Eastern United States.

We also have favorable access to the international market through the Canadian National Railway and an export terminal owned by an affiliate of our sponsor, and we have been exporting coal through New Orleans since 2008. We believe we are among the largest U.S. exporters of thermal coal. Since 2008, we have exported approximately 36% of our coal production to Europe, South America, Africa and Asia, including approximately 6.9 million tons in 2012, 6.5 million tons in 2013 and 1.8 million tons for the three months ended March 31, 2014. These international markets provide us with alternatives to the domestic market and have been an important economic outlet for our coal. While current margins on international sales are lower than the domestic market, the domestic and international markets are driven by different fundamentals, and we consider the international market, given its growth potential, to be a fundamental part of our marketing strategy.

We sell a significant portion of our coal under agreements with terms of one year or longer. We market and sell our coal to a diverse customer base, including electric utility and industrial companies in the Eastern United States and the international market. As of March 31, 2014, we have secured coal sales commitments for approximately 20.5 million tons for 2014, 15.4 million tons for 2015 and 11.6 million tons for 2016, which represents approximately 85%, 64%, and 48%, respectively, of our expected production for the twelve-month period ending June 30, 2015.

Our Operations

We operate four mining complexes: Williamson, Sugar Camp and Hillsboro, which are longwall operations, and Macoupin, which is currently a continuous miner operation. We have the capability to support up to nine longwall mining systems, with a combined long-term potential productive capacity of up to 67.2 million tons of high Btu coal per year. The geology, mine plan, equipment and infrastructure at each of the Williamson, Sugar Camp and Hillsboro mines are relatively similar and we anticipate similar productive capacity and productivity levels as we add additional longwalls. We estimate that each additional longwall mining system or complex could take approximately 24 to 48 months to develop and cost approximately $240.0 million to $425.0 million (based on our experience developing our existing operations and the projected mine plans). We will have the option to construct these additional longwalls, or alternatively, one of our sponsor’s affiliates may construct the longwalls and offer to sell them to us at fair market value once they are complete.

Each of our mining complexes was designed to provide at least 20 years of reserve life at their designed productive capacity without the need to spend significant capital to develop new slopes and shafts for initial access to the coal seam. We believe this design will significantly reduce our maintenance capital expenditures compared to other underground coal producers, which should enable more of our Adjusted EBITDA to result in free cash flow and sustainable distributions for our unitholders. Our maintenance capital expenditures allow us to continue operating at a productive capacity which, inclusive of our fourth longwall that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days, is 32.7 million tons for the life of our reserves (125 years based on our estimated production for the twelve months ending June 30, 2015). Our forecasted maintenance capital expenditures do not include actual or estimated

 

 

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capital expenditures for replacement of our coal reserves as these expenditures are immaterial due to our current expected mine life. The following table presents our existing and future potential mining operations:

 

(short tons in millions)    Williamson      Sugar Camp      Hillsboro      Macoupin      Total *  

Coal Reserves(1)

     388         1,366         880         459         3,092   

Existing Operations:

              

Mine Type

     Longwall         Longwall         Longwall        

 

CM /

Longwall

  

  

  

Number of Existing Longwall Mining Systems(5)

     1         2         1         0         4   

2010 Production(2)

     5.8         0.3         0.0         1.0         7.2   

2011 Production(2)

     7.2         0.9         0.5         1.8         10.4   

2012 Production(2)

     7.5         4.7         2.4         1.7         16.3   

2013 Production(2)

     6.7         6.5         4.8         0.7         18.8   

2014 Production(3)

     1.8         1.5         1.6         0.3         5.2   

Future Operations:

              

Second Longwall

           2017-2019         

Third Longwall

        2016-2018         2018-2020         

Fourth Longwall

        2017-2019            

Total number of Potential Longwall Mining Systems(4)

     1         4         3         1         9   

Current Annual Productive Capacity(6)

     7.5         13.5         9.0         2.7         32.7   

Long-term Annual Productive Capacity(7)

     7.5         27.0         24.0         8.7         67.2   

 

(1) See “Business—Coal Reserves” for more information on how we define reserves and the price at which we no longer consider our reserves to be economic. Coal reserve data is as of January 1, 2014. With respect to Williamson, the reserves shown include approximately 10 million tons of reserves that are subject to partial ownership and lack of exclusive control.
(2) As reported by MSHA through December 31 of the respective year.
(3) As reported by MSHA for the three months ended March 31, 2014.
(4) Represents total number of longwall mining systems that could be deployed, including the three currently in operation, one each at Williamson, Sugar Camp and Hillsboro and the second at Sugar Camp that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days.
(5) The second longwall system at Sugar Camp began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days.
(6) Based on current annual productive capacity of Williamson, Sugar Camp, the second longwall at Sugar Camp that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days, Hillsboro and Macoupin.
(7)

Long-term potential annual productive capacity is an estimate of the design capacity at each of Williamson, Sugar Camp, Hillsboro and Macoupin. We determine the number of longwall mining systems based on the size of the reserves for each mine, access to those reserves and the associated surface infrastructure in place at each mine. A longwall mining system includes the production of one longwall and one or two continuous miner units supporting each longwall. The third and fourth longwalls at Sugar Camp will require new surface infrastructure and a new slope and will form a new mining complex. Although Macoupin is not currently operating a longwall, Macoupin’s long-term productive capacity is shown assuming operation with three continuous miner units, along with a separate longwall system. Achievement of full productive capacity and the timing are subject to risks and uncertainties, including, among others, market conditions, adverse geology, equipment breakdowns and other operational issues, delays in obtaining required permits, engineering and mine design adjustments, and access to the liquidity necessary to develop the mines, any of which may reduce productive capacity or delay planned start-up and ramp-up or result in additional costs. Additionally, to the extent production capacity exceeds sales, we may, from time to time, temporarily adjust work schedules or idle mines to fit our sales position. We estimate we or an affiliate of our sponsor will

 

 

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  invest additional capital expenditures of between $240.0 million to $425.0 million in order to achieve full productive capacity at each incremental longwall mining system. See “Risk Factors” for a more detailed discussion of these and other risks and uncertainties.
* Due to rounding, the amounts set forth above may not total to the amounts set forth in each column.

Longwall mining is a highly-automated, underground mining technique that generates high volumes of low-cost coal production. A longwall mining system is 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.

With over 3 billion tons of coal reserves, we believe we are among the largest holders of coal reserves in the United States, and our reserves are sufficient to support 125 years based on our estimated production for the twelve months ending June 30, 2015; and over 45 years of production at our estimated full productive capacity, assuming all nine of our potential longwalls are constructed. Our reserves are located in Illinois and consist primarily of three large contiguous blocks of coal in the Herrin #6 and Springfield #5 coal seams. These thick coal seams are characterized by roof and floor geology favorable for longwall mining.

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 have contractual access to a 25 million ton per year barge-loading river terminal on the Ohio River owned by an affiliate. We have contractual rights to 11 million tons per year of current export terminal capacity in the Gulf of Mexico, including a terminal owned by an affiliate. We also have long-term, fixed price rail contracts from our mines to both of these terminals. These logistical arrangements give us transportation cost certainty and the flexibility to direct shipments to markets that provide the highest margin for our coal sales.

Our Strengths

Industry-leading productivity resulting in low production costs and attractive margins. The three longwall mines that we currently operate were three of the four most productive underground coal mines in the United States for the year ended December 31, 2013, on a clean tons produced per man hour basis based on MSHA data. Our industry leading productivity results from a combination of favorable geology, innovative mine design, a highly motivated and skilled non-unionized workforce, newly constructed automated longwall mining systems and significant investment in infrastructure. This high productivity results in low operating costs. Our consolidated cash cost per ton sold for the years ended December 31, 2013 and 2012 was $19.53 and $21.51, respectively, which we believe makes us the lowest cost bituminous producer in the United States, based on publicly available information, and significantly below the average cash costs of producers in the Illinois Basin. Our low costs drive margins that we believe are among the highest in the U.S. coal industry. In 2013 and 2012, we generated cash margins per ton sold of $21.33 and $25.30, respectively. We believe our high productivity and low cost structure will allow us to outperform our competitors and generate positive cash flow throughout the commodity cycle. Given our favorable cost position, we believe our coal will remain competitive and retain its position as base load fuel for our customers.

Favorable Illinois Basin Dynamics. The Illinois Basin is the second largest coal producing basin in the United States and the fastest growing coal producing region in the country. The basin’s growth is being driven by an increasing demand for its coal by domestic utilities that have installed or plan to install scrubbers. According to Wood Mackenzie estimates, 215 GWs, or 70% of total coal-fired generation capacity in the United States, is estimated to be scrubbed in 2013. Wood Mackenzie expects scrubbed capacity to increase to 258 GWs, or approximately 100% of total capacity, by 2025. During the same period, Wood Mackenzie forecasts an increase in domestic Illinois Basin coal demand of more than 65 million tons, with much of the demand derived from the South Atlantic and East North Central regions. We believe that scrubbed coal fired utilities purchase coal largely

 

 

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based on the delivered cost of coal adjusted for heat content. We believe that when adjusted for heat content and transportation cost, Illinois Basin coal in general, and our coal in specific, is the lowest cost fuel supply for a substantial majority of scrubbed coal fired generating capacity in the Eastern United States.

Portfolio of sales contracts provide revenue visibility and stability. We believe our long-term coal sales contracts provide significant revenue visibility and will generate stable and consistent cash flows. As of March 31, 2014, we have secured coal sales commitments for approximately 20.5 million tons for fiscal year 2014, 15.4 million tons for fiscal year 2015 and 11.6 million tons for fiscal year 2016, respectively, of which approximately 18.8 million tons in fiscal year 2014, approximately 10.1 million tons in fiscal year 2015 and approximately 5.0 million tons in fiscal year 2016 are priced. Committed sales as a percentage of estimated production for the twelve months ending June 30, 2015 are 85%, 64% and 48% for calendar years 2014, 2015 and 2016, respectively.

Significant growth opportunities enabled by over $2.0 billion of capital investment. At full run rate production, including our longwall that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days, we estimate that our existing operations have total productive capacity of approximately 32.7 million tons per year. Additionally, our reserves are sufficient to support up to nine longwalls, with a portion of the existing surface and underground infrastructure available to be shared among our existing, and most of our future, longwalls. The potential future capacity of our operations if all nine longwalls are constructed would be 67.2 million tons per year. We have already made the significant investment in large scale surface and underground infrastructure, and we believe our growth from these complexes will have shorter lead time and lower costs than greenfield development, which should enable us to generate a higher return on incremental capital employed. Preliminary work has already begun on the third and fourth longwalls on the Sugar Camp reserve, which have been named Logan and Tanner, respectively. These longwall operations will be built as a separate mining complex. The initial development work includes preliminary engineering, permitting (IDNR Permit submitted November 2013) and initial capital expenditures for longwall equipment and certain property right of ways.

Large, contiguous, high quality reserve base supports long mine lives and minimizes maintenance capital expenditure. We control over 3 billion tons of coal reserves, which we believe makes us one of the largest reserve holders in the United States and ranks us 4th among public companies in the United States as of December 31, 2013. Almost all of our reserves are in three large, contiguous blocks of coal: two in central Illinois and one in southern Illinois, where the size of reserves and the geologic conditions are favorable for longwall mining. The contiguous nature of our reserves enables us to develop centrally located mining complexes with long mine lives, which means we do not have to continually develop new mines to replace mines with depleted reserves. As a result, we expect to reduce the amount of capital expenditures necessary to maintain our production levels, thus enabling us to translate more of our Adjusted EBITDA to free cash flow. Please see footnote 3 under “—Summary Historical Consolidated Financial and Other Information” for a US GAAP reconciliation of Adjusted EBITDA.

Broad domestic and export market access through a variety of transportation options allows us to maximize margins. We complement our low cost mining operations with competitive low cost transportation options to the domestic and international markets. Our mines are attractively positioned in close proximity to railroads and rivers and each of our mining complexes has access to two or more competing forms of transportation. We have direct and indirect access to five Class I rail lines. We have contractual access to a 25 million ton per year barge-loading river terminal on the Ohio River owned by an affiliate, an additional barge-loading river terminal on the Mississippi River and two export terminals in Louisiana. We have entered into agreements with railroads, barge carriers and terminals with terms up to 20 years. Transportation optionality allows us to negotiate competitive rates and control costs. The total cost of mining and transporting coal to our primary domestic markets in the Southeast and the Ohio River Valley compares favorably to Henry Hub natural gas forward prices on a dollars per million Btu basis as of December 31, 2013. Across all transportation options, we have contractual access to 11 million tons of current export terminal capacity in the Gulf of Mexico,

 

 

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including a terminal owned by an affiliate. Our affiliate has plans to increase this export capacity to 26 million tons per year. This broad market access enables us to maximize prices and margins realized for our coal sales. As a result, despite the recent decline in seaborne thermal coal benchmark prices, our low cost structure allows us to profitably deliver coal to the European market.

Best-in-class management capabilities. Chris Cline, our Principal Strategy Advisor, and senior operations personnel have, on average, more than 30 years of experience in the coal industry. They are hands-on operators and have substantial experience in designing and developing new mines, increasing productivity, reducing costs, building infrastructure, implementing marketing strategies and operating safe mines. In addition to their operating strengths, our senior executives have experience in identifying, acquiring, financing and integrating relevant businesses that we believe will enhance the value of our assets.

Strong relationship with our sponsor. One of our principal strengths is our relationship with our sponsor, Foresight Reserves, who will have a significant interest in our partnership through its ownership of a 85.9% limited partner interest in us as well as a 99.33% ownership interest in our general partner and incentive distribution rights. We have entered into a development agreement with Foresight Reserves that offers Foresight Reserves the right to develop additional longwalls on the Sugar Camp, Hillsboro and Macoupin reserve base. If Foresight Reserves accepts and develops the additional longwall mines, we have the option to purchase the developed mines at fair market value upon commencement of longwall production. We also have a strong relationship with the Cline Group, Foresight Reserves’ indirect parent, which has a well-established 30-year history in the development and operation of coal mining facilities. In addition, in September 2007, Foresight Reserves received an investment from an affiliate of Riverstone Holdings LLC (“Riverstone”). Riverstone is an energy and power-focused private investment firm founded in 2000 with approximately $27 billion of equity capital raised. As such, we believe that our relationship with our sponsor will provide us with growth opportunities as it will potentially acquire, develop and drop down qualifying assets to us to help drive our growth.

Our Strategy

Our business strategy is to steadily and sustainably increase cash distributions to our common unitholders by:

Operating mines with high productivity and industry-leading cost structure. We believe we are the lowest cost bituminous coal producer in the United States, based on publicly available information. We believe low operating costs are critical to maintain stable financial performance and sustain profitability and cash flow throughout business and commodity cycles.

Growing production and operating cash flows. We expect our coal production and cash flow to increase with the commencement of the second longwall mining system at Sugar Camp that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. We have a visible pipeline of additional organic growth projects to further develop our vast reserve base by incrementally adding longwall systems at our existing mining complexes and developing new mining complexes.

Minimizing maintenance capital expenditures. We have designed each of our mines to have at least 20 years of productive life from our initial mine development. This design reduces the amount of expected future capital expenditures necessary for surface infrastructure to maintain the productive capacity as the mines get older. Reducing maintenance capital expenditures (which are those cash expenditures made to maintain our long-term production capacity and net income) in the future should enable more of our Adjusted EBITDA to result in free cash flow.

Maintaining a stable revenue base. We currently have approximately 72.1 million tons of coal sales under contract for delivery through December 31, 2020. We intend to continue to expand our portfolio of long-term coal supply agreements as our production grows to maintain the stability of our operating cash flows and mitigate the effects of coal price volatility.

 

 

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Expanding the diversity of our sales portfolio. We believe that it is essential to have a diverse base of end-users for our coal including international coal consumers. Customer diversity enables us to manage concentration risks with a particular end-user or market and optimize sales to various market subsectors based on the most attractive margins on a net back basis at the mines. We have sold coal or are currently selling coal to 110 different customers and end-users in 19 states in the United States and 17 countries around the world and no single customer represented greater than 10% of our revenues for the year ended December 31, 2013.

Maintaining our transportation and logistics network. We believe that it is important for our coal to be low cost on a delivered basis to end-users. As a result, we have developed infrastructure to ensure that we have access to multiple low cost transportation options that provide wide market access to reach existing and new customers in the domestic and international markets.

Continuing to operate with industry-leading safety standards. Safety is our priority and it is incorporated in all aspects of our operations, including mine design, equipment selection and operating processes. We will continue to work with equipment manufacturers to make our mining equipment and mining process safer. We will continue to implement safety measures to maintain the high quality of our underground infrastructure, including using ventilation and roof control measures that exceed industry standards.

Coal Market Overview

Coal remains an in-demand, cost-competitive energy source. According to the EIA, total United States electricity generation is expected to grow by 14% from 2013 to 2025. Despite recent reductions in coal-fired electrical demand, coal is expected to retain the largest share of electrical power generation in the United States, representing an average 38% share of domestic electricity generation through 2025. Coal, particularly coal produced in the Illinois Basin, has historically been a low-cost, stable and reliable source of energy relative to alternative fuel sources. Conventional coal powered generation plants also have a lower levelized capital cost relative to alternative energy sources, such as nuclear, hydroelectric, wind and solar power.

Demand for Illinois Basin coal is growing in the United States. Many domestic utilities have installed or plan to install scrubbers. This increase in scrubbers is expanding the market for high sulfur coal from the Illinois Basin. According to Wood Mackenzie estimates, 215 GWs, or 70% of total coal-fired generation capacity in the United States, is estimated to be scrubbed in 2013. Wood Mackenzie expects scrubbed capacity to increase to 258 GWs, or approximately 100% of total capacity, by 2025. During the same period, Wood Mackenzie forecasts an increase in domestic Illinois Basin coal demand of more than 65 million tons, with much of the demand deriving from the South Atlantic and East North Central regions.

Expected long-term increases in international demand and the United States export market. While international coal market prices have declined recently, we believe that over the long-term, Pacific Basin demand for global seaborne thermal coal will continue to increase and create a shortfall in the Atlantic Basin supply as quantities of thermal coal from traditional European, Colombian and South African suppliers will shift to Asia over the decade. This shift, which was evident in 2011 and 2012, should continue to create opportunities for U.S. and South American producers to export to coal-fired plants in Europe and Asia in the future.

Developments in U.S. regional coal markets. Coal production in the Central Appalachian region of the United States has declined in recent years because of production challenges, reserve degradation and difficulties acquiring permits needed to conduct mining operations. In addition, underground mining operations have become subject to additional, more costly and stringent safety regulations, which have had the effect of increasing the operating costs of older mines with large areas to maintain.

 

 

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Risk Factors

An investment in our common units involves risks. Those risks are described under the caption “Risk Factors” beginning on page 22 and include the following:

 

    We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

 

    A further decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.

 

    We compete in a global coal market and could be negatively impacted by an increase in global coal supply as well as a decrease in global market demand.

 

    Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws, regulations or enforcement could materially increase our operating costs or limit our ability to produce and sell coal.

 

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

 

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, or initially to remove our general partner without its consent.

 

    Unitholders will experience immediate and substantial dilution of $19.35 per common unit.

 

    There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

 

    Our tax treatment depends on our status as a partnership for U.S. 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 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 could be substantially reduced.

 

    Our unitholders will be required to pay taxes on their share of income even if they do not receive any cash distributions from us.

Our Management

Upon consummation of this offering we will be managed and operated by the board of directors and executive officers of our general partner, Foresight Energy GP LLC, which is owned by Foresight Reserves and a member of management. Following this offering, 72.5% and 0.5% of our outstanding common units and all of our outstanding subordinated units and incentive distribution rights will be owned, directly or indirectly, by Foresight Reserves and a member of management, respectively. As a result of controlling our general partner, Foresight Reserves will have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. For more information about the executive officers and directors of our general partner, please read “Management.”

Following the consummation of this offering, neither our general partner nor Foresight Reserves will receive any management fee, but we will reimburse our general partner and its affiliates for all expenses they

 

 

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incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions.”

Our operations will be conducted through, and our operating assets will be owned by, our wholly-owned subsidiary, Foresight Energy LLC, and its subsidiaries.

The Cline Group, Foresight Reserves’ indirect parent, has well-established experience in the development and operation of coal mining facilities. Over the last 30 years, The Cline Group has acquired, permitted, developed or operated over 25 separate coal mining operations in Appalachia and the Illinois Basin. In September 2007, an affiliate of Riverstone invested in Foresight Reserves. Riverstone is an energy and power-focused private investment firm founded in 2000 with approximately $27 billion of equity capital raised.

Summary of Conflicts of Interest and Fiduciary Duties

Although our relationship with Foresight Reserves may provide significant benefits to us, it may also become a source of potential conflicts. For example, Foresight Reserves is not restricted from competing with us. In addition, the executive officers and certain of the directors of our general partner also serve as officers or directors of Foresight Reserves, and these officers and directors face conflicts of interest, including conflicts of interest regarding the allocation of their time between us and Foresight Reserves.

Our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to Foresight Reserves. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and Foresight Reserves and our general partner, on the other hand.

Our partnership agreement limits the liability of and replaces the fiduciary duties that would otherwise be owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or officers. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and the duties of our general partner and its directors and officers, please read “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

IPO Reorganization

In connection with the closing of this offering, the following transactions will occur:

 

    Foresight Reserves and a member of management will each contribute their membership interests in Foresight Energy LLC to us;

 

    we will issue to Foresight Reserves and a member of management, on a pro rata basis, an aggregate of 47,238,895 common units and 64,738,895 subordinated units, representing a combined 86.5% limited partner interest in us;

 

    we will issue to our general partner the incentive distribution rights, which entitle the holder to an increasing percentage, up to a maximum of 50% of the cash we distribute in excess of $0.5063 per unit per quarter, as described under “Cash Distribution Policy and Restrictions on Distributions”;

 

 

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    we will issue 17,500,000 common units to the public, representing a 13.5% limited partner interest in us, and will use the net proceeds from this offering as described under “Use of Proceeds”;

 

    to the extent the underwriters exercise their option to purchase 2,625,000 additional common units, we will issue such units to the public and distribute the net proceeds to Foresight Reserves and a member of management on a pro rata basis; and

 

    to the extent the underwriters do not exercise their option to purchase additional common units, we will issue those common units to Foresight Reserves and a member of management on a pro rata basis for no additional consideration.

Our Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or “JOBS Act.” For as long as we are an emerging growth company, unlike other public companies, we will not be required to:

 

    provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

 

    comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

 

    comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the Securities and Exchange Commission determines otherwise;

 

    provide certain disclosure regarding executive compensation required of larger public companies; or

 

    submit for unitholder approval golden parachute payments not previously approved.

We will cease to be an “emerging growth company” upon the earliest of:

 

    when we have $1.0 billion or more in annual revenues;

 

    when we have at least $700 million in market value of our common units held by non-affiliates;

 

    when we issue more than $1.0 billion of non-convertible debt over a three-year period; or

 

    the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

See “Risk Factors—Risks Inherent in an Investment in Us—Pursuant to the JOBS Act our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as we are an emerging growth company” and “Risk Factors—Risks Inherent in an Investment in Us—For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.”

 

 

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Pro Forma Corporate Structure

The following chart summarizes our corporate structure after giving effect to this offering and the use of proceeds therefrom and the IPO Reorganization:

 

     Percentage
Interest
 

Public Common Units

     13.5 %(1) 

Interests of Foresight Reserves and a member of management:

  

Common Units

     36.5 %(1) 

Subordinated Units

     50.0

Non-Economic General Partner Interest

     0.0 %(2) 

Incentive Distribution Rights

     —       (3) 
  

 

 

 
     100.0
  

 

 

 

 

(1) Assumes no exercise of the underwriters’ overallotment option and that we issue the common units subject to underwriters’ overallotment option to Foresight Reserves and a member of management on a pro rata basis.
(2) Our general partner owns a non-economic general partner interest in us. Please read “How We Make Distributions To Our Partners—General Partner Interest.”
(3) Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. See “How We Make Distributions To Our Partners—General Partner Interest—Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. Incentive distribution rights will be issued to Foresight Energy GP LLC, our general partner, which is owned by Foresight Reserves and a member of management.

 

 

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LOGO

 

(1) The list below details the names of our operating subsidiaries. Our operating subsidiaries rely exclusively on affiliated contractors for their operations which are consolidated as variable interest entities.

Williamson Energy, LLC

Hillsboro Energy LLC

Macoupin Energy LLC

Sugar Camp Energy, LLC

Foresight Coal Sales LLC

Oeneus LLC d/b/a Savatran LLC

Foresight Energy Services LLC

Foresight Energy Employee Services Corporation

Seneca Rebuild LLC

 

(2) The member of management refers to Michael J. Beyer, our President and Chief Executive Officer.

 

 

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Partnership Information

We are a Delaware limited partnership formed in January 2012. On April 15, 2014, we changed our name from “Foresight Energy Partners LP” to “Foresight Energy LP.” Our principal executive offices are located at 211 North Broadway, Suite 2600, Saint Louis, Missouri 63102. The telephone number of our principal offices is (314) 932-6160 and our website is www.foresight.com. We intend to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed or furnished to the SEC. The information on our website is not part of, and is not incorporated by reference into, this prospectus.

The Offering

 

Common units offered to the public

17,500,000 common units.

 

  20,125,000 common units if the underwriters exercise their option to purchase an additional 2,625,000 common units in full.

 

Units outstanding after this offering

64,738,895 common units and 64,738,895 subordinated units.

 

  If the underwriters do not exercise their option to purchase additional common units, we will issue 2,625,000 common units to Foresight Reserves and a member of management, pro rata upon the option’s expiration for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Foresight Reserves and a member of management, pro rata at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

 

Use of proceeds

We intend to use the net proceeds of this offering of approximately $323.3 million (after deducting the underwriting discounts, expenses and the structuring fee), or $372.3 million if the underwriters’ option to purchase additional units is exercised in full, to repay approximately $210.0 million of our Term Facility and to distribute the remaining net proceeds to Foresight Reserves and a member of management, pro rata. We will not retain any proceeds from this offering.

 

Distribution policy

We expect to make a minimum quarterly distribution in cash of $0.3375 ($1.3500 on an annualized basis) on each common unit and subordinated unit to the extent we have sufficient cash after the establishment of reserves and payment of fees and expenses. Our ability to make distributions at the minimum quarterly distribution rate is subject to various restrictions and other factors. Please see “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution” and “Risk Factors—Risks Related to Our Business—Restrictions in the agreements governing our indebtedness could limit our ability to make distributions to our unitholders.”

 

 

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  We will pay a pro rated distribution for the first quarter during which we are a publicly-traded partnership. Such distribution will cover the period from the closing date of this offering to and including June 30, 2014. We expect to pay this cash distribution before August 30, 2014.

 

  Our partnership agreement generally provides that we will distribute cash each quarter during the subordinated period in the following manner:

 

    first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.3375 plus any arrearages from prior quarters;

 

    second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.3375; and

 

    third, 100.0% to the holders of the common and subordinated units, pro rata, until each common and subordinated unit has received a distribution of $0.3881.

 

  If cash distributions to our unitholders exceed $0.3881 per common and subordinated unit in any quarter, our unitholders and the general partner (as holder of our incentive distribution rights) will receive distributions according to the following percentage allocations:

 

     Marginal Percentage
Interest in
Distributions
 

Total Quarterly Distribution

Target Amount

   Unitholders     General
Partner
 

above $0.3881 up to $0.4219

     85.0     15.0

above $0.4219 up to $0.5063

     75.0     25.0

above $0.5063

     50.0     50.0

 

  We refer to the additional increasing distributions to our general partner as “incentive distributions.” Please read “How We Make Distributions to Our Partners—General Partner Interest—Incentive Distribution Rights.”

 

  Pro forma cash available for distribution generated during the year ended December 31, 2013 and the twelve months ended March 31, 2014 were approximately $171.4 million and $182.5 million, respectively. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common and subordinated units to be outstanding immediately after this offering is approximately $174.8 million (or an average of approximately $43.7 million per quarter). As a result, for the year ended December 31, 2013 we would have generated available cash sufficient to pay 100% of the minimum quarterly distribution on our common and 96.1% of the minimum quarterly distribution on our subordinated units and, for the twelve months ended March 31, 2014, we would have generated available cash sufficient to pay 100% of the minimum quarterly distribution on both our common and subordinated units.

 

 

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  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient cash available to pay the minimum quarterly distribution of $0.3375 on all of our common and subordinated units for each quarter in the twelve months ending June 30, 2015. However, we do not have a legal or contractual obligation to pay quarterly distributions at the minimum quarterly distribution rate or at any other rate and there is no guarantee that we will pay distributions to our unitholders in any quarter. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

Foresight Reserves and a member of management will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $1.3500 (the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2017 and there are no outstanding arrearages on our common units.

 

  Notwithstanding the foregoing, the subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $2.0250 (150.0% of the minimum quarterly distribution on an annualized basis) on the outstanding common and subordinated units and we have earned 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 our common units.

 

  When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages.

 

General partner’s right to reset the target distribution levels

Our general partner, as the initial holder of our incentive distribution rights, will have the right, at any time when there are no subordinated units outstanding and we have made distribution at or above 150.0% of the minimum quarterly distribution for the prior four consecutive whole fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will

 

 

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be entitled to exercise this right. Following a reset election, the minimum quarterly distribution will be adjusted to equal the distribution for the quarter immediately preceding the reset, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the initial target distribution levels were above the minimum quarterly distribution.

 

  If the target distribution levels are reset, the holders of our incentive distribution rights will be entitled to receive common units. The number of common units to be issued will equal the number of common units that would have entitled the holders of our incentive distribution rights to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights in such quarter. Please read “How We Make Distributions To Our Partners—General Partner Interest—Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 23% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Foresight Reserves will own an aggregate of 85.9% of our outstanding units (or 83.9% of our outstanding units, if the underwriters exercise their option to purchase additional common units in full). 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. This will give Foresight Reserves the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units 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

 

 

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general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “The Partnership Agreement—Limited Call Right.”

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2016, you will be allocated, on a cumulative basis, an amount of U.S. federal taxable income for that period that will be less than 35% of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.3500 per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $0.4725 per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

 

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences.”

 

Exchange listing

We have applied to have our common units listed on the NYSE under the symbol “FELP.”

 

 

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Summary Historical Consolidated Financial and Other Information

The following table sets forth our summary historical consolidated financial and other data, at the dates and for the periods indicated. The summary historical consolidated statements of operations data for the years ended December 31, 2013, 2012 and 2011 and the summary historical consolidated balance sheet data as of December 31, 2013 and 2012 have been derived from Foresight Energy LLC’s audited consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated balance sheet data as of December 31, 2011 has been derived from Foresight Energy LLC’s audited consolidated balance sheet as of December 30, 2011, which is not included in this prospectus. The summary historical consolidated balance sheet data as of March 31, 2014 and the summary historical consolidated statements of operations data for the three months ended March 31, 2014 and 2013 have been derived from Foresight Energy LLC’s unaudited consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated balance sheet data as of March 31, 2013 have been derived from Foresight Energy LLC’s unaudited consolidated balance sheet as of March 31, 2013, which is not included in this prospectus. The unaudited consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of our management, include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of the information set forth herein. Operating results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014 or for any future period. The summary financial information presented below should be read in conjunction with the information presented under “Selected Historical Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes thereto appearing in this prospectus. The summary financial information for the year ended December 31, 2013 below does not give effect to the full year impact of the 2013 Reorganization, which occurred in August 2013.

 

    For the Years Ended December 31,     For the Three Months
Ended March 31,
 
    2013     2012     2011     2014     2013  
    (in thousands, except per ton sold data)  

Revenues

         

Coal sales

  $ 957,412      $ 845,886      $ 500,791      $ 242,723      $ 232,593   

Costs and expenses

         

Cost of coal sales (excluding depreciation, depletion and amortization)

    363,024        309,801        174,183        93,153        79,848   

Transportation

    197,839        171,679        98,394        59,436        49,614   

Depreciation, depletion and amortization

    161,216        124,552        70,411        35,258        37,199   

Accretion on asset retirement obligations

    1,527        1,368        1,705        405        382   

Selling, general and administrative

    32,291        41,528        38,894        9,038        9,006   

Other operating (income) expense, net(1)

    (280     (10,759     (791     (686     (424

Gain on cost derivatives

    (2,392     (534     (2,395     (15,401     (452
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    204,187        208,251        120,390        61,520        57,420   

Other (income) and expense:

         

Loss on early extinguishment of debt

    77,773        —          —          —          —     

Interest expense, net

    115,897        82,580        38,193        29,604        28,200   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    10,517        125,671        82,197        31,916        29,220   

Less: Net income (loss) attributable to non-controlling interests

    2,236        (160     104        613        75   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to controlling interests

  $ 8,281      $ 125,831      $ 82,093      $ 31,303      $ 29,145   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data

         

Net cash provided by operating activities

  $ 179,526      $ 209,691      $ 103,143      $ 28,423      $ 55,247   

Net cash used in investing activities

  $ (209,275   $ (207,039   $ (332,821   $ (65,160   $ (33,261

Net cash provided by (used in) financing activities

  $ 25,145      $ (26,525   $ 247,988      $ 38,698      $ (8,462

 

 

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    For the Years Ended December 31,     For the Three Months
Ended March 31,
 
    2013     2012     2011     2014     2013  
    (in thousands, except per ton sold data)  

Balance Sheet Data (at period end)

         

Cash and cash equivalents

  $ 23,284      $ 27,888      $ 51,761      $ 25,245      $ 41,412   

Property, plant, equipment and development, net

  $ 1,414,074      $ 1,401,285      $ 1,323,800      $ 1,440,892      $ 1,396,356   

Total assets

  $ 1,710,171      $ 1,695,288      $ 1,546,969      $ 1,782,576      $ 1,710,913   

Total long-term debt(2)

  $ 1,519,213      $ 1,061,949      $ 897,411      $ 1,560,812      $ 1,078,424   

Total members’ (deficit) equity

  $ (148,116   $ 280,103      $ 394,205      $ (118,492   $ 309,198   

Other Data

         

Adjusted EBITDA(3)

  $ 364,694      $ 338,607      $ 192,402      $ 96,570      $ 94,926   

Capital expenditures

  $ 210,726      $ 209,937      $ 336,020      $ 65,160      $ 34,247   

Tons produced(4)

    17,991        15,080        9,028        5,059        4,888   

Tons sold(4)

    18,589        14,403        8,773        4,706        4,275   

Average realized price per ton sold(5)

  $ 51.50      $ 58.73      $ 57.08      $ 51.58      $ 54.41   

Cash costs per ton sold(6)

  $ 19.53      $ 21.51      $ 19.85      $ 19.79      $ 18.68   

 

(1) For the year ended December 31, 2012, $10.0 million was recognized as other operating income for a legal settlement with a customer on a coal sales contract.
(2) Includes current portion of long-term debt. Total long-term debt does not include $143.5 million for the year ending December 31, 2011 and $193.4 million for the years ending December 31, 2013 and 2012 and the three months ended March 31, 2014 and 2013 of certain sale-leaseback financing obligations (including coal and surface leases) that are characterized as financing arrangements due to the involvement of certain of our affiliates in mining the reserves and utilizing the equipment related to the leases. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Certain Relationships and Related Party Transactions.”
(3) Adjusted EBITDA is defined as net income from continuing operations (as applicable) attributable to controlling interests before interest, taxes, depreciation, depletion, amortization and accretion. Adjusted EBITDA may also be adjusted for material nonrecurring and other items which may not reflect the trend of future results. Adjusted EBITDA is not a measure of performance defined in accordance with US 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 the US GAAP results and the reconciliation to US 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 as an indicator of our performance or as an alternative to net cash provided by operating activities as a measure of liquidity. The primary material limitations associated with the use of Adjusted EBITDA as compared to US GAAP results are (i) Adjusted EBITDA may not be comparable to similarly titled measures used by other companies in our industry, and (ii) Adjusted EBITDA excludes financial information that some consider important in evaluating our performance. We compensate for these limitations by providing disclosure of the differences between Adjusted EBITDA and US GAAP results, including providing a reconciliation of Adjusted EBITDA to US GAAP results, to enable investors to perform their own analysis of our operating results. Adjusted EBITDA presented herein for the years ended December 31, 2013, 2012 and 2011 and the three months ended March 31, 2013 does not give effect to the full year impact of the 2013 Reorganization. See “Business—2013 Reorganization.”

 

 

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The following table reconciles Adjusted EBITDA to the most directly comparable US GAAP measure, net income attributable to controlling interests:

 

     For the Years Ended
December 31,
     For the Three
Months Ended
March 31,
 
     2013      2012      2011      2014      2013  
     (in thousands, except per ton sold data)  

Net income attributable to controlling interests

   $ 8,281       $ 125,831       $ 82,093       $ 31,303       $ 29,145   

Write-off of deferred offering costs

     —           4,276         —           —           —     

Loss on early extinguishment of debt

     77,773         —           —           —           —     

Interest expense, net(a)

     115,897         82,580         38,193         29,604         28,200   

Depreciation, depletion and amortization

     161,216         124,552         70,411         35,258         37,199   

Accretion on asset retirement obligations

     1,527         1,368         1,705         405         382   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 364,694       $ 338,607       $ 192,402       $ 96,570       $ 94,926   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

  (a) Interest expense, net includes interest expense attributable to our sale-leaseback financing obligations (including coal and surface leases) that are characterized as financing transactions due to the continuing involvement of certain of our affiliates in mining related to the leases. For the years ended December 31, 2013, 2012 and 2011, interest expense related to these financing arrangements was $26.8 million, $26.0 million and $13.1 million, respectively. For the three months ended March 31, 2014 and 2013, interest expense related to these financing arrangements was $6.4 million and $6.6 million, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Certain Relationships and Related Party Transactions” and our consolidated historical financial statements, along with the notes thereto, included elsewhere in this prospectus.
(4) Tons produced and tons sold do not include mines in development. Revenues and costs from mines in development are capitalized as mine development in our balance sheets. The first longwall mines at Sugar Camp and Hillsboro came out of development in March 2012 and September 2012, respectively. Our second longwall mine at Sugar Camp began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. During the years ended December 31, 2013, 2012, and 2011, our development mines produced 0.8 million tons, 1.2 million tons and 1.4 million tons, respectively, and sold 0.8 million tons, 1.4 million tons and 0.9 million tons, respectively. During the three months ended March 31, 2014 and 2013, our development mines produced 0.2 million tons and 0.2 million tons, respectively, and sold 0.2 million tons and 0.2 million tons, respectively.
(5) Calculated as coal sales divided by tons sold. Average realized price per ton sold is not a US GAAP metric and it may not be comparable to similarly titled measures used by other companies in our industry.
(6) Calculated as cost of coal sales (excluding depreciation, depletion and amortization) divided by tons sold. Cash costs per ton sold is not a US GAAP metric and may not be comparable to similarly titled measures used by other companies in our industry.

 

 

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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 prospectus, before investing in our common units. We cannot assure you that any of the events discussed in this prospectus will or will not occur. 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, the common units.

Risks Related to Our Business

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution on our common and subordinated units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.3375 per unit, or $1.3500 per unit per year. The payment of the full minimum quarterly distribution on all of the common and subordinated units outstanding after the completion of this offering would require us to have cash available for distribution of approximately $43.7 million per quarter, or $174.8 million per year. Our estimated aggregate annual distribution amount for each of the forecast periods is based on the assumptions set forth in “Cash Distribution Policy and Restrictions on Distributions—Significant Forecast Assumptions.” If our assumptions prove to be inaccurate, our actual distribution for the twelve months ending June 30, 2015 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all during that period.

The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

    the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

 

    the market price of coal;

 

    the level of our operating costs, including reimbursement of expenses to our general partner;

 

    the supply of and demand for domestic and foreign coal;

 

    the timing of shipment of our contractual coal sales some of which are based on annual, not quarterly, minimum purchases;

 

    the impact of delays in the receipt of, failure to maintain, or revocation of, necessary governmental permits;

 

    the price and availability of other fuels;

 

    the impact of existing and future environmental and climate change regulations, including those impacting coal-fired power plants;

 

    the loss of, or significant reduction in, purchases by our largest customers;

 

    the cost of compliance with new environmental laws;

 

    the cost of power needed to run our mines;

 

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    worker stoppages or other labor difficulties;

 

    cancellation or renegotiation of contracts;

 

    prevailing economic and market conditions;

 

    difficulties in collecting our receivables because of credit or financial problems of customers;

 

    the effects of new or expanded health and safety regulations;

 

    air emission, wastewater discharge and other environmental standards for coal-fired power plants or coal mines and technologies developed to help meet these standards;

 

    domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry or the electric utility industry;

 

    the proximity to and capacity of transportation facilities;

 

    the availability of transportation infrastructure, including flooding and railroad derailments;

 

    competition from other coal suppliers;

 

    advances in power technologies;

 

    the efficiency of our mines;

 

    the pricing terms contained in our long-term contracts;

 

    cancellation or renegotiation of contracts;

 

    legislative, regulatory and judicial developments, including those related to the release of GHGs;

 

    delays in the receipt of, or failure to receive, or revocation of necessary government permits;

 

    inclement or hazardous weather conditions and natural disasters, such as heavy rain, high winds and flooding;

 

    transportation costs;

 

    the cost and availability of our contract miners;

 

    the availability of skilled employees;

 

    changes in tax laws; and

 

    force majeure events.

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

 

    the level and timing of capital expenditures we make;

 

    our debt service requirements and other liabilities;

 

    fluctuations in our working capital needs;

 

    our ability to borrow funds and access capital markets;

 

    restrictions contained in debt agreements to which we are a party;

 

    the amount of cash reserves established by our general partner; and

 

    the cost of acquisitions.

For a description of additional restrictions and factors that may affect our ability to pay cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

 

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We are a holding company with no independent operations or assets. Distributions to our unitholders are dependent on cash flow generated by our subsidiaries.

We are a holding company. All of our operations are conducted, and all of our assets are owned, by our direct and indirect subsidiaries. Consequently, our cash flow and our ability to meet our obligations or to pay cash distributions to our unitholders will depend upon the cash flows of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends or otherwise. The ability of our subsidiaries to make any payments to us will depend on their earnings, the terms of their indebtedness and legal restrictions applicable to them. In particular, the terms of certain indebtedness of our subsidiaries place significant limitations on the ability of our subsidiaries to pay dividends to us, and thus on our ability to pay distributions to our unitholders. See “Description of Indebtedness.” In the event that we do not receive distributions or dividends from our subsidiaries, we may be unable to make cash distributions to our unitholders.

The assumptions underlying our forecast of cash available for distribution included in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from our estimates.

Our forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” has been prepared by management and we have not received an opinion or report on it from any independent registered public accountants. The assumptions underlying our forecast of cash available for distribution are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from our estimates. If we do not achieve our forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The amount of cash we have available for distribution to our partners depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we report net income.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we report net losses for financial accounting purposes and may not pay cash distributions during periods when we report net income.

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

At March 31, 2014, our total long-term indebtedness (excluding our sale-leaseback financing obligations) was approximately $1,560.8 million, including our 2021 Senior Notes, Senior Secured Credit Facilities, Longwall Financing Arrangements, Interim Longwall Financing Arrangement and capital leases and we had available capacity of $217.4 million under our Revolving Credit Facility (including $2.6 million of outstanding letters of credit). Our substantial indebtedness could adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders:

 

    making it more difficult for us to satisfy our debt obligations;

 

    requiring a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;

 

    limiting our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;

 

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    limiting our flexibility in planning for, or reacting to, changes in our business or the industry in which we operate, placing us at a competitive disadvantage compared to our competitors who have less leverage and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploiting; and

 

    increasing our vulnerability to adverse economic, industry or competitive developments.

In addition, our Senior Secured Credit Facilities, 2021 Senior Notes, Longwall Financing Arrangements and Longwall Shield Facilities contain various covenants, including financial covenants and potential restrictions on dividends, liens, investments and other indebtedness, that limit our ability to conduct certain activities. Moreover, we are required to comply with certain financial covenants under our Senior Secured Credit Facilities, Longwall Financing Arrangements and our ability to make certain restricted payments under the indenture governing our 2021 Senior Notes and the Senior Secured Credit Facilities is tied to, among other things, and subject to specified exceptions, our fixed charge coverage ratio. See “Description of Indebtedness” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt and Sale-Leaseback Financing Arrangements” for a description of these financing arrangements.

Our ability to generate the significant amount of cash needed to service our debt and financial obligations and our ability to refinance all or a portion of our indebtedness or obtain additional financing depends on many factors beyond our control.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to make payments on our indebtedness. If we are unable to fund our debt service obligations, it will have an adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of our existing or future debt instruments may restrict us from adopting some of these alternatives. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

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. See “Business—Legal Proceedings and Liabilities.”

 

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Our Sugar Camp mine has received three violation notices from the Illinois Environmental Protection Agency (“IEPA”) regarding exceedances in high chloride effluent discharge and improper dilution of high chloride effluent and one violation notice from the IEPA regarding construction of an underground well without issuance of an appropriate permit.

We believe we are in compliance with all environmental regulatory requirements and are actively working in good faith with the IEPA to address these outstanding violations. Various alternatives for a long term mitigation plan exist and we are in active discussions with the IEPA to formulate the optimum solution. Presently, we have proposed a plan which will resolve all outstanding violations and provide long term water treatment and disposal capacity for the operations. This plan will require capital expenditures of approximately $20 million ($10.7 million of which has been invested through March 31, 2014 in facilities currently under construction), in addition to timely permit approvals from Illinois regulatory agencies. In the event this plan, or an acceptable alternative plan, is not satisfactorily implemented, these violations may result in the assessment of fines or penalties, or, a temporary or permanent suspension of the affected mining operations. Such a suspension 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. See “Business—Legal Proceedings and Liabilities.”

Our future success depends upon our ability to obtain necessary permits to mine all of our coal reserves.

In order to develop our economically recoverable coal reserves, we must obtain, maintain or renew various governmental permits. 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.

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, it 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 the ability to pay distributions to our unitholders.

A substantial or extended decline in coal prices or increase in the costs of mining or transporting coal could adversely affect our operating results and the value of our coal reserves.

Our operating results depend, in part, on the margins that we receive on sales of our coal. Our margins reflect the price we receive for our coal over our cost of producing and transporting our coal and are impacted by many factors, including:

 

    The market price for coal;

 

    the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

 

    The supply of, and demand for, domestic and foreign coal;

 

    Competition from other coal suppliers;

 

    Advances in power technologies;

 

    The efficiency of our mines;

 

    The pricing terms contained in our long-term contracts;

 

    Cancellation or renegotiation of contracts;

 

    Legislative, regulatory and judicial developments, including those related to the release of GHGs;

 

    The cost of using, and the availability of, other fuels, including the effects of technological developments;

 

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    Air emission, wastewater discharge and other environmental standards for coal-fired power plants and technologies developed to help meet these standards;

 

    Delays in the receipt of, or failure to receive, or revocation of necessary government permits;

 

    Inclement or hazardous weather conditions and natural disasters, such as heavy rain, high winds and flooding;

 

    The availability and cost or interruption of fuel, equipment and other supplies;

 

    Transportation costs;

 

    The availability of transportation infrastructure, including flooding and railroad derailments;

 

    The cost and availability of our contract miners;

 

    The availability of skilled employees; and

 

    Work stoppages or other labor difficulties.

Substantial or extended declines in the price that we receive for our coal or increases in the costs of mining or transporting 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 pay distributions to 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 and our ability to pay distributions to our unitholders.

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

The anticipated productive capacity at our longwall mining systems 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.

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

The anticipated productive capacity at our longwall mining systems may not be achieved. 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

 

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laws and regulations require substantial capital expenditures. While a significant amount of the 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 estimate that we or an affiliate of our sponsor will invest additional capital expenditures of between $240.0 million to $425.0 million in order to achieve full productive capacity at each incremental longwall mining system. If our affiliate invests such funds, we will have the right to purchase the new longwall mining system at its fair market value, which may exceed such estimated capital expenditures. 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 pay distributions to our unitholders may be materially adversely affected if we cannot make such capital expenditures.

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 and our ability to 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 and geologists. 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 recoverable coal reserves necessarily depend upon a number of variable 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:

 

    Geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experience in areas we currently mine;

 

    Future coal prices, operating costs and capital expenditures;

 

    Severance and excise taxes, royalties and development and reclamation costs;

 

    Future mining technology improvements;

 

    The effects of regulation by governmental agencies;

 

    Ability to obtain, maintain and renew all required permits;

 

    Employee health and safety needs; and

 

    Historical production from the area compared with production from other producing areas.

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 pay distributions to our unitholders.

 

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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.

Substantially all of our coal sales contracts are forward sales contracts. If the production costs underlying these contracts increase, our results of operations could be materially and adversely affected.

Substantially all 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. These production costs are subject to variability due to a number of factors, including increases in the cost of labor, supplies or other raw materials. To the extent our costs increase but pricing under these coal sales contracts remains fixed, 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.

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

According to the World Coal Association, in 2012 coal was used to generate approximately 41% of the world’s electricity needs. According to the EIA, in the United States, the domestic electricity generation industry accounts for approximately 95% of domestic thermal coal consumption. The amount of coal consumed by the electric generation industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations as well as 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. For example, the relatively recent low price of natural gas has resulted, in some instances, in domestic generators increasing natural gas consumption while decreasing coal consumption. For example, on June 2, 2014, the EPA proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this proposal, nationwide carbon dioxide emissions would be reduced by 30% from 2005 levels by 2030 with a flexible interim goal. The final rule is expected to be issued in June 2015, and the emission reductions are scheduled to commence in 2020. That said, expected procedural delays and anticipated litigation create uncertainty regarding if and when these new regulations will take effect. 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. A decrease in coal consumption by the electric 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 pay distributions to our unitholders.

 

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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 pay distributions to our unitholders.

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 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 pay distributions to our unitholders.

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, 2013, we derived approximately 10% of our total coal revenues from one customer and 8% from another 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 two 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 pay distributions to our unitholders may be materially adversely affected.

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.

Insurance against certain risks, including certain liabilities for environmental pollution or hazards, may not be generally available to us or other companies within the mining industry. 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

 

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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 pay distributions to our unitholders.

We have future mine closure and reclamation obligations the timing of and amount for 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 liabilities 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. At March 31, 2014, we have recorded total asset retirement obligations on our consolidated balance sheet of approximately $21.6 million. Our estimates for this future liability are subject to change based on new or amendments to existing applicable laws and regulation, the nature of ongoing operations and technological innovations. Although we accrue for future costs on our consolidated balance sheet, 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 costs 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.

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.

Substantially all 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

 

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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 pay distributions to our unitholders may be materially adversely affected.

Substantially all of our coal reserves are leased or subleased from affiliates and are subject to minimum royalty payments that are due regardless of whether coal is actually mined.

Substantially all of the reserves that our operating companies currently mine and will mine are leased or subleased from affiliates. Some leases have minimum production requirements. Failure to meet those requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself. See “Business—Coal Reserves” for details regarding these minimum royalties. If certain operations do not meet production goals then we could suffer shortage of cash due to the ongoing requirement to pay minimum royalty payments despite a lack of production and the associated sales revenue. As a result, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

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.

A substantial portion of our operations are in Illinois. If Illinois were 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 the ability to 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.

Each of our mining complexes has a contract mining agreement and coal processing agreement in place with an affiliated contractor (or “operator”) who operate each of our mines.

We operate each mine with a work force that is employed by a contractor that is not under common ownership by us, but is an “affiliate” of us due to our ability to exert control with respect to certain matters. We account for these operators as a “variable interest entity,” meaning that, among other things, each does not have sufficient equity to finance their activities without additional financial support and their respective equity holders do not have the ability to exert control over those activities which most significantly impact their economic performance. Rather, as described below, the Partnership has the ability to control certain long-term and other strategic decisions related to each of the operators. These contractor arrangements are entered into pursuant to a form agreement under which the operator furnishes labor. The Partnership’s operating subsidiaries have historically provided the parts, equipment, fuel and other materials and supplies necessary to operate each mine. The operator is required to use modern and efficient deep mining methods to mine, clean, load, deliver and transport the coal from the premises. Although the contract mining agreement permits the Partnership to require the contract miner to provide parts and equipment, the Partnership has not done so. Our contractors are required to comply with all applicable federal and state laws and regulations. We rely extensively on our operators to operate our mines professionally and therefore provide minimal day-to-day supervision. While we do not provide direct supervision to our contractors’ work forces, we monitor the performance of the contractors through certain of our executives and daily reports from the operators addressing key management performance indicators relating to safety, regulatory compliance, production and costs, each of which is compared to budgeted operating parameters. Further, we have periodic and unannounced on-site inspections to monitor performance. These

 

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members of our management, including Chris Cline, Michael Beyer and Christopher Moravec, have the ability to control long-term strategic and other significant decisions related to our operations and these operators. While the day-to-day operations of these operators are managed by another affiliate, Coal Field Construction Company, LLC, Messrs. Cline, Beyer and Moravec have significant influence over the strategic decisions and operations, such as equipment, strategy and target production levels.

We have had a relationship with the parent company that owns our contract mining operators since our inception, and this structure is similar to the one that Chris Cline has implemented at previous mine developments over the past 30 years. In addition, Chris Cline employs similar affiliated operators at two mining complexes in West Virginia and Ohio, as well as two transportation facilities that we utilize, Sitran and Convent Marine Terminal. These other operators employed by affiliates of Chris Cline have approximately 60 employees in total. While these other operations are separate from our four mining complexes, there is no assurance that our relationships and agreements with our operators may not be adversely impacted by these other relationships with affiliates of Chris Cline.

Our dependence on our operators to meet day-to-day health, safety, and environmental standards to which we, and they, are bound presents a risk to our unitholders. While we monitor our operators’ compliance with health, safety, or environmental standards, through reports, and as needed inspections, a contractor’s failure to meet health, safety or environmental standards or failure to comply with all applicable laws and regulations could have a material adverse effect on our results of operations, business, and financial condition, as well as our ability to pay distributions to unitholders.

Our dependence on our operators to meet day-to-day productive and quality standards to which we are bound through our coal sales agreements also presents a risk to our unitholders. While we monitor our operators’ performance towards meeting our production targets and quality standards, through reports, and as needed inspections, a contractor’s failure to produce the quality or quantity of coal required by our coal supply agreements could have a material adverse effect on our results of operations, business, and financial condition, as well as our ability to pay distributions to unitholders.

The Partnership may terminate a contract mining agreement with or without cause by giving 10 days’ notice, and the operator may terminate the agreement, with or without cause, by giving the Partnership 45 days’ notice. The Partnership may terminate a coal processing agreement, with or without cause, by giving 30 days’ notice, and the operator may terminate the agreement, with or without cause, by giving the Partnership 30 days’ notice. Mines and processing facilities require a qualified workforce, and a sudden contactor termination at one or more mines could have a material adverse effect on our results of operations, business, and financial condition, as well as our ability to pay distributions to unitholders, if the workforce could not be quickly replaced, by a new contractor, or otherwise.

While the coal mining agreements do not contain any provisions which inhibit or prohibit the Partnership from directly hiring the contractor workforce, there can be no assurance that the Partnership would be able to hire the work force previously employed by the operators, or find properly trained replacement contractors, or employees, quickly, on as favorable terms, or at all. Failure to rapidly attract and retain qualified replacement contractors, or qualified substitute employees of our own, could have a material adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to unitholders.

We are dependent upon certain of our affiliates for the mining, transloading and storage of our coal.

Each of our operators is accounted for as a “variable interest entity.” The Partnership has the ability to control certain long-term and other strategic decisions related to each of the operators. In light of this ability to control certain decisions, notwithstanding lack of common ownership, we have deemed each to be an “affiliate.” Each of these operators is a party to a contract mining agreement and a coal processing agreement that provide for contract mining, processing and loading services for us. We are also party to a transloading and storage agreement with one of our affiliates, Sitran, which provides for the unloading of coal, from each of Williamson,

 

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Sugar Camp, Hillsboro and Macoupin, from railcars into stockpiles at Sitran and for the loading of coal from such stockpiles into barges. If there are significant disruptions in any of these services, our business could be adversely affected. In addition, while our current contract with Sitran has an initial term of three years and automatically renews for successive one year periods, each party has the right to terminate the contract following the initial three year period. Each of our contracts with the operators is also for one year, renewable at the end of each year until otherwise terminated. There is no assurance that Sitran or our contract operators will renew their respective contracts, or that they will renew these contracts on similar terms or terms that are favorable to us. While we currently believe that these affiliate contracts are on terms that are fair and reasonable to us, we cannot assure you that any future modification, amendment or extension of these affiliate contracts will not provide for terms that are more favorable to our affiliates. Any non-renewal or renewal on terms not as favorable to us could have a material adverse impact on our results of operations, business and financial condition, as well as our ability to pay distributions to unitholders. See “Certain Relationships and Related Party Transactions—Transactions with Foresight Reserves and Foresight Energy GP LLC—2013 Reorganization” for a description of the 2013 Reorganization and this agreement and “Certain Relationships and Related Party Transactions—Transactions with our Contract Operators” for a discussion of these contract arrangements.

The Partnership’s operating subsidiaries are the sole customers of our contract mining operators, all of whom are affiliates and under common control with us and one another.

We rely exclusively on our contract mining operators to operate our mines pursuant to contract mining agreements which set forth the rights and obligations of both parties. In addition, these contract mining operators rely exclusively on Chris Cline and his affiliates for their work. These contract mining operators are all owned by the same parent company. If the Partnership were to terminate a contract mining agreement with one operator, there is no assurance that the parent of the contract mining operators would not choose to cause its other related entities to terminate their respective agreements with another or all of our mines. Although the Partnership would receive at least 30 days’ notice of termination under its contract mining and coal processing agreements, there can be no assurance that the Partnership would be able to hire the work force previously employed by the operators, or find properly trained replacement contractors, or employees, quickly. If the Partnership was unable to hire a work force as highly skilled, trained, or efficient, in a condensed time period, or within the geographical proximity of our mines, the Partnership could experience a material adverse effect on its results of operations, business and financial condition, as well as its ability to pay distributions to its unitholders. Moreover, the need to acquire a large work force of trained replacements, whether by contractor or otherwise, would tend to drive up labor costs and may, even if successful, cause a material adverse effect on the Partnership’s results of operations, business and financial condition, as well as its ability to pay distributions to its unitholders.

Our ability to operate our mines efficiently and profitably could be impaired if we lose, or fail to continue to attract, key qualified operators.

We manage our business with a key mining operator at each location. As our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified operators and contractors. We cannot be certain that we will be able to find and retain qualified operators or that they will be able to attract and retain qualified contractors in the future. Failure to retain or attract key operators could have a material adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

We operate our mines with a work force that is employed exclusively by our operators which are consolidated as “variable interest entities.” While none of our operators’ employees are members of unions, our work force may not remain non-union in the future.

None of our operators’ employees are represented under collective bargaining agreements. However, that work force may not remain non-union in the future, and proposed legislation, could, if enacted, make union organization more likely. If some or all of our current operations were to become unionized, it could adversely

 

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affect our productivity, increase our labor costs and increase the risk of work stoppages at our mining complexes. In addition, even if we remain non-union, our operations may still be adversely affected by work stoppages at our facilities or at unionized companies, particularly if union workers were to orchestrate boycotts against our contractors.

A shortage of skilled mining labor in the United States 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 pay distributions to our unitholders.

Failures of contractor-operated sources to fulfill the delivery terms of their contracts with us could adversely affect our operations and reduce our profitability.

Within our normal mining operations, we utilize contract operators for all of our coal production and transportation or transloading companies to deliver our coal. These contract operators are owned by affiliated entities that have engaged in business with us and our affiliates, including other operations for The Cline Group, for approximately 10 years. However, there is no assurance that our relationship will continue or continue on terms that are reasonably acceptable to us. In addition, these contract operators may determine that other operations within The Cline Group are better or more profitable for them and may lead to conflicts of interest. To the extent this were to occur, and we are unable to adequately replace their services, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders, could be materially adversely affected.

Our contract operators and contract transportation or transloading companies pass their costs to us. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon a variety of factors, including the reliability of the operator; the cost and financial viability of the contractor; our willingness to reimburse temporary cost increases experienced by the operator our ability to pass on operator cost increases to customers; our ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market; and other factors. If any of the contract operators or contract transportation companies with whom we contract go bankrupt or were otherwise unavailable to provide their services, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders could be materially affected.

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 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. As a public company, our future success also will depend on our ability to hire and retain management with public company experience. 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.

 

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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. For example, our contract operators have experienced two unrelated fatalities at one of our mining complexes. 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:

 

    Adverse geologic conditions including floor and roof conditions, variations in seam height, washouts and faults;

 

    Fire or explosions from methane, coal or coal dust or explosive materials;

 

    Industrial accidents;

 

    Seismic activities, ground failures, rock bursts or structural cave-ins or slides;

 

    Delays in the receipt of, or failure to receive, or revocation of necessary government permits;

 

    Changes in the manner of enforcement of existing laws and regulations;

 

    Changes in laws or regulations, including permitting requirements and the imposition of additional regulations, taxes or fees;

 

    Accidental or unexpected mine water inflows;

 

    Delays in moving our longwall equipment;

 

    Railroad derailments;

 

    Inclement or hazardous weather conditions and natural disasters, such as heavy rain, high winds and flooding;

 

    Environmental hazards;

 

    Interruption or loss of power, fuel, or parts;

 

    Increased or unexpected reclamation costs;

 

    Equipment availability, replacement or repair costs; and

 

    Mining and processing equipment failures and unexpected maintenance problems.

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, including those under the 2021 Senior Notes. 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. These risks, conditions or events have had, and can be expected in the future to have, a significant adverse impact on our business and operating results, as well as our ability to pay distributions to our unitholders.

 

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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. As a result, a substantial portion of coal production is from companies that have significantly greater resources than we do. 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 United States, 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 United States and international coal sales with numerous other coal producers located in the United States 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 pay distributions to our unitholders may be materially adversely affected.

The availability or reliability of current transportation facilities and our current dependence on a single rail carrier for coal transport from Williamson 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 pay distributions to our unitholders.

Currently, coal produced at Williamson is transported to our customers by a single rail carrier. If there are significant disruptions in the rail services provided by that carrier, then costs of transportation for our coal could increase substantially until we develop our alternative rail right-of-way. 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 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 and demurrage, 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 United States or abroad.

 

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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 United States. 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 United States inherently more expensive on a per ton-mile basis than shipments originating in the Western United States. Historically, high coal transportation rates and transportation constraints from the western coal producing areas into Eastern United States 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 United States 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 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 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, business and financial condition, as well as our ability to pay distributions to our unitholders.

Our revenues and operating profits could be negatively impacted if we are unable to extend existing agreements at favorable 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 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 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.

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

The current challenging economic environment, along with difficult and volatile conditions in the capital and credit markets, could materially adversely affect our financial position, results of operations or cash flows, and we are unsure whether these conditions will improve in the future.

The United States economy and global credit markets remain volatile. Worsening economic conditions or factors that negatively affect the economic health of the United States, Europe and Asia could reduce our revenues and thus adversely affect our results of operations. These markets have historically experienced

 

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disruptions, including, among other things, 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, unprecedented government support of financial institutions, high unemployment rates and increasing interest rates. Furthermore, if these developments continue or worsen it may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. We believe that further 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 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 United States 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 United States. 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 pay distributions to our unitholders.

The amount of our customers’ coal inventories may have a negative impact on our business.

Our customers may experience increases or decreases in their respective coal inventories from time to time. If we are unable to meet our customers’ increased demand due to decreases in their respective coal inventories, we may experience a loss of customers which could have a negative impact on our results of operations. In addition, if our customers experience an increase in coal inventory it is possible that their demand for additional coal from us may decrease which could have a negative impact on our results of operations.

Restrictions in the agreements governing our indebtedness could limit our ability to make distributions to our unitholders.

The indenture governing our 2021 Senior Notes, our Senior Secured Credit Facilities and the Longwall Financing Arrangements prohibit us from making distributions to unitholders if any default or event of default (as defined in the each agreement) exists. In addition, the indenture governing our 2021 Senior Notes and our Senior Secured Credit Facilities contain covenants limiting our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture for the 2021 Senior Notes and the Senior Secured Credit Facilities). If the fixed charge coverage ratio is greater than 1.75 to 1.00, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than or equal to 1.75 to 1.00, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $50.0 million basket that can be utilized in any quarter until total distributions since the date of the Qualified MLP IPO under this basket have on a cumulative basis reached $50.0 million plus certain other amounts referred to as “incremental funds” under the indenture and the Senior Secured Credit Facilities. The aggregate minimum quarterly distribution on our common units will be $21.8 million. Our 2021 Senior Notes mature in August 2021, our Term Facility matures in August 2020 and our Revolving Credit Facility matures in August 2018. If we do not exceed the fixed charge coverage ratio of 1.75 to 1.00 in respect of any quarter, we may be restricted in paying all or part of the minimum quarterly distribution to our unitholders. See “Description of Indebtedness.”

 

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Risks Related to Environmental, Health, Safety and Other Regulations

Our mining operations, including our transportation infrastructure, 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 regulation by federal, state and local authorities on matters such as:

 

    Permits and other licensing requirements;

 

    Surface subsidence from underground mining;

 

    Contract miner health and safety;

 

    Remediation of contaminated soil, surface water and groundwater;

 

    Air emissions;

 

    Water quality standards;

 

    The discharge of materials into the environment, including waste water;

 

    Storage, treatment and disposal of petroleum products and substances which are regarded as hazardous under applicable laws or which, if spilled, could reach waterways or wetlands;

 

    Storage and disposal of coal wastes including coal slurry under applicable laws;

 

    Protection of human health, plant life and wildlife, including endangered and threatened species;

 

    Reclamation and restoration of mining properties after mining is completed;

 

    Wetlands protection;

 

    Dam permitting; and

 

    The effects, if any, that mining has on groundwater quality and availability.

Because we engage in longwall mining at Williamson, Sugar Camp and Hillsboro, subsidence issues are particularly important to our operations. Failure to timely secure subsidence rights or any associated mitigation agreements, or any related regulatory action, 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.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand 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.

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 pay distributions to our unitholders.

 

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

Mining companies 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. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mine development or operations 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. 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 pay distributions to our unitholders. See “Business—Legal Proceedings and Liabilities.”

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. Such changes could have a material adverse effect on our financial condition and results of operations as well as our ability to pay distributions to our unitholders. See “Environmental and Other Regulatory Matters.”

Extensive governmental regulation pertaining to contractor 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 pervasive systems for protection of employee safety and health affecting any United States industry. Compliance with these requirements imposes significant costs on us and can result in reduced productivity.

The possibility exists that new health and safety legislation, regulations and orders may be adopted that may materially and adversely affect our mining operations. For example, in response to underground mine accidents of our competitors in the last decade, state and federal legislatures and regulatory authorities have increased scrutiny of mine safety matters and adopted more stringent requirements governing all forms of mining, including increased sanctions for and disclosure regarding non-compliance. In 2006, Congress enacted the Mine Improvement and New Emergency Response Act, or MINER Act, which imposed additional obligations on all coal operators, including, among other matters:

 

    The development of new emergency response plans;

 

    Ensuring the availability of mine rescue teams;

 

    Prompt notification to federal authorities of incidents that pose a reasonable risk of death; and

 

    Increased penalties for violations of the applicable federal laws and regulations.

Various states also have enacted new laws and regulations addressing many of these same subjects.

Federal and state health and safety authorities inspect our operations, and we anticipate a significant increase in the frequency and scope of these inspections. In recent years, federal authorities have also conducted

 

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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.

Our contractors must compensate employees for work-related injuries. If they do not make adequate provisions for their workers’ compensation liabilities, our future operating results could be harmed. Under the Black Lung Benefits Revenue Act of 1977 and 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 are current and former employees and contribute to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry before July 1973. The trust fund is funded by an excise tax on coal production of up to $1.10 per ton for underground coal sold domestically, not to exceed 4.4% of the gross sales price. For the three months ended March 31, 2014 and the year ended December 31, 2013, we recognized approximately $3.2 million and $13.6 million, respectively, of expense related to this tax. 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 effected. If new laws or regulations increase the number and award size of claims, it could materially and adversely harm our business. See “Environmental and Other Regulatory Matters.” In addition, the erosion through tort liability of the protections we are currently provided by workers’ 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 pay distributions to our unitholders.

Finally, as a public company, we will be subject to the Dodd-Frank Wall Street Reform and Consumer Protection Act provisions requiring disclosure in our periodic and other reports filed with the SEC regarding specified health and safety violations, orders and citations, related assessments and legal actions and mining-related fatalities.

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 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 pay distributions to our unitholders

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 current and historical 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

 

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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. For example, we are conducting remediation of refuse storage areas and groundwater contamination that occurred under a prior owner at our Macoupin mine pursuant to our agreement with Illinois regulators. See “Business—Legal Proceedings and Liabilities.” Liability may be strict, joint and several, so that we, regardless of whether we caused contamination, may be held responsible for more than our share of the contamination or other damages, or even for the entire share. These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to regulated materials or wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

New 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 increasing scrutiny from local, state, federal and international government bodies. Future regulation of GHGs could occur pursuant to United States 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, the EPA has issued regulations 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. The EPA also recently proposed new source performance standards for GHG emissions for new coal and oil-fired power plants, which could require partial carbon capture and sequestration. 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 are also being considered that place restrictions on carbon dioxide and other GHG emissions. On June 2, 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this proposal, nationwide carbon dioxide emissions would be reduced by 30% from 2005 levels by 2030 with a flexible interim goal. The final rule is expected to be issued in June 2015 and the emission reductions are scheduled to commence in 2020. The permitting of new coal-fired power plants has recently been contested by state regulators and environmental organizations over concerns related to GHG emissions from the new plants. 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.

A well-publicized failure in December 2008 of a coal ash slurry impoundment maintained by the Tennessee Valley Authority used to store ash from its coal burning power plants has led to new legislative and regulatory scrutiny and proposals that, if enacted, may impose significant obligations on us or our customers. The EPA has proposed regulations to address the management of coal ash that could result in treating coal ash as a hazardous waste, and doing so would increase regulatory obligations, costs and potential liability for handling coal ash for our utility customers and for us if we were to use coal ash for reclamation, or store or dispose of coal ash for any of our utility customers. We have used coal ash for reclamation at Macoupin.

 

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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 operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. 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 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. See “Environmental and Other Regulatory Matters.”

Risks Inherent in an Investment in Us

Foresight Reserves and a member of management will own our general partner and Foresight Reserves will control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including 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.

Following the offering, Foresight Reserves and Michael J. Beyer will own our general partner and Foresight Reserves will control our general partner and will 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 Foresight Reserves and Michael J. Beyer. Therefore, conflicts of interest may arise between Foresight Reserves or its affiliates, including our general partner, on the one hand, or any of us and 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 Foresight Reserves and Michael J. Beyer, in exercising certain rights under our partnership agreement;

 

    neither our partnership agreement nor any other agreement requires 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;

 

    Foresight Reserves and its 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;

 

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    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. Please read “How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Capital Expenditures” for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. 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. Please read “How We Make Distributions To Our Partners—Subordination Period”;

 

    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 subordination units or the incentive distribution rights;

 

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

 

    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates 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;

 

    our general partner may transfer its incentive distribution rights without unitholder approval; 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.

In addition, Foresight Reserves and its affiliates currently hold substantial interests in other companies in the energy and natural resource sectors. We may compete directly with entities in which Foresight Reserves or its affiliates have an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us. Please read “—Foresight Reserves and affiliates of our general partner may compete with us” and “Conflicts of Interest and Fiduciary Duties.”

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute quarterly at least $0.3375 per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. See “Cash Distribution Policy and Restrictions on Distributions.”

 

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In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of Foresight Reserves and Michael J. Beyer to the detriment of our common unitholders.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit 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.

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

Pursuant to our cash distribution policy, we expect that we will distribute a significant portion of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our 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.

In addition, because we intend to distribute a significant 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. See “Cash Distribution Policy and Restrictions on Distributions.”

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

Our partnership agreement does not limit 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 will have the following effects:

 

    our existing unitholders’ proportionate ownership interest in us will decrease;

 

    the amount of cash available for distribution on each unit may decrease;

 

    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

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    the ratio of taxable income to distributions may increase;

 

    the relative voting strength of each previously outstanding unit may be diminished; and

 

    the market price of the common units may decline.

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 will be dilutive to the existing unitholders.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

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. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

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:

 

    how to allocate business opportunities among us and its affiliates;

 

    whether to exercise its call right;

 

    how to exercise its voting rights with respect to the units it owns;

 

    whether to exercise its registration rights;

 

    whether to elect to reset target distribution levels; and

 

    whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

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 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:

 

    whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

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    our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was adverse to the interest of the partnership or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

 

    our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

 

  (1) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

 

  (2) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

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. Please read “Conflicts of Interest and Fiduciary Duties.”

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.

Foresight Reserves and affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. Foresight Reserves, as parent of our general partner, and the other affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

In addition, The Cline Group and Riverstone, each of whom is an affiliate of our general partner, currently hold substantial interests in other companies in the coal mining business, including other coal reserves in Illinois. For example, The Cline Group 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, these 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

 

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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 of us and our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

The holder or holders of our incentive distribution rights may elect to cause us to issue common units to it 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.

The holder or holders of a majority of our incentive distribution rights (initially our general partner) have 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 equal to 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 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. Please read “How We Make Distributions To Our Partners—General Partner Interest—Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will 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 will 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 Foresight Reserves, as a result of it owning our general partner, and not by our unitholders. Please read “Management—Management of Foresight Energy LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will 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 will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

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Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66  23% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the closing of this offering, Foresight Reserves will own an aggregate of 85.9% of our common and subordinated units (or 83.9% if the underwriters exercise their option to purchase additional common units in full). 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. This will provide Foresight Reserves the ability to prevent the removal of our general partner.

Unitholders will experience immediate and substantial dilution of $19.35 per common unit.

The assumed initial public offering price of $20.00 per common unit exceeds pro forma net tangible book value of $0.65 per common unit. Based on the assumed initial public offering price of $20.00 per common unit, unitholders will incur immediate and substantial dilution of $19.35 per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with US GAAP, and not their fair value. Please read “Dilution.”

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 sponsor may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If our sponsor transfers the incentive distribution rights to a third party but retains its ownership interest 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 sponsor had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by our sponsor could reduce the likelihood of our sponsor accepting offers made by us relating to assets owned by it, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

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 will have 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

 

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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, or the Exchange Act. Upon consummation of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, Foresight Reserves and Michael J. Beyer will own an aggregate of 85.9% and 0.6%, respectively, of our common and subordinated units, respectively. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), Foresight Reserves and Michael J. Beyer will own an aggregate of 85.9% and 0.6%, respectively, of our common units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Foresight Reserves or other large holders.

After this offering, we will have 129,477,790 common units and subordinated units outstanding, which includes the 17,500,000 common units we are selling in this offering that may be resold in the public market immediately. At the end of the subordination period, all of the subordinated units will convert into an equal number of common units. All of the units that are issued to Foresight Reserves and Michael J. Beyer will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by Foresight Reserves or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to Foresight Reserves. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by Foresight Reserves. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold. Please read “Units Eligible for Future Sale.”

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.

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.

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 will determine the expenses that are allocable to us. The reimbursement of expenses and payment

 

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of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for our common units will be determined by negotiations between us and the representative of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

    our quarterly distributions;

 

    our quarterly or annual earnings or those of other companies in our industry;

 

    announcements by us or our competitors of significant contracts or acquisitions;

 

    changes in accounting standards, policies, guidance, interpretations or principles;

 

    general economic conditions;

 

    volatility in the capital and credit markets;

 

    the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

    future sales of our common units; and

 

    the other factors described in these “Risk Factors.”

Unitholders may have liability to repay distributions.

Under certain circumstances, 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 will be 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.

We will be required by Section 404 of the Sarbanes-Oxley Act to evaluate the effectiveness of our internal controls. If we are unable to achieve and maintain effective internal controls, our operating results and financial condition could be harmed.

We will be required to comply with Section 404 of the Sarbanes-Oxley Act beginning with the year ending December 31, 2015 (except for the requirement for an auditor’s attestation report). Section 404 will require that we evaluate our internal control over financial reporting to enable management to report on, the effectiveness of

 

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those controls. Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements in accordance with US GAAP. While we have begun the lengthy process of evaluating our internal controls, we are in the early phases of our review and will not complete our review until well after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify control deficiencies of varying degrees of severity.

Management has taken steps to improve and continues to improve our internal control over financial reporting, including identification of the gaps in skills base and expertise of staff required in the finance group to operate as a publicly traded partnership and the implementation of a new ERP system. We will incur significant costs to remediate our material weaknesses and deficiencies and improve our internal controls if any are identified. To comply with these requirements, we may need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff. If we are unable to upgrade our systems and procedures in a timely and effective fashion, we may not be able to comply with our financial reporting requirements and other rules that apply to publicly traded partnerships.

As a publicly traded partnership, we will be required to report control deficiencies that constitute a material weakness in our internal control over financial reporting. If we fail to implement the requirements of Section 404 in a timely manner, if we are unable to conclude that our internal control over financial reporting are effective or if we fail to comply with our financial reporting requirements, investors may lose confidence in the accuracy and completeness of our financial reports. In addition, we or members of our management could be the subject of adverse publicity, investigations and sanctions by regulatory authorities, including the SEC and the NYSE, and be subject to unitholder lawsuits. Any of the above consequences could impose significant unanticipated costs on us.

Pursuant to the JOBS Act our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as we are an emerging growth company.

We are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” under the JOBS Act. We could be an emerging growth company for up to five years. See “Prospectus Summary—Our Emerging Growth Company Status.” Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2019. Once we are required to do so, and even if we conclude that our internal control over financial reporting is effective, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us. We expect, based on our 2014 forecasted sales, that our emerging growth status will expire on December 31, 2014; therefore, we will be subjected to the attestation provisions of Section 404 of the Sarbanes-Oxley Act of 2012 for our fiscal year ending December 31, 2015.

We may take advantage of these exemptions until we are no longer an emerging growth company. If we rely on these exemptions, investors may find our common units less attractive.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for emerging growth companies including certain requirements relating to accounting standards and compensation

 

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disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes Oxley Act of 2002, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise, (4) provide certain disclosure regarding executive compensation required of larger public companies, or (5) submit for unitholder approval golden parachute payments not previously approved. See “Prospectus Summary—Our Emerging Growth Company Status.”

If we avail ourselves of certain exemptions from various reporting requirements, our reduced disclosure may make it more difficult for investors and securities analysts to evaluate us and may result in less investor confidence. Additionally, if we rely on these exemptions, investors may find our common units less attractive.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us 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 will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Foresight Energy LP.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership, will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a publicly traded partnership.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the board of directors of our general partner or as executive officers.

We estimate that we will incur approximately $4.0 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

 

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Tax Risks to Common Unitholders

In addition to reading the following risk factors, please read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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 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 could 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. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the “IRS”) on this or any other tax matter affecting us. Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business, a change in current law or a change in the interpretation of 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, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. 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 the unitholders, likely causing a substantial reduction in the value of our common units. 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 on us.

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. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. Please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status.” We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such 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.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, 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 whether or not you receive cash

 

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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 that results from that income.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, Foresight Reserves, LP will own, directly and indirectly, more than 50% of the total interests in our capital and profits. Therefore, a transfer by Foresight Reserves, LP of all or a portion of its interests in us could result in a termination of us as a partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

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. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation and amortization deductions and certain other items. 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. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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 (or “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 will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their shares of our taxable income. 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 will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. 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

 

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some or all of the positions we take. Any contest by the IRS, and the outcome of any IRS contest, may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units 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 will adopt 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. Our counsel is unable to opine as to the validity of this approach. 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. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We will 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 our 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, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we will allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we will adopt. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

A unitholder whose 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) may be considered as having disposed of those common units. If so, he 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 consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he 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 the unitholder 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 the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are the subject of a securities loan. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

 

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Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2015 budget (the “Budget Proposal”) recommends elimination of certain key U.S. federal income tax preferences related to coal exploration and development. The Budget Proposal would (1) repeal expensing of exploration and development costs relating to coal, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal royalties, and (4) repeal the domestic manufacturing deduction for the production of coal. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate or defer certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

You will likely be subject to state and local taxes and return filing requirements in states 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 will initially own assets and conduct business in several states (including Illinois, Missouri and Indiana and through one of our affiliates in Louisiana), each of which currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You may 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 those 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. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

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USE OF PROCEEDS

We expect to receive approximately $323.3 million of net proceeds from the sale of common units by us in this offering, after deducting the underwriting discounts, the estimated expenses of this offering and the structuring fee, based on an assumed initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover page of the prospectus). We intend to use the net proceeds of this offering to repay approximately $210.0 million of our Term Facility due 2020 and to distribute the remaining net proceeds to Foresight Reserves and a member of management, pro rata, and will not retain any proceeds from this offering. Borrowings under our Term Facility bear interest at a rate equal to, at our option, (1) British Bankers’ Association (as published by Reuters) LIBOR plus 4.50% or (2) a base rate plus 3.50%, with a LIBOR floor of 1.00% for the Term Facility. See “Description of Indebtedness—Senior Secured Credit Facilities.”

If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $49.1 million (and the total net proceeds to us would be approximately $372.3 million), in each case assuming an initial public offering price per common unit of $20.00 (the mid-point of the price range set forth on the cover page of the prospectus). The net proceeds from any exercise of such option will also be paid as a special distribution to Foresight Reserves and a member of management, pro rata. If the underwriters do not exercise their option, we will issue and common units to Foresight Reserves and a member of management, respectively, upon the expiration of the option for no additional consideration.

A $1.00 increase (or decrease) in the assumed initial public offering price of $20.00 per common unit would increase (decrease) the net proceeds to us from this offering by approximately $16.4 million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and assuming the underwriters do not exercise their option to purchase additional common units, and after deducting the underwriting discounts and the structuring fee. The actual initial public offering price is subject to market conditions and negotiations between us and the underwriters.

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per common unit after the offering. On a pro forma basis as of March 31, 2014, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $83.9 million, or $0.65 per common unit. Purchasers of common units in this offering will experience immediate and substantial dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

 

Assumed initial public offering price per common unit

     $ 20.00   

Net tangible book value per common unit before the offering(1)

   ($ 1.13  

Increase in net tangible book value per common unit attributable to purchasers in the offering

     1.77     

Less: Pro forma net tangible book value per common unit after the offering(2)

       0.65   
    

 

 

 

Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)

     $ 19.35   
    

 

 

 

 

(1) Determined by dividing the number of units (47,238,895 common units and 64,738,895 subordinated units) to be issued to our general partner and its affiliates, including Foresight Reserves and a member of management, for the contribution of assets and liabilities to us) into the net tangible book value of the contributed assets and liabilities. The net tangible book value of the contributed assets and liabilities is equal to Foresight Energy LLC members’ (deficit) equity attributable to controlling interests of ($126.1 million) as of March 31, 2014.
(2) Determined by dividing the total number of units to be outstanding after the offering (64,738,895 common units and 64,738,895 subordinated units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.
(3) If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $20.35 and $18.35, respectively.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

 

     Units Acquired      Total Consideration  
     Number      Percent      Amount     Percent  
     (in thousands)  

General partner and affiliates(a)(b)(c)

     111,978         86.5%       $ (126,053     (63.9)%   

Purchasers in the offering

     17,500         13.5%       $ 323,250        163.9%   

Total

     129,478         100.0%       $ 197,197        100.00%   

 

(a) The units acquired by our general partner and its affiliates, including Foresight Reserves and Michael J. Beyer, consist of common units and subordinated units.
(b) The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with US GAAP. Book value of the consideration provided by our general partner and its affiliates, as of March 31, 2014, equals parent net investment, which was ($126.1) million and is not affected by this offering.
(c) Assumes the underwriters’ option to purchase additional common units is not exercised and that we issue the common units subject to underwriters’ overallotment option to Foresight Reserves and Michael J. Beyer on a pro rata basis.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of March 31, 2014:

 

    On an actual basis; and

 

    On an as adjusted basis, after giving effect to this offering (assuming the underwriters’ overallotment option to purchase additional common units is not exercised), the use of proceeds therefrom and the IPO Reorganization.

You should read this table together with “Use of Proceeds,” “Selected Historical Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Description of Indebtedness” and our consolidated historical financial statements, along with the notes thereto, included elsewhere in this prospectus.

 

     As of March 31,
2014
 
     Actual     As
Adjusted
 
     ($ in thousands)  

Cash and cash equivalents(1)

   $ 25,245      $ 25,245   
  

 

 

   

 

 

 

Long-term debt(2)(3):

    

Senior Secured Credit Facilities:

    

Revolving Credit Facility(3)

   $ 280,000      $ 280,000   

Term Facility(5)

     443,638        233,638   

7.875% Senior Notes due 2021(6)

     595,897        595,897   

5.780% Longwall Financing Arrangement

     72,833        72,833   

5.555% Longwall Financing Arrangement

     67,031        67,031   

Interim Longwall Financing Arrangement(4)

     61,335        61,335   

Capital Lease Obligations—Longwall Shield Facility

     40,078        40,078   
  

 

 

   

 

 

 

Total debt

     1,560,812        1,350,812   
  

 

 

   

 

 

 

Partners’ capital:

    

Limited partners:

    

Common unitholders—public(7)

       323,250   

Common unitholders—Foresight Reserves and a member of management(8)(9)

       (100,952

Subordinated unitholders—Foresight Reserves and a member of management(8)(9)

       (138,351

General partner

       —     

Non-controlling interests

       7,561   

Total Foresight Energy LP partners’ capital

       91,508   

Members’ (deficit) equity:

    

Controlling interests

     (126,053  

Non-controlling interests

     7,561     
  

 

 

   

Total members’ (deficit) equity

     (118,492  
  

 

 

   

 

 

 

Total Capitalization

   $ 1,442,320      $ 1,442,320   
  

 

 

   

 

 

 

 

(1) As of April 30, 2014, cash and cash equivalents were $4.1 million, which gives effect to amounts used to repay portions of our Revolving Credit Facility. See footnote 3 below.

 

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(2) Includes current portion of long-term debt. Total debt does not include $193.4 million of certain sale-leaseback financing obligations (including coal and surface leases) as of March 31, 2014 that are characterized as financing transactions due to the continuing involvement of certain of our affiliates in mining related to the leases. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Certain Relationships and Related Party Transactions.”
(3) See “Description of Indebtedness” for a complete description of this indebtedness. As of April 30, 2014, the outstanding balance under our Revolving Credit Facility was $243.5 million, which gives effect to amounts repaid subsequent to March 31, 2014, but does not give effect to additional borrowings under our Revolving Credit Facility to repay the Interim Longwall Financing Arrangement described in footnote 4 below. In addition, at April 30, 2014, we had unused capacity of $253.9 million under our Revolving Credit Facility (including $2.6 million of letters of credit).
(4) Prior to the consummation of this offering, we repaid the amounts due under this arrangement with borrowings under our Revolving Credit Facility. See “Description of Indebtedness—Interim Longwall Financing Arrangement.”
(5) Includes unamortized debt discount of $4.1 million. The As Adjusted amount gives effect to the anticipated use of approximately $210.0 million of the proceeds from this offering to repay amounts outstanding under the Term Facility. See “Use of Proceeds.”
(6) Includes unamortized debt discount of $4.1 million.
(7) Calculated based on the gross proceeds from the offering, net of the estimated underwriters discount and structuring fees at the midpoint of the range set forth on the cover of this prospectus and the estimated expenses of this offering.
(8) A member of management refers to Michael J. Beyer, our President and Chief Executive Officer.
(9) Calculated as the ownership percentage of common and subordinated partnership equity held by Foresight Reserves and a member of management after giving effect to this offering, multiplied by members’ deficit attributable to controlling interests, at March 31, 2014, less the special distribution being made to Foresight Reserves and a member of management (pro rata for the percentage interest of common and subordinated units owned by Foresight Reserves and such member of management). The calculation of the “As Adjusted” partners’ capital attributable to Foresight Reserves’ and a member of management’s common and subordinated units is as follows:

 

As adjusted, common unitholders—Foresight

Reserves and a member of management

         (in thousands)  

Members’ deficit attributable to controlling interests as of March 31, 2014

     $ (126,053

Percentage of Foresight Reserves and a member of management’s common unit ownership as a percentage of total units retained after the offering

     x        42.2
    

 

 

 
     $ (53,177

Less: Special distribution ($(113,250) multiplied by 42.2%)

     $ (47,776
    

 

 

 

As adjusted, common unitholders—Foresight Reserves and a member of management

     $ (100,952
    

 

 

 

As adjusted, subordinated unitholders—Foresight

Reserves and a member of management

         (in thousands)  

Members’ deficit attributable to controlling interests as of March 31, 2014

     $ (126,053

Percentage of Foresight Reserves and a member of management’s subordinated unit ownership as a percentage of total units retained after the offering

     x        57.8
    

 

 

 
     $ (72,876

Less: Special distribution ($(113,250) multiplied by 57.8%)

     $ (65,474
    

 

 

 

As adjusted, subordinated unitholders—Foresight Reserves and a member of management

     $ (138,351
    

 

 

 

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. In addition, you should read “Special Note Regarding Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma combined results of operations, you should refer to the audited historical consolidated financial statements as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 and the unaudited historical condensed consolidated financial statements as of March 31, 2014 and 2013 and for the three months ended March 31, 2014 and 2013, respectively, included elsewhere in this prospectus.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.3375 per unit ($1.3500 per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. Our general partner has not established any cash reserves, and does not have any specific types of expenses for which it intends to establish reserves. We expect our general partner may establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. The board of directors of our general partner will monitor the execution of our business strategy including sales, profitability, and cash reserves. The board of directors of our general partner will determine the amount of our quarterly distributions and may maintain, increase or decrease our distribution policy at any time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

    Our cash distribution policy will be subject to restrictions on distributions under our Senior Secured Credit Facilities and the indenture governing our 2021 Senior Notes, which contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Description of Indebtedness.” Should we be unable to satisfy these restrictions or if we are otherwise in default under our Senior Secured Credit Facilities or the indenture governing our 2021 Senior Notes, we will be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

 

   

Subject to certain exceptions, the indenture governing the 2021 Senior Notes, the Senior Secured Credit Facilities and the Longwall Financing Arrangements as well as future debt agreements, will place restrictions on our ability to pay cash distributions. Specifically, the indenture governing our 2021 Senior Notes, the Senior Secured Credit Facilities and the Longwall Financing Arrangements each prohibit us from making distributions if a default or event of default has occurred and is

 

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continuing and each contain financial covenants that limit our ability to make distributions if our fixed charge coverage ratio is below a specified level. Should we be unable to satisfy these restrictions under the indenture governing our 2021 Senior Notes, the Senior Secured Credit Facilities and the Longwall Facilities or if we are otherwise in default under the indenture, the Senior Secured Credit Facilities, or the Longwall Facilities we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. See “Description of Indebtedness.”

 

    Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.

 

    We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur on our behalf. 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. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay distributions to our unitholders.

 

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

 

    Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or selling, general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

 

    If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read “How We Make Distributions to Our Partners—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” We do not anticipate that we will make any distributions from capital surplus.

 

    Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

Our Ability to Grow May Be Dependent on Our Ability to Access External Expansion Capital

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, our future growth may be slower than our historical growth. We expect that we will rely primarily upon external financing sources, including bank borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy could significantly impair our ability to grow.

 

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Our Minimum Quarterly Distribution

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.3375 per unit for each whole quarter, or $1.3500 per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash available for distribution of approximately $43.7 million per quarter, or $174.8 million per year. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the cash available for distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period:

 

            Distributions(1)  
     Number of Units      One Quarter      Annualized  

Common units

     64,738,895       $ 21,849,377       $ 87,397,508   

Subordinated units

     64,738,895         21,849,377         87,397,508   
  

 

 

    

 

 

    

 

 

 

Total

     129,477,790       $ 43,698,754       $ 174,795,017   
  

 

 

    

 

 

    

 

 

 

 

(1) Our general partner will initially hold the incentive distribution rights, which entitle the holder thereof to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $0.3881 per unit per quarter.

We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month, starting August 15, 2014. We will adjust the quarterly distribution for the period after the closing of this offering through June 30, 2014 based on the actual length of the period.

Subordinated Units

Foresight Reserves and a member of management will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

To the extent we do not pay the minimum quarterly distribution from operating surplus on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “How We Make Distributions To Our Partners—Subordination Period.”

 

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In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $0.3375 per common and subordinated unit each quarter for the twelve months ending June 30, 2015. In those sections we present the following two tables:

 

    “Unaudited Pro Forma Cash Available for Distribution,” in which we present our estimate of the amount of cash we would have had available for distribution for the year ended December 31, 2013 and for the twelve month period ended March 31, 2014, based on our historical financial statements that are included in this prospectus, as adjusted to reflect incremental general and administrative expenses we expect we will incur as a publicly-traded partnership.

 

    “Estimated Cash Available for Distribution,” in which we demonstrate our anticipated ability to generate the cash available for distribution necessary for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2015.

Unaudited Pro Forma Cash Available for Distribution

The following table illustrates, on a pro forma basis for the year ended December 31, 2013 and twelve months ended March 31, 2014, cash available to pay distributions assuming that the IPO Reorganization, the consummation of this offering and the application of proceeds therefrom had occurred as of January 1, 2013, but does not give effect to the full year impact of the 2013 Reorganization or the 2013 Refinancing.

If we had completed the transactions contemplated in this prospectus on January 1, 2013, our unaudited pro forma cash available for distribution for the fiscal year ended December 31, 2013 and the twelve months ended March 31, 2014 would have been approximately $171.4 million and $182.5 million, respectively. For the fiscal year ended December 31, 2013, this amount would have enabled us to make an annualized distribution of 100% of the minimum quarterly distribution on our common units, but only approximately 96.1% of the minimum quarterly distribution on our subordinated units. For the twelve months ended March 31, 2014, this amount would have enabled us to make an annualized distribution of 100% of the minimum quarterly distribution on both our common and subordinated units.

Unaudited pro forma cash available for distribution includes incremental general and administrative expenses that we expect we will incur as a publicly-traded partnership, including costs associated with SEC and Sarbanes-Oxley reporting requirements, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

Cash available for distribution is a cash accounting concept, while our combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

 

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Foresight Energy LP

Unaudited Pro Forma Cash Available for Distribution

 

     Year Ended
December 31, 2013
    Twelve Months Ended
March 31, 2014
 
    

($ and tons in thousands,

except average realized

price per ton sold)

 

Operating Data:

    

Coal produced in tons

     17,991        18,162   

Decrease (increase) to coal inventory in tons

     598        813   

Coal purchased in tons

     —          45   
  

 

 

   

 

 

 

Coal sales in tons

     18,589        19,020   
  

 

 

   

 

 

 

Average realized price per ton sold

   $ 51.50      $ 50.87   
  

 

 

   

 

 

 

Financial Data:

    
    

Coal sales

   $ 957,412      $ 967,542   
  

 

 

   

 

 

 

Costs and expenses:

    

Cost of coal sales (excluding depreciation, depletion and amortization)

   $ 363,024      $ 376,329   

Transportation expense

     197,839        207,661   

Depreciation, depletion and amortization

     161,216        159,275   

Accretion on asset retirement obligations

     1,527        1,550   

Selling, general and administrative

     32,291        32,323   

Other operating (income) expense, net

     (280     (542

Gain on coal derivatives

     (2,392     (17,341
  

 

 

   

 

 

 

Total costs and expenses

   $ 753,225      $ 759,255   
  

 

 

   

 

 

 

Operating income

   $ 204,187      $ 208,287   

Interest and other income (expense):

    

Interest expense, net

   $ 115,897      $ 117,301   

Loss on early extinguishment of debt

     77,773        77,773   
  

 

 

   

 

 

 

Net income

   $ 10,517      $ 13,213   

Less: net income attributable to noncontrolling interests

     2,236        2,774   
  

 

 

   

 

 

 

Net income attributable to controlling interests

   $ 8,281      $ 10,439   
  

 

 

   

 

 

 

 

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     Year Ended
December 31, 2013
    Twelve Months Ended
March 31, 2014
 
    

($ in thousands, except

distributions per unit)

 

Net income attributable to controlling interests

   $ 8,281      $ 10,439   

Plus:

    

Loss on early extinguishment of debt

   $ 77,773      $ 77,773   

Depreciation, depletion and amortization

     161,216        159,275   

Accretion on asset retirement obligations

     1,527        1,550   

Interest expense, net

     115,897        117,301   
  

 

 

   

 

 

 

Adjusted EBITDA(1)

   $ 364,694      $ 366,338   
  

 

 

   

 

 

 

Less:

    

Incremental selling, general and administrative expense(2)

   $ 4,000      $ 4,000   

Cash interest expense(3)

     112,921        108,430   

Maintenance capital expenditures

     76,402        71,406   

Expansion capital expenditures

     134,324        170,233   
  

 

 

   

 

 

 

Plus:

    

Borrowings or cash on hand for expansion capital expenditures(4)

   $ 134,324      $ 170,233   
  

 

 

   

 

 

 

Cash available for distribution

   $ 171,371      $ 182,502   
  

 

 

   

 

 

 

Minimum quarterly distribution per unit (annualized)

   $ 1.3500      $ 1.3500   

Distributions (annualized):

    

Distributions to common unitholders

   $ 87,398      $ 87,398   

Distributions to subordinated units

   $ 87,398      $ 87,398   

Total distributions

   $ 174,795      $ 174,795   
  

 

 

   

 

 

 

Excess (shortfall)

   $ (3,424   $ 7,707   
  

 

 

   

 

 

 

Interest Coverage Ratio(3)(5)

     3.19x        3.34x   

Minimum Interest Coverage Ratio

     2.00x        2.00x   

Net Senior Secured Leverage Ratio(3)(5)

     2.13x        2.24x   

Maximum Net Senior Secured Leverage Ratio

     3.50x        3.50x   

 

(1) Please read Note 3 to “Selected Historical Financial Information.”
(2) Reflects incremental selling, general and administrative expenses that we expect to incur as a publically traded partnership.
(3) For the year ended December 31, 2013, includes $31.6 million from the Interim Longwall Financing Arrangement and a $79.4 million pro forma adjustment for borrowings under our Revolving Credit Facility. For the twelve months ended March 31, 2014, includes $61.3 million from the Interim Longwall Financing Arrangement and a $83.7 million pro forma adjustment for borrowings under our Revolving Credit Facility. Prior to the consummation of this offering, we repaid the amounts due under the Interim Longwall Financing Arrangement with borrowings under our Revolving Credit Facility, which is not reflected herein. See “Description of Indebtedness—Interim Longwall Financing Arrangement.”
(4) For the year ended December 31, 2013, includes $23.3 million in cash and a $79.4 million pro forma adjustment for borrowings under our Revolving Credit Facility. For the twelve months ended March 31, 2014, includes $25.2 million in cash and an $83.7 million pro forma adjustment for borrowings under our Revolving Credit Facility.
(5) Our Revolving Credit Facility requires us to maintain, as of the last day of each fiscal quarter, a consolidated interest coverage ratio (the ratio of our consolidated adjusted EBITDA to our consolidated cash interest charges and measured for the preceding four quarters, in each case, as defined in the credit agreement) of not less than 2.0 to 1.0 for the fourth quarter 2013 and quarters ending thereafter.

 

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Our Revolving Credit Facility also requires us to maintain, as of the last day of any fiscal quarter, a senior secured leverage ratio (the ratio of consolidated funded indebtedness that is secured by a lien on the collateral (other than any lien that is subordinated to the liens securing the obligations thereunder) less the sum of all unrestricted cash, cash equivalents and short-term marketable debt securities to consolidated adjusted EBITDA for the preceding four quarters, in each case, as defined in the credit agreement). Each of these terms has a specific meaning set forth in the Revolving Credit Facility. The maximum net senior secured leverage ratio allowed under the Revolving Credit Facility is as follows:

 

Fiscal Quarter Ending   

Maximum Net

Senior Secured Leverage Ratio

Fourth Quarter 2013

   3.50 to 1.00

First Quarter 2014

   3.50 to 1.00

Second Quarter 2014

   3.25 to 1.00

Third Quarter 2014

   3.00 to 1.00

Fourth Quarter 2014 and thereafter

   2.75 to 1.00

Each of our Senior Secured Credit Facilities and the indenture governing the 2021 Senior Notes restricts our ability to make cash distributions to our unitholders in the event of default. See “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy” above. For purposes of calculating these ratios, we have subtracted $4.0 million related to incremental selling, general and administrative expenses from Adjusted EBITDA for both the year ended December 31, 2013 and the twelve months ended March 31, 2014. See footnote (2) to this table above.

Estimated Cash Available for Distribution

The following table sets forth our calculation of forecasted cash available for distribution to our unitholders and general partner for the twelve months ending June 30, 2015. We forecast that our cash available for distribution generated during the twelve months ending June 30, 2015 will be approximately $227.2 million. This amount in the aggregate would be sufficient to pay the minimum quarterly distribution of $0.3375 per unit on all of our common and subordinated units for each quarter during this period. Since our revenue and cash available for distribution will likely fluctuate over time as a result of changes in coal prices as well as other factors, the board of directors of our general partner expects to reserve all or a portion of any cash generated in excess of the amount sufficient to pay the full minimum quarterly distribution on all units, as a whole, to allow us to maintain and to gradually increase our quarterly cash distributions.

We are providing the financial forecast to supplement our historical consolidated financial statements in support of our belief that we will have sufficient cash available to allow us to pay distributions on all of our common and subordinated units for each quarter in the twelve months ending June 30, 2015 at the minimum quarterly distribution rate. Please read “—Significant Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” for information as to the accounting policies we have followed for the financial forecast.

Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2015. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay distributions on our common and subordinated units at the minimum quarterly distribution rate of $0.3375 per unit each quarter (or $1.3500 per unit on an annualized basis) or any other rate. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in “Risk Factors.” Accordingly, there can be no assurance that the forecast is indicative of

 

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our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.

We do not, as a matter of course, make public forecasts as to future sales, earnings or other results. However, we have prepared the following forecast to present the forecasted cash available for distribution to our unitholders and general partner during the forecasted period. The accompanying forecast was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not necessarily indicative of future results.

Neither our independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the forecast contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the forecast. We do not undertake to release publicly after this offering any revisions or updates to the financial forecast or the assumptions on which our forecasted results of operations are based.

 

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Foresight Energy LP

Forecasted Cash Available for Distribution

 

    Quarter Ending
September 30,
2014
    Quarter Ending
December 31,
2014
    Quarter Ending
March 31,
2015
    Quarter Ending
June 30,
2015
    Twelve Months
Ending
June 30,
2015
 
    ($ and tons in thousands, except weighted average coal sales price per ton)  

Operating Data:

         

Coal produced in tons

    5,335        6,066        6,201        6,471        24,073   

Decrease (increase) to coal inventory in tons

    949        (252     (39     (39     619   

Coal purchased in tons

    —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Coal sales in tons

    6,285        5,814        6,162        6,432        24,692   

Coal sales in tons—committed

    5,932        5,267        4,069        4,094        19,362   

Weighted average coal sales price per ton—committed

  $ 52.14      $ 53.05      $ 53.44      $ 53.58      $ 52.97   

Coal sales in tons—uncommitted

    352        547        2,093        2,338        5,330   

Weighted average coal sales price per ton—uncommitted

  $ 43.65      $ 40.92      $ 46.47      $ 47.50      $ 46.17   

Financial Data:

         

Coal sales—committed

  $ 309,298      $ 279,443      $ 217,444      $ 219,361      $ 1,025,545   

Coal sales—uncommitted

    15,384        22,386        97,267        111,051        246,089   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 324,682      $ 301,829      $ 314,710      $ 330,412      $ 1,271,633   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

         

Cost of coal sales (excluding depreciation, depletion and amortization)

  $ 133,703      $ 124,883      $ 135,364      $ 140,919      $ 534,868   

Transportation expense

    68,861        62,956        74,000        77,409        283,226   

Depreciation, depletion and amortization

    44,300        44,300        44,300        44,300        177,200   

Accretion on asset retirement obligations

    319        319        319        319        1,276   

Selling, general and administrative

    10,000        10,000        10,300        10,300        40,600   

Other operating income (expense), net

    —          —          —          —          —     

Gain (loss) on commodity contracts

    —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

  $ 257,182      $ 242,458      $ 264,283      $ 273,247      $ 1,037,171   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

  $ 67,500      $ 59,371      $ 50,427      $ 57,165      $ 234,463   

Interest and other income (expense):

         

Interest expense

  $ 29,876      $ 29,611      $ 29,455      $ 29,323      $ 118,265   

Interest income

    —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 37,623      $ 29,759      $ 20,973      $ 27,842      $ 116,198   

Less: net income attributable to noncontrolling interests

    —          —          —          —          —     

Net income attributable to controlling interests

  $ 37,623      $ 29,759      $ 20,973      $ 27,842      $ 116,198   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    Quarter Ending
September 30,
2014
    Quarter Ending
December 31,
2014
    Quarter Ending
March 31,
2015
    Quarter Ending
June 30,
2015
    Twelve Months
Ending June 30,
2015
 
    ($ in thousands, except distributions per unit)  

Net income attributable to controlling interests

  $ 37,623      $ 29,759      $ 20,973      $ 27,842      $ 116,198   

Plus:

         

Depreciation, depletion and amortization

  $ 44,300      $ 44,300      $ 44,300      $ 44,300      $ 177,200   

Accretion on asset retirement obligations

    319        319        319        319        1,276   

Interest expense

    29,876        29,611        29,455        29,323        118,265   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA(1)

  $ 112,119      $ 103,990      $ 95,046      $ 101,784      $ 412,939   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less:

         

Cash interest expense

  $ 40,506      $ 17,053      $ 40,094      $ 16,756      $ 114,408   

Maintenance capital expenditures

    17,824        17,824        17,824        17,824        71,297   

Expansion capital expenditures

    12,568        6,215        4,027        2,899        25,709   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Plus:

         

Borrowings or cash on hand for expansion capital expenditures(2)

  $ 12,568      $ 6,215      $ 4,027      $ 2,899      $ 25,709   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash available for distribution

  $ 53,789      $ 69,112      $ 37,129      $ 67,204      $ 227,234   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Minimum quarterly and annual distributions per unit

  $ 0.3375      $ 0.3375      $ 0.3375      $ 0.3375      $ 1.3500   

Distributions:

         

Distributions to common unitholders

  $ 21,849      $ 21,849      $ 21,849      $ 21,849      $ 87,398   

Distributions to subordinated unitholders

    21,849        21,849        21,849        21,849        87,398   

Total distributions

  $ 43,699      $ 43,699      $ 43,699      $ 43,699      $ 174,795   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Excess (shortfall)(3)

  $ 10,090      $ 25,413      $ (6,570   $ 23,505      $ 52,439   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Interest Coverage Ratio(4)

    3.25x        3.39x        3.44x        3.61x        3.61x   

Minimum Interest Coverage Ratio

    2.00x        2.00x        2.00x        2.00x        2.00x   

Net Senior Secured Leverage Ratio(4)

    1.64x        1.64x        1.67x        1.55x        1.55x   

Maximum Net Senior Secured Leverage Ratio

    3.25x        3.00x        2.75x        2.75x        2.75x   

 

(1) Please read Note 3 to “Selected Historical Financial Information.”
(2) Includes borrowings under our Revolving Credit Facility equal to expansion capital expenditures.
(3) Any shortfall is expected to be absorbed by borrowings under the Revolving Credit Facility.
(4) Our Revolving Credit Facility requires us to maintain, as of the last day of each fiscal quarter, a consolidated interest coverage ratio (the ratio of our consolidated adjusted EBITDA to our consolidated cash interest charges and measured for the preceding four quarters) of not less than 2.0 to 1.0 for the fourth quarter 2013 and quarters ending thereafter.

Our Revolving Credit Facility also requires us to maintain, as of the last day of any fiscal quarter, a senior secured leverage ratio (the ratio of consolidated funded indebtedness that is secured by a lien on the collateral (other than any lien that is subordinated to the liens securing the obligations thereunder) less the sum of all unrestricted cash, cash equivalents and short -term marketable debt securities to consolidated

 

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adjusted EBITDA for the preceding four quarters). Each of these terms has a specific meaning set forth in the Revolving Credit Facility. The maximum net senior secured leverage ratio allowed under the Revolving Credit Facility is as follows:

 

Fiscal Quarter Ending   

Maximum Net Senior Secured

Leverage Ratio

Fourth Quarter 2013

   3.50 to 1.00

First Quarter 2014

   3.50 to 1.00

Second Quarter 2014

   3.25 to 1.00

Third Quarter 2014

   3.00 to 1.00

Fourth Quarter 2014 and thereafter

   2.75 to 1.00

Each of our Senior Secured Credit Facilities and the indenture governing the 2021 Senior Notes restricts our ability to make cash distributions to our unitholders in the event of default.

 

* Due to rounding, the amounts set forth above may not total to the amounts set forth in each column.

Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of our management. Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2015. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations. We believe we have a reasonable objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and the actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the minimum distribution rate or at all.

Production and Revenues. We forecast that our total revenues for the twelve months ending June 30, 2015 will be approximately $1,272 million, as compared to approximately $957.4 million for the year ended December 31, 2013 and $967.5 million for the twelve months ended March 31, 2014. Our forecast is based primarily on the following assumptions:

 

    We estimate that we will produce approximately 24.1 million tons of coal for the twelve months ending June 30, 2015 as compared to approximately 18.0 million tons we produced for the year ended December 31, 2013 and 18.2 million tons produced for the twelve months ended March 31, 2014. Production from our coal operations for the forecasted period is expected to increase from the year ended December 31, 2013 and the twelve months ended March 31, 2014 based on increased production at our Sugar Camp mining complex due to the addition of a second longwall system that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days and increased production at our other mines. Combined they are expected to add 6.1 million tons of total production compared to the year ended December 31, 2013 and 5.9 million tons of total production compared to the twelve months ended March 31, 2014. Our coal production could vary significantly from the foregoing assumption based on numerous factors, many of which are beyond our control.

 

    We estimate that we will sell approximately 24.7 million tons of coal for the twelve months ending June 30, 2015 as compared to the 18.6 million tons and 19.0 million tons we sold for the year ended December 31, 2013 and the twelve months ended March 31, 2014, respectively. Coal sold for the forecasted period is expected to increase from the year ended December 31, 2013 and the twelve months ended March 31, 2014 based on increased production at our Sugar Camp mining complex due to the addition of a second longwall system that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days and increased production at our other mines.

 

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    We estimate that our coal revenues per ton will be $51.50 for the twelve months ending June 30, 2015, which is materially consistent with revenue per ton of $51.50 for the year ended December 31, 2013 and $50.87 for the twelve months ended March 31, 2014.

 

    The forecast includes commitments to sell approximately 19.4 million tons, or approximately 78% of our forecasted sales at a weighted average price of $52.97 per ton, during the forecasted period.

 

    We are also forecasting to sell approximately 5.3 million tons, or approximately 22% of our forecasted sales during the forecasted period, for which we do not currently have executed supply contracts, for a weighted average price per ton of $46.17. Our estimated weighted average sales price for our uncommitted tons assumes that we will be successful in selling these tons at prices that reflect management’s current estimates of market conditions and pricing trends. Management’s estimates are based on published indices (API2 and API4 in the international market and NYMEX in the domestic market), a review of recently completed transactions and conversations with customers and sales prospects. Actual results could vary significantly from the foregoing assumptions if we are unable to deliver coal pursuant to our contracts, if a number of our customers are unable to satisfy their contractual obligations or if we are incorrect in our pricing or volume assumptions for uncommitted sales.

Cost of Coal Sales (Excluding Depreciation, Depletion and Amortization). We forecast our cost of coal sales will be approximately $534.9 million for the twelve months ending June 30, 2015, as compared to approximately $363.0 million for the year ended December 31, 2013 and $376.3 million for the twelve months ended March 31, 2014. Cost of operations primarily includes the cost of labor and benefits, operating supplies, equipment maintenance, rental and lease cost of equipment, royalties and taxes. The increase in cost of operations for the forecasted period as compared to the year ended December 31, 2013 and the twelve months ended March 31, 2014 is attributable primarily to increased production as well as a forecasted increase in cash cost per ton.

We forecast that our cash cost of coal sales on a per ton basis for the twelve months ending June 30, 2015 will be $21.66, as compared to $19.53 for the year ended December 31, 2013 and $19.79 for the twelve months ended March 31, 2014. Our cash cost per ton is expected to increase over the forecast period. This expectation is based primarily on our assessment of the near-term mining conditions at our mines, timing of longwall moves and the commencement of production at our second longwall at Sugar Camp that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. Our forecasted cost of coal sales could vary significantly because of a large number of variables, many of which are beyond our control.

Transportation. We forecast transportation expense to be approximately $283.2 million for the twelve months ending June 30, 2015, as compared to approximately $197.8 million for the year ended December 31, 2013 and $207.7 million for the twelve months ended March 31, 2014. The increase in transportation expense as compared to the year ended December 31, 2013 and the twelve months ended March 31, 2014 is due primarily to the increase in forecasted tons sold.

Depreciation, Depletion and Amortization. We forecast depreciation, depletion and amortization expense to be approximately $177.2 million for the twelve months ending June 30, 2015, as compared to approximately $161.2 million for the year ended December 31, 2013 and $159.3 million for the twelve months ended March 31, 2014. The increase in depreciation, depletion and amortization expense as compared to the year ended December 31, 2013 and the twelve months ended March 30, 2014 is due to an increase in depreciation related to an additional longwall system at Sugar Camp that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days.

Selling, General and Administrative. We forecast selling, general and administrative expenses to be approximately $40.6 million for the twelve months ending June 30, 2015, as compared to approximately $32.3 million for the year ended December 31, 2013 and $32.3 million for the twelve months ended March 30, 2014.

 

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The increase in expenses as compared to the year ended December 31, 2013 and the twelve months ended March 30, 2014, is primarily due to lower discretionary bonuses paid in 2013 and $4.0 million in incremental expenses related to public company costs.

Other Operating Income and Expense. We forecast no material other operating income or expense for the twelve months ending June 30, 2015, as compared to operating income of approximately $0.3 million for the year ended December 31, 2013 and $0.5 million for the twelve months ended March 30, 2014.

Gain on Coal Derivatives. For the year ended December 31, 2013 we recorded income of $2.4 million from our coal derivatives and for the twelve months ended March 31, 2014 we recorded income of $17.3 million. We do not forecast and gain or loss on derivative contracts during out forecast period.

Interest Expense. We forecast interest expense of approximately $118.3 million for the twelve months ending June 30, 2015, as compared to $115.9 million for the year ended December 31, 2013 and $117.3 million for the twelve months ended March 30, 2014. The increase in interest expense as compared to the year ended December 31, 2013 and the twelve months ended March 30, 2014, is due primarily to capitalized interest in the historical periods. Forecasted interest expense gives effect to the repayment of the Interim Longwall Financing Arrangement with borrowings under our Revolving Credit Facility. See “Description of Indebtedness—Interim Longwall Financing Arrangement.”

Capital Expenditures. Our partnership agreement will distinguish between maintenance capital expenditures (which are those cash expenditures made to maintain, over the long term, our operating capacity or net income as they exist at such time as the capital expenditures are made) and expansion capital expenditures (which are those cash expenditures, including transaction expenses, made to sustainably increase, over the long term, our operating capacity or net income as they exist at such time as the capital expenditures are made). We forecast capital expenditures for the twelve months ending June 30, 2015 based on the following assumptions:

 

    We forecast our maintenance capital expenditures to be $71.3 million for the twelve months ending June 30, 2015, as compared to actual maintenance capital expenditures of approximately $76.4 million for the year ended December 31, 2013 and $71.4 million for the twelve months ended March 31, 2014. The decrease compared to the year ended December 31, 2013 is primarily due to lower maintenance capital expenditures forecasted at our first Sugar Camp and Williamson mines, the distribution of the Sitran complex in August 2013, and lower corporate spend on software and other projects. Partially offsetting these decreases are maintenance capital expenditures related to the new longwall system at Sugar Camp, that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days, and higher capital spending at Hillsboro. Maintenance capital expenditures include the rebuild, replacement, repair and maintenance of mining equipment associated with our continuous miners and longwall systems, belts and conveyors, preparation plant maintenance, and refuse disposal areas. The forecasted levels of maintenance capital expenditures are based on actual cost experienced operating Williamson, Sugar Camp, Hillsboro, and Macoupin and budgeted capital expenditures by our mine operation teams based on recent purchase orders and discussions with vendors regarding pricing. Our forecasted maintenance capital expenditures do not include actual or estimated capital expenditures for replacement of our coal reserves. We expect to fund maintenance capital expenditures from cash generated by our operations.

 

    We estimate that our expansion capital expenditures will be approximately $25.7 million for the twelve months ending June 30, 2015. For purposes of this presentation, we have assumed that all expansion capital expenditures will be funded with borrowings or cash on hand.

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those expenditures made to maintain, over the long term, our operating capacity or net income

 

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as they exist at such time as the capital expenditures are made. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain, over the long term, our operating capacity or net income as they exist at such time as the capital expenditures are made. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of. Our general partner will review all capital expenditures on an annual basis in connection with the budget process and on a quarterly basis at the time expenditures are made to determine which expenditures increase current operating capacity or net income over the long term. Factors our general partner will consider include an assessment of current operating capacity or net income of the mine at the time of the expenditure and an evaluation of whether the expenditure will increase the mine’s capacity or net income or whether the expenditure will replace current operating capacity or net income. To the extent the capital expenditure increases operating capacity or net income in a sustainable way, it will be classified as an expansion capital expenditure in the period in which the expenditure was made. Otherwise, it will be considered a maintenance capital expenditure. As an example, the capital expenditure related to the development of the second longwall at Sugar Camp is considered an expansion capital expenditure since it increases the current operating capacity or net income of the Sugar Camp Complex over the long term. In contrast, the rebuild of a continuous miner unit would be considered a maintenance capital expenditure as it would not result in a sustainable, long-term increase to our operating capacity or net income but rather will maintain our current operating capacity. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Regulatory, Industry and Economic Factors. We forecast our results of operations for the twelve months ending June 30, 2015 based on the following assumptions related to regulatory, industry and economic factors:

 

    No material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor.

 

    All supplies and commodities necessary for production and sufficient transportation will be readily available.

 

    No new federal, state or local regulation of the portions of the mining industry in which we operate or any interpretation of existing regulation that in either case will be materially adverse to our business.

 

    No material unforeseen geological conditions or equipment problems at our mining locations.

 

    No material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events.

 

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

General

Cash Distribution Policy

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending June 30, 2014, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3375 per unit, or $1.3500 on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We will prorate the distribution for the period after the closing of the offering through June 30, 2014.

The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Operating Surplus and Capital Surplus

General

Any distributions we make will be characterized as made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the incentive distribution rights would generally not participate in any capital surplus distributions. Any distribution of capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the incentive distribution rights would thereafter be entitled to participate in such distributions. Please read “—Distributions From Capital Surplus.”

Operating Surplus

We define operating surplus as:

 

    $125 million (as described below); plus

 

    all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and provided that cash receipts from the termination of any hedge contract prior to its stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus

 

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    cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

 

    cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on until the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is abandoned or disposed of; less

 

    all of our operating expenditures (as defined below) after the closing of this offering; less

 

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

    all working capital borrowings not repaid within twelve months after having been incurred; less

 

    any cash loss realized on disposition of an investment capital expenditure.

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity’s operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to described in the first bullet above). Operating surplus does not reflect cash generated by our operations. For example, it includes a basket of $125 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deduction.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under hedge contracts (provided that (1) with respect to amounts paid in connection with the initial purchase of a hedge contract, such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated), officer compensation, repayment of working capital borrowings, interest on indebtedness and estimated maintenance capital expenditures, provided that operating expenditures will not include:

 

    repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

 

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    payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;

 

    expansion capital expenditures;

 

    actual maintenance capital expenditures;

 

    investment capital expenditures;

 

    payment of transaction expenses relating to interim capital transactions;

 

    distributions to our partners (including distributions in respect of our incentive distribution rights); or

 

    repurchases of equity interests except to fund obligations under employee benefit plans.

Capital Surplus

Capital surplus is defined in our partnership agreement as any cash distribution in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as “interim capital transactions”):

 

    borrowings other than working capital borrowings;

 

    sales of our equity interests; and

 

    sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus since the closing of this offering. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Our partnership agreement will distinguish between maintenance capital expenditures (which 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), expansion capital expenditures (which are cash expenditures, including transaction expenses, made to increase over the long term, our operating capacity or net income as they exist at such time as the capital expenditures are made) and investment capital expenditures (capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures). Our general partner will determine the amount of expenditures made to maintain or increase our long term operating capacity or net income.

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether at an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain our then current operating capacity or net income as they exist at such time as the capital expenditures are made. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights)

 

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to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of. Our general partner will review all capital expenditures on an annual basis in connection with the budget process and on a quarterly basis at the time expenditures are made to determine which expenditures increase current operating capacity or net income over the long term. Factors our general partner will consider include an assessment of current operating capacity or net income of the mine at the time of the expenditure and an evaluation of whether the expenditure will increase the mine’s capacity or net income or whether the expenditure will replace current operating capacity or net income. To the extent the capital expenditure increases operating capacity or net income in a sustainable way, it will be classified as an expansion capital expenditure in the period in which the expenditure was made. Otherwise, it will be considered a maintenance capital expenditure. As an example, the capital expenditure related to the development of the second longwall at Sugar Camp is considered an expansion capital expenditure since it increases the current operating capacity or net income of the Sugar Camp Complex over the long term. In contrast, the rebuild of a continuous miner unit would be considered a maintenance capital expenditure as it would not result in a sustainable, long-term increase to our operating capacity or net income but rather will maintain our current operating capacity. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus if we subtracted actual maintenance capital expenditures from operating surplus.

To eliminate these fluctuations, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity over the long-term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and change by our general partner at least once a year, provided that any change is approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, including but not limited to a major acquisition or expansion or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

 

    the amount of actual maintenance capital expenditures in any quarter will not directly reduce operating surplus but will instead be factored into the estimate of the average quarterly maintenance capital expenditures. This may result in the subordinated units converting into common units when the use of actual maintenance capital expenditures would result in lower operating surplus during the subordination period and potentially result in the tests for conversion of the subordinated units not being satisfied;

 

    it may increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

 

    it may be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

Expansion capital expenditures are those cash expenditures, including transaction expenses, made to increase our operating capacity or net income over the long term. Examples of expansion capital expenditures including but not limited to the acquisition of reserves, equipment or a new mine or the expansion of an existing

 

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mine, to the extent such expenditures are expected to expand our long-term operating capacity or net income. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such acquisition or expansion in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition construction, development or expansion commences commercial service and the date that it is disposed of or abandoned. Expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures are those capital expenditures, including transaction expenses, that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of an asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or net income, but which are not expected to expand, for more than the short term, our operating capacity or net income.

As described above, neither investment capital expenditures nor expansion capital expenditures are included in operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of an acquisition, development or expansion in respect of a period that begins when we enter into a binding obligation for an acquisition construction, development or expansion and ending on the earlier to occur of the date on which such acquisition, construction, development or expansion commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Cash expenditures that are made in part for maintenance capital purposes, investment capital purposes and/or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

For example, during the period ending June 30, 2015, we expect to incur $25.7 million in expansion capital expenditures related to our fourth longwall that began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. Because the fourth longwall is expected to result in a long term increase in our operating capacity, it will be classified as an expansion capital expenditure. We expect that any other expansion capital expenditures will be incurred by Foresight Reserves and the expansion project will be offered to us upon completion of development. Because any such expansion capital expenditure will be incurred by Foresight Reserves, it will not be our capital expenditure. However, if we were to purchase an expansion following completion, the purchase price would be an expansion capital expenditure or maintenance capital expenditure, depending on whether it was made to expand or maintain our long term operating capacity or net income. We expect that each additional longwall we construct or acquire will require approximately $20 million in incremental maintenance capital expenditures annually.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $0.3375 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from

 

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prior quarters, before any distributions from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending March 31, 2017, if each of the following has occurred:

 

    for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding in each quarter in each period;

 

    for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as described below) equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and

 

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

For the period after the closing of this offering through June 30, 2014, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending March 31, 2015, if each of the following has occurred:

 

    for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded the sum of 150.0% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in the period;

 

    for the same four-quarter period, the “adjusted operating surplus” (as described below) equaled or exceeded the sum of 150.0% of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

 

    there are no arrearages in payment of the minimum quarterly distributions on the common units.

Conversion Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause, the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner.

 

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Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions.

Adjusted Operating Surplus

Adjusted operating surplus is intended to generally reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses during that period. Adjusted operating surplus for any period consists of:

 

    operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

    any net increase during that period in working capital borrowings; less

 

    any net decrease during that period in cash reserves for operating expenditures not relating to an operating expenditure made during that period; plus

 

    any net decrease during that period in working capital borrowings; plus

 

    any net increase during that period in cash reserves for operating expenditures required by any debt instrument for the repayment of principal, interest or premium; plus

 

    any net decrease made in subsequent periods in cash reserves for operating expenditures initially established during such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Any disbursements received, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period that the general partner determines to include in operating surplus for such period shall also be deemed to have been made, received or established, increased or reduced in such period for purposes of determining adjusted operating surplus for such period.

Distributions From Operating Surplus During the Subordination Period

If we make a distribution from operating surplus for any quarter ending before the end of the subordination period, our partnership agreement requires that we make the distribution in the following manner:

 

    first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

 

    second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

    thereafter, in the manner described in “—General Partner Interest—Incentive Distribution Rights” below.

Distributions From Operating Surplus After the Subordination Period

If we make distributions of cash from operating surplus for any quarter ending after the subordination period, our partnership agreement requires that we make the distribution in the following manner:

 

    first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

 

    thereafter, in the manner described in “—General Partner Interest—Incentive Distribution Rights” below.

 

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General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner owns the incentive distribution rights and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

If for any quarter:

 

    we have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

    we have distributed cash from operating surplus to the common unitholders in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the incentive distribution rights in the following manner:

 

    first, to all unitholders, pro rata, until each unitholder receives a total of $0.3881 per unit for that quarter (the “first target distribution”);

 

    second, 85.0% to all common unitholders and subordinated unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.4219 per unit for that quarter (the “second target distribution”);

 

    third, 75.0% to all common unitholders and subordinated unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $0.5063 per unit for that quarter (the “third target distribution”); and

 

    thereafter, 50.0% to all common unitholders and subordinated unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Percentage Allocations of Distributions From Operating Surplus

The following table illustrates the percentage allocations of distributions, from operating surplus between the unitholders and the holders of our incentive distribution rights 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 holders of our incentive distribution rights and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit.” The percentage interests shown for our unitholders and the holders of our incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.

 

     Total Quarterly Distribution
Per Common Unit(1)
   Marginal Percentage
Interest in Distributions
 
      Unitholders     IDR Holders  

Minimum Quarterly Distribution

   $0.3375      100.0     0

First Target Distribution

   above $0.3375 up to $0.3881      100.0     0

Second Target Distribution

   above $0.3881 up to $0.4219      85.0     15.0

Third Target Distribution

   above $0.4219 up to $0.5063      75.0     25.0

Thereafter

   above $0.5063      50.0     50.0

 

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Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made.

The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner 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 the prior four consecutive fiscal quarters. The reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset election and higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. Because the reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset, if we were to issue additional common units after the reset and maintain the per unit distribution level, no additional incentive distributions would be payable. By contrast, if there were no such reset and we were to issue additional common units and maintain the per unit distribution level, additional incentive distributions would have to be paid based on the additional number of outstanding common units and the percentage interest of the incentive distribution rights above the target distribution levels. Thus, the exercise of the reset right would lower our cost of equity capital. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

In connection with the resetting of the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would equal the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter.

Following a reset election, a baseline minimum quarterly distribution amount will be calculated as an amount equal to the cash distribution amount per unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

 

    first, to all common unitholders, pro rata, until each unitholder receives an amount per unit for that quarter equal to 115.0% of the reset minimum quarterly distribution;

 

    second, 85.0% to all common unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for the quarter equal to 125.0% of the reset minimum quarterly distribution;

 

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    third, 75.0% to all common unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for the quarter equal to 150.0% of the reset minimum quarterly distribution; and

 

    thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights at various distribution levels (1) pursuant to the distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the target distribution levels based on the assumption that the quarterly distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $0.6000.

 

     Quarterly Distribution
Per Unit Prior to Reset
   Unitholders     IDR
Holders
    Quarterly Distribution
Per Unit Following
Hypothetical Reset

First Target Distribution

   up to $0.3881      100.0     0.0            up to $0.6900(1)

Second Target Distribution

   above $0.3881 up to $0.4219      85.0     15.0   above $0.6900 up to $0.7500(2)

Third Target Distribution

   above $0.4219 up to $0.5063      75.0     25.0   above $0.7500 up to $0.9000(3)

Thereafter

   above $0.5063      50.0     50.0   above $0.9000

 

(1) This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
(2) This amount is 125.0% of the hypothetical reset minimum quarterly distribution.
(3) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be 129,477,790 common units outstanding and the distribution to each common unit would be $0.6000 for the quarter prior to the reset.

 

    Prior to Reset  
  Quarterly
Distributions
Per Unit
  Distributions to
Common
Unitholders
    Cash Distributions
to IDR Holders
    Total
Distributions
 
      Common
Units
    Incentive
Distribution
Rights
    Total    

Minimum Quarterly Distribution

  $0.3375   $ 43,698,754        —          —          —        $ 43,698,754   

First Target Distribution

  above $0.3375 up to $0.3881     6,554,813        —          —          —          6,554,813   

Second Target Distribution

  above $0.3881 up to $0.4219     3,714,394        —          655,481        655,481        4,369,875   

Third Target Distribution

  above $0.4219 up to $0.5063     8,193,516        —          2,731,172        2,731,172        10,924,689   

Thereafter

  above $0.5063     6,069,271        —          6,069,271        6,069,271        12,138,543   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $ 68,230,749        —        $ 9,455,925      $ 9,455,925      $ 77,686,674   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of our incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be 145,237,665 common units outstanding and the distribution to each common unit would be $0.6000. The number of common units to be issued upon the reset was calculated by dividing (1) the amount received in respect of the incentive distribution rights for the quarter prior to the reset as shown in the table above, or $9.5 million, by (2) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $0.6000.

 

    After Reset  
  Quarterly
Distributions
Per Unit
  Distributions to
Common
Unitholders
    Cash Distributions
to IDR Holders
    Total
Distributions
 
      Common
Units(1)
    Incentive
Distribution
Rights
    Total    

Minimum Quarterly Distribution

  $0.6000   $ 68,230,749      $ 9,455,925            —        $ 9,455,925      $ 77,686,674   

First Target Distribution

  above $0.6000 up to $0.6900     —          —          —          —          —     

Second Target Distribution

  above $0.6900 up to $0.7500     —          —          —          —          —     

Third Target Distribution

  above $0.7500 up to $0.9000     —          —          —          —          —     

Thereafter

  above $0.9000     —          —          —          —          —     
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $ 68,230,749      $ 9,455,925      $ —        $ 9,455,925      $ 77,686,674   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Represents distributions in respect of the common units issued upon the reset.

The holders of our incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion.

Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions from capital surplus, if any, in the following manner:

 

    first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

 

    second, to the common unitholders, pro rata, until we distribute for each common unit an amount from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

 

    thereafter, we will make all distributions from capital surplus as if they were from operating surplus.

Effect of a Distribution From Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution of capital surplus to the fair market value of the common units prior to the announcement of the

 

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distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 50.0% is paid to all unitholders, pro rata, and 50.0% is paid to the holder or holders of incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

 

    the minimum quarterly distribution;

 

    the target distribution levels;

 

    the initial unit price, as described below under “—Distributions of Cash Upon Liquidation”;

 

    the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and

 

    the number of subordinated units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is cash for that quarter (after deducting our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholdings taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (1) cash for that quarter, plus (2) our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

 

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The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

 

    first, to our general partner to the extent of certain prior losses specially allocated to our general partner;

 

    second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

 

    third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1) the initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

    fourth, to all unitholders, pro rata, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

 

    fifth, 85.0% to all unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights for each quarter of our existence;

 

    sixth, 75.0% to all unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights for each quarter of our existence; and

 

    thereafter, 50.0% to all unitholders, pro rata, and 50.0% to holders of our incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

 

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We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

 

    first, to holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;

 

    second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

 

    thereafter, 100% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and the holders of our incentive distribution rights based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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SELECTED HISTORICAL FINANCIAL INFORMATION

The following table sets forth our selected historical consolidated financial and other data, at the dates and for the periods indicated. The selected historical consolidated statements of operations data for the years ended December 31, 2013, 2012 and 2011 and the selected historical consolidated balance sheet data as of December 31, 2013 and 2012 have been derived from Foresight Energy LLC’s audited consolidated financial statements included elsewhere in this prospectus. The selected historical consolidated statements of operations data for the years ended December 31, 2010 and 2009 and the selected historical consolidated balance sheet data as of December 31, 2011, December 31, 2010 and December 31, 2009 have been derived from Foresight Energy LLC’s audited consolidated financial statements, which are not included in this prospectus. The selected historical consolidated balance sheet data as of March 31, 2014 and the selected historical consolidated statements of operations data for the three months ended March 31, 2014 and 2013 have been derived from Foresight Energy LLC’s unaudited consolidated financial statements included elsewhere in this prospectus. The selected historical consolidated balance sheet data as of March 31, 2013 have been derived from Foresight Energy LLC’s unaudited consolidated balance sheet as of March 31, 2013, which is not included in this prospectus. The selected unaudited consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of our management, include all material adjustments, consisting of normal and recurring adjustments, necessary for a fair presentation of the information set forth herein. Operating results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the year ended December 31, 2014 or for any future period. This data should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this prospectus. The following information is only a summary and should be read in conjunction with the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the related notes included elsewhere in this prospectus.

 

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    For the Years Ended December 31,     For the Three
Months Ended
March 31,
 
    2013     2012     2011     2010     2009     2014     2013  
    (in thousands, except per ton sold data)  

Statements of Operations

             

Revenues

             

Coal sales

  $ 957,412      $ 845,886      $ 500,791      $ 362,592      $ 271,249      $ 242,723      $ 232,593   

Costs and expenses

             

Cost of coal sales (excluding depreciation, depletion and amortization)

    363,024        309,801        174,183        130,610        101,528        93,153        79,848   

Transportation

    197,839        171,679        98,394        58,482        48,933        59,436        49,614   

Depreciation, depletion and amortization

    161,216        124,552        70,411        55,647        39,017        35,258        37,199   

Accretion on asset retirement obligations

    1,527        1,368        1,705        2,011        1,655        405        382   

Selling, general and administrative

    32,291        41,528        38,894        28,367        22,610        9,038        9,006   

Other operating (income) expense, net(1)

    (280     (10,759     (791     (2,611     (3,208     (686     (424

Gain on commodity contracts

    (2,392     (534     (2,395     —          —         
(15,401

    (452
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    204,187        208,251        120,390        90,086        60,714        61,520        57,420   

Other (income) and expense:

             

Loss on early extinguishment of debt

    77,773        —          —          —          —          —          —     

Interest income

    (11     (1     (6     (67     (427     (1     (11

Interest expense

    115,908        82,581        38,199        40,498        47,052        29,605        28,211   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income from continuing operations

    10,517        125,671        82,197        49,655        14,089        31,916        29,220   

Net loss from discontinued operations

    —          —          —          (40,893     (50,545     —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    10,517        125,671        82,197        8,762        (36,456     31,916        29,220   

Less: Net income (loss) attributable to non-controlling interests

    2,236        (160     104        909        246        613        75   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to controlling interests

  $ 8,281      $ 125,831      $ 82,093      $ 7,853      $ (36,702   $ 31,303      $ 29,145   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statements of Cash Flows

             

Net cash provided by operating activities

  $ 179,526      $ 209,691      $ 103,143      $ 61,388      $ 85,480      $ 28,423      $ 55,247   

Net cash used in investing activities

  $ (209,275   $ (207,039   $ (332,821   $ (272,117   $ (386,794   $ (65,160   $ (33,261

Net cash provided by (used in) financing activities

  $ 25,145      $ (26,525   $ 247,988      $ 196,091      $ 329,604      $ 38,698      $ (8,462

Balance Sheet Data (at period end)

             

Cash and investments in available-for-sale securities

  $ 23,284      $ 27,888      $ 51,761      $ 33,451      $ 57,031      $ 25,245      $ 41,412   

Property, plant, equipment and mine
development, net

  $ 1,414,074      $ 1,401,285      $ 1,323,800      $ 995,425      $ 634,250      $ 1,440,892      $ 1,396,356   

Total assets

  $ 1,710,171      $ 1,695,288      $ 1,546,969      $ 1,131,880      $ 1,036,160      $ 1,782,576      $ 1,710,913   

Total long-term debt(2)

  $ 1,519,213      $ 1,061,949      $ 897,411      $ 605,390      $ 345,753      $ 1,560,812      $ 1,078,424   

Total members’ (deficit) equity

  $ (148,116   $ 280,103      $ 394,205      $ 282,066      $ 133,103      $ (118,492   $ 309,198   

Other Data

             

Adjusted EBITDA(3)

  $ 364,694      $ 338,607      $ 192,402      $ 146,835      $ 101,140      $ 96,570      $ 94,926   

Capital expenditures

  $ 210,726      $ 209,937      $ 336,020      $ 277,409      $ 326,525      $ 65,160      $ 34,247   

Tons produced(4)

    17,991        15,080        9,028        6,813        5,921        5,059        4,888   

Tons sold(4)

    18,589        14,403        8,773        6,730        5,635        4,706        4,275   

Average realized price per ton sold(5)

  $ 51.50      $ 58.73      $ 57.08      $ 53.88      $ 48.14      $ 51.58      $ 54.41   

Cash costs per ton sold(6)

  $ 19.53      $ 21.51      $ 19.85      $ 19.41      $ 18.02      $ 19.79      $ 18.68   

 

(1) For the year ended December 31, 2012, $10.0 million was recognized as other operating income for a legal settlement with a customer on a coal sales contract. For the year ended December 31, 2009, other operating income relates primarily to a one-time sale of equipment at Macoupin.
(2) Includes current portion of long-term debt. Total long-term debt does not include $143.5 million for the years ended December 31, 2011 and 2010, $193.4 million for the years ended December 31, 2013 and 2012 and for the three months ended March 31, 2014 and 2013 of certain sale-leaseback financing obligations (including coal and surface leases) that are characterized as financing arrangements due to the involvement of certain of our affiliates in mining the reserves and utilizing the equipment related to the leases. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Certain Relationships and Related Party Transactions.” Total long-term debt also includes, among other items, other liabilities of discontinued operations for the years ended December 31, 2009.
(3)

Adjusted EBITDA is defined as net income from continuing operations (as applicable) attributable to controlling interests before interest, taxes, depreciation, depletion, amortization and accretion. Adjusted EBITDA may also be adjusted for material nonrecurring and other

 

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  items which may not reflect the trend of future results. Adjusted EBITDA is not a measure of performance defined in accordance with US 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 the US GAAP results and the reconciliation to US 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 as an indicator of our performance or as an alternative to net cash provided by operating activities as a measure of liquidity. The primary material limitations associated with the use of Adjusted EBITDA as compared to US GAAP results are (i) Adjusted EBITDA may not be comparable to similarly titled measures used by other companies in our industry, and (ii) Adjusted EBITDA excludes financial information that some consider important in evaluating our performance. We compensate for these limitations by providing disclosure of the differences between Adjusted EBITDA and US GAAP results, including providing a reconciliation of Adjusted EBITDA to US GAAP results, to enable investors to perform their own analysis of our operating results. Adjusted EBITDA presented herein does not give effect to the full year impact of the 2013 Reorganization or the 2013 Refinancing. See “Business—2013 Reorganization.”

The following table reconciles Adjusted EBITDA to the most directly comparable US GAAP measure, net income from continuing operations attributable to controlling interests:

 

    For the Years Ended December 31,     For the Three
Months Ended
March 31,
 
    2013     2012     2011     2010     2009     2014     2013  

Net income from continuing operations attributable to controlling interests

  $ 8,281      $ 125,831      $ 82,093      $ 48,746      $ 13,843      $ 31,303      $ 29,145   

Write-off of deferred offering costs

    —          4,276        —          —          —          —          —     

Loss on early extinguishment of debt

    77,773        —          —          —          —          —          —     

Interest income

    (11     (1     (6     (67     (427     (1     (11

Interest expense

    115,908        82,581        38,199        40,498        47,052        29,605        28,211   

Depreciation, depletion and amortization

    161,216        124,552        70,411        55,647        39,017        35,258        37,199   

Accretion on asset retirement obligations

    1,527        1,368        1,705        2,011        1,655        405        382   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 364,694      $ 338,607      $ 192,402      $ 146,835      $ 101,140      $ 96,570      $ 94,926   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

  (a) Interest expense, net includes interest expense attributable to our sale-leaseback financing obligations (including coal and surface leases) that are characterized as financing transactions due to the continuing involvement of certain of our affiliates in mining related to the leases. For the years ended December 31, 2013, 2012, 2011 and 2010, interest expense related to these financing arrangements was $26.8 million, $26.0 million, $13.1 million and $23.4 million, respectively. Prior to 2010, we had no sale-leaseback financing obligations outstanding. For the three months ended March 31, 2014 and 2013, interest expense related to these financing arrangements was $6.4 million and $6.6 million, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Certain Relationships and Related Party Transactions” and our consolidated historical financial statements, along with the notes thereto, included elsewhere in this prospectus.

 

(4) Tons produced and tons sold do not include mines while in development. Revenues and costs from mines in development are capitalized as mine development in our balance sheets. The first longwall mines at Sugar Camp and Hillsboro came out of development in March 2012 and September 2012, respectively. Our second longwall mine at Sugar Camp began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. During the years ended December 31, 2013, 2012, 2011, 2010 and 2009 our development mines produced 0.8 million tons, 1.2 million tons, 1.4 million tons, 0.3 million tons and 0.1 million tons, respectively, and sold 0.8 million tons, 1.4 million tons, 0.9 million tons, 0.3 million tons and 0.2 million tons, respectively. During the three months ended March 31, 2014 and 2013, our development mines produced 0.2 million tons and 0.2 million tons, respectively, and sold 0.2 million tons and 0.2 million tons, respectively.
(5) Calculated as coal sales divided by tons sold. Average realized price per ton sold is not a US GAAP metric and it may not be comparable to similarly titled measures used by other companies in our industry.
(6) Calculated as cost of coal sales (excluding depreciation, depletion and amortization) divided by tons sold. Cash costs per ton sold is not a US GAAP metric and may not be comparable to similarly titled measures used by other companies in our industry.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis together with “Selected Historical Financial Information” and our consolidated financial statements and related notes included elsewhere in this prospectus. 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 “Special Note Regarding Forward-Looking Statements,” “Risk Factors” and elsewhere in this prospectus. All references to produced tons, sold tons, or cash cost per ton sold refer to clean tons of coal.

Overview

We believe we are the lowest cost underground coal producer in the United States, based on publicly available information. We currently operate four underground mining complexes, all in the Illinois Basin region of the United States. Our mining complexes consist of:

 

    Williamson Energy, LLC (“Williamson”), a longwall mining complex in southern Illinois, currently producing coal with one longwall mining system and two continuous miner units, with a productive capacity in excess of approximately 7.5 million tons per year;

 

    Sugar Camp Energy, LLC (“Sugar Camp”), a longwall mining complex in southern Illinois, currently producing coal with one longwall mining system and three continuous miner units. A second longwall mine at the Sugar Camp complex began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. With additional mine development, we have the capacity to add two incremental longwall systems, which would form a new mining complex requiring new surface infrastructure and a new slope. As a result, we expect productive capacity at these two complexes will be 27.0 million tons per year when all four of these longwall mining systems are operational, the first of which began in March 2012 and the second of which began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days;

 

    Hillsboro Energy, LLC (“Hillsboro”), a longwall mining complex in central Illinois, currently producing coal with one longwall mining system and two continuous miner units. The complex has a productive capacity of 24.0 million tons per year with all three of its longwall mining systems operational, the first of which began in September 2012; and

 

    Macoupin Energy, LLC (“Macoupin”), a continuous miner operation in central Illinois, currently producing with one continuous miner. The complex has a productive capacity of 8.7 million tons per year with the operation of a second continuous miner unit and the development of a new mine with a longwall mining system accessing its additional reserves.

With more than three billion tons of assigned proven and probable coal reserves, we believe our coal reserves are sufficient to support over 45 years of production at our full productive capacity of up to 67.2 million tons per year. All of our reserves are favorably located with transportation access to market via rail, barge, vessel and truck. We have direct and indirect access to five Class I railroads. We also have contractual access to a barge-loading river terminal on the Ohio River owned by an affiliate and have contractual arrangements with railroads, seaborne export terminals and additional river terminals giving us long-term market access with cost certainty.

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. Our second longwall mining system at our Sugar Camp complex began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. The timing of additional

 

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development is dependent on several factors, including permitting, demand, access to capital, equipment availability and the committed sales position at our existing mining operations.

Factors That Affect Our Results

Coal Prices. We attempt to mitigate price fluctuations by executing long-term contracts and economically hedging a portion of our unpriced export position. Domestic coal prices have weakened due to reduced demand from coal-fired plants. International prices have also declined as a result of excess supply in the marketplace. We expect this low-price environment to continue into the first half of 2014.

Coal Demand. Demand for coal can increase due to unusually hot or cold weather as consumers use more air conditioning or heating. 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.

In the domestic market, we are generally seeing renewed demand as utilities have largely worked through remaining excess inventories and as natural gas prices have risen. Despite the current weakness in international prices, we believe that long-term international demand for thermal coal will continue to increase due primarily to strong demand from China, India and other Asian countries, coupled with a shift of supply from the Atlantic market to the Pacific market and a limited supply from traditional coal exporting countries. As a result of growing international demand, coal prices for seaborne thermal coal have, from time to time, been higher relative to domestic prices and, based on forward price curves, are expected to continue to increase over time. Given our low cost of production and transportation optionality, we believe we will be able to competitively sell our coal into the seaborne market.

Operations in Development. For US generally accepted accounting principles (“US GAAP”) reporting purposes, our mining operations are considered to be in development until longwall mining operations commence. While in development, coal sales, if any, and their costs are capitalized, and therefore, the results of operations in development do not have an effect on our consolidated statements of operations. Longwall operations at Sugar Camp and Hillsboro came out of development in March 2012 and September 2012, respectively. Therefore, their results of operations are included in our consolidated statements of operations subsequent to the end of development of their longwall operations. Our second longwall mine at the Sugar Camp complex began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days.

Contract Position. We sell a significant portion of our coal under agreements with terms that range from one to seven years. As of March 31, 2014, we had 18.8 million tons committed and priced and 1.8 million tons committed and unpriced for 2014. We have 10.1 million tons committed and priced and 5.3 million tons committed and unpriced for the year ending December 31, 2015. We have 5.0 million tons committed and priced and 6.6 million tons committed and unpriced for the year ending December 31, 2016. We have sold coal to 110 domestic power plants, industrial users and international customers. Historically, we have marketed our coal principally to electric utilities in the United States. With the execution of a long-term throughput agreement at an international export terminal in April 2012, we have been able to balance our domestic and international sales mix. During the three months ended March 31, 2014 and the years ended December 31, 2013, 2012, and 2011, export tons represented 37%, 33%, 44%, and 29% of tons sold, respectively (inclusive of both our operating mine sales and nominal sales from our development mines).

Our sales strategy is generally to enter into long-term contracts for the majority of our production, with the initial two to three years at fixed prices and subsequent years subject to reset at a negotiated price or the prevailing market price.

 

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We believe that our low-cost structure positions us to successfully re-price our coal at a profitable margin in any price environment in which our competitors also operate. Our average coal sales revenue per ton in the near term may decrease as we replace expiring favorably priced supply contracts with new supply contracts at contractually negotiated market prices.

Coal Production Rates. For US GAAP reporting purposes, our Williamson and Macoupin mining complexes were our only operating mines prior to 2012. Sugar Camp’s and Hillsboro’s first longwalls began production on March 1, 2012, and September 1, 2012, respectively. Our coal production and revenues for US GAAP reporting purposes have grown as Sugar Camp and Hillsboro transitioned from development to longwall production. Our fourth longwall began start-up testing and operations in late May, 2014 and is expected to achieve normal run-rate within the next thirty days. Unless otherwise noted herein, all references to tons produced, tons sold or cash cost per ton sold refer to clean tons of coal produced from our operating mines. The table below represents total tons produced from our operating and development mines:

 

    Year Ended December 31,     Three Months Ended March 31,  
      2013         2012         2011         2014         2013    
    (in millions)              

Tons produced—operating mines

    18.0        15.1        9.0        5.1        4.9   

Tons produced—development mines

    0.8        1.2        1.4        0.2        0.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

*Total

    18.8        16.3        10.4        5.3        5.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

* Amounts may not foot due to rounding.

Longwall Moves. Longwall mines have periods of interrupted production as mining is completed in a particular panel and the longwall mining equipment is disassembled, moved and reassembled at the next panel. During these periods, the mine continues to ship coal to customers from inventory. We attempt to minimize this production interruption by designing long and wide panels that limit moves to approximately once per year. Using this design, combined with advance planning and spare longwall mining equipment, the last three longwall moves at Williamson and the first longwall move at Sugar Camp during the third quarter of 2013 have had production interruptions of two days or less. There are no guarantees that future longwall moves at our longwall mines will have similar results. In October 2013, Hillsboro executed its first longwall move. Spare longwall shields were not available; therefore, production was interrupted for approximately three weeks. However, Hillsboro had sufficient inventory on hand such that sales were not impacted by the longwall move.

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, property and land subsidence costs, sales-related costs, 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, the cost of consumable items or inputs in to our supplies, changes in regulation on our industry, and/or our staffing levels. In particular, our royalties can depend directly upon the price at which we sell our coal and the underlying terms of our coal leases.

Transportation. We sell a majority of our coal to customers at delivery points other than our mines, including, but not limited to, river terminals on the Ohio and Mississippi Rivers and at two ports in New Orleans. As such, we often bear the transportation cost to and through these facilities. Where possible, we enter into long-term transportation and throughput agreements. Because we are responsible for the cost of transporting our coal to these various delivery points, we bear the risk that our transportation expense will increase over time. Our transportation costs, in part, correlate to the distance required to transport our coal to the buyer. 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 require us to transport coal first by rail to a seaborne export terminal and then load the coal onto the buyers’ ships. In certain circumstances, the cost of transporting our coal to international buyers can be as much as twice the cost of transporting our coal to domestic buyers.

 

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Depreciation, Depletion and Amortization. Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the estimated life of the developed mineral reserves. Property, plant and equipment are recorded at cost and are generally expensed on a straight-line basis over the useful life of the asset. Costs that extend the useful life or increase the productivity of the assets are capitalized, while normal repairs and maintenance are expensed as incurred. Interest costs applicable to major additions are capitalized during the construction period.

Accretion on Asset Retirement Obligations. Accretion expense represents the increase in the carrying amount of our asset retirement obligations due to the passage of time.

Selling, General and Administrative. Selling, general and administrative expense consists of our general corporate overhead expenses, including, but not limited to, management and administrative labor, corporate occupancy expenses, office expenses, and professional fees.

Regulatory Environment. A variety of actions taken by regulatory agencies, including, but not limited to, climate change regulation, challenges to the issuance or renewal of our permits to operate, etc., 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.

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 US GAAP. US GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. We base these estimates on historical experience and on various other assumptions that we consider reasonable under the circumstances. On an ongoing basis we evaluate our estimates. Actual results may differ from these estimates. Of these significant accounting policies, we believe the following may involve a higher degree of judgment or complexity.

Sale-Leaseback Financing Arrangements. In the first quarter of 2009, Macoupin sold certain of its coal reserves to WPP, LLC (“WPP”), a subsidiary of Natural Resources 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 the first quarter of 2012, Sugar Camp sold certain rail facilities to HOD LLC (“HOD”), a subsidiary of NRP, and leased them back. The gross proceeds from this transaction were $50.0 million, and were used for capital expenditures, to pay down our revolving credit facility and for general corporate purposes. In both transactions, because we had continuing involvement in the assets sold, the transactions were treated as sale-leaseback financing arrangements.

Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in future expected amounts and timing of payments based on the mine plans. 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 approximately 14.2% as of December 31, 2013 and 2012, respectively, on the Macoupin sale-leaseback financing arrangement and 14.3% and 13.8% for the Sugar Camp sale-leaseback financing arrangement as of December 31, 2013 and 2012, respectively. If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant.

Prepaid Royalties. Prepaid royalties consist of recoupable minimum royalty payments under various lease agreements. As of December 31, 2013 and 2012, we had recorded on the consolidated balance sheets $79.6

 

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million and $60.5 million, respectively, of prepaid royalties which we expect to recoup in future periods. We continually evaluate our ability to recoup prepaid royalty balances which includes, among other things, assessing mine production plans, sales commitments, future coal market conditions, and remaining years available for recoupment. The contractual recoupment periods are generally five to ten years from the payment date.

Asset Retirement Obligations. Our asset retirement obligations (“ARO”) liabilities 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 8.8%, 7.6%, and 8.6% at December 31, 2013, 2012, and 2011, 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 and productivity assumptions. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled. At December 31, 2013, our balance sheet reflected asset retirement obligation of $21.2 million, including amounts classified as a current liability. We estimate the aggregate undiscounted cost of final mine closures, at 2013 costs, to be approximately $45.7 million as of December 31, 2013.

Variable Interest Entities (VIEs). We employ contractors to provide labor for our mines and coal processing facilities. In accordance with US GAAP, our consolidated financial statements include entities considered variable interest entities (“VIEs”) for which we are the primary beneficiary. These entities are deemed to be our affiliates and generally own no equipment, real property or other intangible assets and each holds a contract, and in some instances an operator assignment, to provide contract labor services solely to Foresight Energy LLC subsidiaries.

VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses, or (c) right to receive expected residual returns. VIEs must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIEs economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.

To determine a VIE’s primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE’s economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, and must therefore consolidate the entity, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests

 

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held by us and other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary.

New Accounting Pronouncements

None.

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 production, tons sold, coal sales realization, cash cost per ton sold and Adjusted EBITDA (non-US GAAP measures are defined in subsequent sections).

Results of Operations

The table below displays the Company’s results operations:

 

     Year Ended December 31,     Three Months Ended
March 31,
 
     2013     2012     2011     2014     2013  
     (In thousands)  

Coal sales

   $ 957,412      $ 845,886      $ 500,791      $ 242,723      $ 232,593   

Costs and expenses:

          

Cost of coal sales (excluding depreciation, depletion and amortization)

     363,024        309,801        174,183        93,153        79,848   

Transportation

     197,839        171,679        98,394        59,436        49,614   

Depreciation, depletion and amortization

     161,216        124,552        70,411        35,258        37,199   

Accretion on asset retirement obligations

     1,527        1,368        1,705        405        382   

Selling, general, and administrative

     32,291        41,528        38,894        9,038        9,006   

Gain on commodity contracts

     (2,392     (534     (2,395     (15,401     (452

Other operating income, net

     (280     (10,759     (791     (686     (424
  

 

 

   

 

 

   

 

 

     

Operating income

     204,187        208,251        120,390        61,520        57,420   

Other expenses:

          

Loss on early extinguishment of debt

     77,773        —          —          —          —     

Interest expense, net

     115,897        82,580        38,193        29,604        28,200   
  

 

 

   

 

 

   

 

 

     

Net income

     10,517        125,671        82,197        31,916        29,220   

Less: net income (loss) attributable to noncontrolling interests

     2,236        (160     104        613        75   
  

 

 

   

 

 

   

 

 

     

Net income attributable to controlling interests

   $ 8,281      $ 125,831      $ 82,093        31,303        29,145   
  

 

 

   

 

 

   

 

 

     

Adjusted EBITDA reconciliation:

          

Net income attributable to controlling interests

   $ 8,281      $ 125,831      $ 82,093      $ 31,303      $ 29,145   

Write-off of deferred offering costs

     —          4,276        —          —          —     

Loss on early extinguishment of debt

     77,773        —          —          —          —     

Interest expense, net(1)

     115,897        82,580        38,193        29,604        28,200   

Depreciation, depletion and amortization

     161,216        124,552        70,411        35,258        37,199   

Accretion on asset retirement obligations

     1,527        1,368        1,705        405        382   
  

 

 

   

 

 

   

 

 

     

Adjusted EBITDA(2)

   $ 364,694