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As filed with the Securities and Exchange Commission on April 24, 2014

Registration No. 333-179304

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

AMENDMENT NO. 6

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		Proposed maximum aggregate offering price(1)(2)		Amount of registration fee(3)
Common units representing limited partner interests		$300,000,000		$34,380

(1)	Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

(2)	Includes common units that the underwriters have the option to purchase to cover over-allotments, if any.

(3)	Previously paid.

 

 

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 APRIL 24, 2014

PRELIMINARY PROSPECTUS

FORESIGHT ENERGY LP

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             common units in this offering. We currently expect the initial public offering price to be between $         and $         per common unit.

The underwriters have the option to purchase up to             additional common units from us at the initial public offering price, less the underwriting discounts and a structuring fee payable to             , 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 23.

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 $         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     % of the gross proceeds of this offering payable to             . 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 and/or our Longwall Financing Arrangements (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

 

 

                    , 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			23
USE OF PROCEEDS			57
DILUTION			58
CAPITALIZATION			59
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			60
HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS			72
SELECTED HISTORICAL FINANCIAL INFORMATION			86
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			89
BUSINESS			110
THE COAL INDUSTRY			131
ENVIRONMENTAL AND OTHER REGULATORY MATTERS			150
MANAGEMENT			156
EXECUTIVE COMPENSATION			160
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			164
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			171
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			183
DESCRIPTION OF INDEBTEDNESS			184
DESCRIPTION OF COMMON UNITS			190
THE PARTNERSHIP AGREEMENT			192
UNITS ELIGIBLE FOR FUTURE SALE			206
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			208
INVESTMENT IN FORESIGHT ENERGY LP BY EMPLOYEE BENEFIT PLANS			224
UNDERWRITING			226
LEGAL MATTERS			232
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM			232
EXPERTS—COAL RESERVES			232
WHERE YOU CAN FIND ADDITIONAL INFORMATION			232
MARKET AND INDUSTRY DATA AND FORECASTS			233
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			233
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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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 $         per unit, or $         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 $         million per quarter, or $         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 March 31, 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 cost of compliance with new environmental laws;

 

•

the cost of power needed to run our mines;

 

•

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;

 

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•

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.”

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

 

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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 “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 December 31, 2013, our total long-term indebtedness (excluding our sale-leaseback financing obligations) was approximately $1,519.2 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 $238.5 million under our Revolving Credit Facility (including $2.5 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;

 

•

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.

 

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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 of the 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.”

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 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/disposal capacity for the operations. The proposed plan requires capital expenditures of $20 million, of which approximately $7.5 million has been invested through December 31, 2013 for the construction of the treatment facilities, in addition to

 

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timely approvals from the relevant 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 coal reserves that are economically recoverable, 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;

 

•

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;

 

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•

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 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.

 

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

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

 

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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;

 

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Future coal prices, operating costs and capital expenditures;

 

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

 

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Future mining technology improvements;

 

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The effects of regulation by governmental agencies;

 

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Ability to obtain, maintain and renew all required permits;

 

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Employee health and safety needs; and

 

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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.

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

 

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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. 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.

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

 

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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. Negotiations to extend existing agreements or enter into long-term agreements with this and other customers may not be successful, and such customers may not continue to purchase coal from us. If 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 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 December 31, 2013, we have recorded total asset retirement obligations on our consolidated balance sheet of approximately $21.2 million. Our estimates for this future liability are subject to change based on new or

 

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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 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

 

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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.

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 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. Our contract operators and contract transportation or

 

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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.

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

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

 

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

 

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

 

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Industrial accidents;

 

•

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

 

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

 

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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;

 

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Accidental or unexpected mine water inflows;

 

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Delays in moving our longwall equipment;

 

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Railroad derailments;

 

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•

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

 

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Environmental hazards;

 

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Interruption or loss of power, fuel, or parts;

 

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Increased or unexpected reclamation costs;

 

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Equipment availability, replacement or repair costs; and

 

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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.

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

 

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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.

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

 

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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 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.

 

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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 $         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.”

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

We are party to a transloading and storage agreement with one of our affiliates, Sitran, which provides for the unloading of coal from each of Williamson, 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 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. There is no assurance that Sitran will renew this contract, or that it will renew this contract on similar terms or terms that are favorable to us. Any failure to do so 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.

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;

 

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•

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.

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.”

 

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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 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 year ended December 31, 2013, we recognized approximately $13.6 million 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.

 

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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 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

 

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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 for new coal and oil-fired power plants, which could require partial carbon capture and sequestration. The permitting of new coal-fired power plants has also 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. 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.

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.

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.”

 

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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;

 

•

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 $         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;

 

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•

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 $         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.”

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.

 

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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 “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;

 

•

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

 

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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;

 

•

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.”

 

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

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 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

 

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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— 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 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.

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 ²⁄₃% 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     % of our common and subordinated units (or     % 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 $         per common unit.

The assumed initial public offering price of $         per common unit exceeds pro forma net tangible book value of $         per common unit. Based on the assumed initial public offering price of $         per common unit, unitholders will incur immediate and substantial dilution of $         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

 

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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 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     % and     %, 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     % and     %, 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             common units and subordinated units outstanding, which includes the              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

 

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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 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:

 

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our quarterly distributions;

 

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

 

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

 

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

 

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general economic conditions;

 

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volatility in the capital and credit markets;

 

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

 

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future sales of our common units; and

 

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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             (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 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.

 

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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.

While we generally must comply with Section 404 of the Sarbanes-Oxley Act for our fiscal year ending             , 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 . 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 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 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

 

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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 $         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.

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

 

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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 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

 

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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 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

 

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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.

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 $         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 $         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 $         million of our Term Facility and/or our Longwall Financing Arrangements to 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.

If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $         million (and the total net proceeds to us would be approximately $         million), in each case assuming an initial public offering price per common unit of $         (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 $         per common unit would increase (decrease) the net proceeds to us from this offering by $         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 December 31, 2013, 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 $         million, or $         per common unit. Net tangible book value excludes $         million of net intangible assets. 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		$
Pro forma net tangible book value per common unit before the offering(1)
Increase in net tangible book value per common unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per common unit after the offering(2)
Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)		$

 

(1)

Determined by dividing the number of units (             common units and             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.

(2)	Determined by dividing the total number of units to be outstanding after the offering (             common units and             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 $         and $        , 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)						%		$						%
Purchasers in the offering						%		$						%
Total					100.0	%		$					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 December 31, 2013 equals parent net investment, which was $         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 December 31, 2013:

 

•

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 December 31, 2013
		Actual				As Adjusted
		($ in thousands)
Cash and cash equivalents		$	23,284			$
Long-term debt(1)(2):
Senior Secured Credit Facilities:
Revolving Credit Facility		$	259,000			$
Term Facility(3)			444,602
7.875% Senior Notes due 2021(4)			595,795
5.780% Longwall Financing Arrangement			72,833
5.555% Longwall Financing Arrangement			72,187
Interim Longwall Financing Arrangement			31,616
Capital Lease Obligations—Longwall Shield Facility			43,180
Total debt		$	1,519,213			$
Partners’ capital:
Limited partners:
Common unitholders—public
Common unitholders—Foresight Reserves and a member of management(5)
Subordinated unitholders—Foresight Reserves and a member of management(5)
General partner
Total Foresight Energy LP partners’ capital
Members’ (deficit) equity:
Controlling interests		$	(157,356	)		$
Non-controlling interests			9,240
Total members’ (deficit) equity		$	(148,116	)
Total Capitalization		$	1,371,097			$

 

(1)

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 December 31, 2013 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.”

(2)	See “Description of Indebtedness” for a complete description of this indebtedness. In addition, at December 31, 2013, we had unused capacity of $238.5 million under our Revolving Credit Facility (including $2.5 million of letters of credit).

(3)	Includes unamortized debt discount of $4.3 million.

(4)	Includes unamortized debt discount of $4.2 million.

(5)	A member of management refers to Michael J. Beyer our President and Chief Executive Officer.

 

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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 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 $          per unit ($          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 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

 

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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 $         per unit for each whole quarter, or $         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 $         million per quarter, or $         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				$				$
Subordinated units
Total				$				$

 

(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 $         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                     , 2014. We will adjust the quarterly distribution for the period after the closing of this offering through                     , 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 $         per common and subordinated unit each quarter for the twelve months ending March 31, 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, 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 March 31, 2015.

Unaudited Pro Forma Cash Available for Distribution

The following table illustrates, on a pro forma basis for the year ended December 31, 2013, 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 would have been approximately $169.7 million. This amount would have enabled us to make an annualized distribution of 100% of the minimum quarterly distribution on 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
		($ and tons in thousands, except weighted average coal sales price per ton)
Operating Data:
Coal produced in tons			17,991
Decrease (increase) to coal inventory in tons			598
Coal purchased in tons			—
Coal sales in tons			18,589
Weighted average coal sales price per ton		$	51.50
Financial Data:
Coal sales		$	957,412
Costs and expenses:
Cost of coal sales (excluding depreciation, depletion and amortization)		$	363,024
Transportation expense			197,839
Depreciation, depletion and amortization			161,216
Accretion on asset retirement obligations			1,527
Selling, general and administrative			32,291
Other operating (income) expense, net			(280	)
Gain on commodity contracts			(2,392	)
Total costs and expenses		$	753,225
Operating income		$	204,187
Interest and other income (expense):
Interest expense		$	115,897
Loss on early extinguishment of debt			77,773
Net income		$	10,517
Less: net income attributable to noncontrolling interests			2,236
Net income attributable to controlling interests		$	8,281

 

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		Year Ended December 31, 2013
		($ in thousands, except distributions per unit)
Net income attributable to controlling interests		$	8,281
Plus:
Loss on early extinguishment of debt			77,773
Depreciation, depletion and amortization			161,216
Accretion on asset retirement obligations			1,527
Interest expense, net			115,897
Adjusted EBITDA(1)		$	364,694
Less:
Incremental selling, general and administrative expense(2)		$	4,000
Cash interest expense			114,621
Maintenance capital expenditures			76,402
Expansion capital expenditures			134,324
Plus:
Borrowings or cash on hand for expansion capital expenditures(3)		$	134,324
Cash available for distribution		$	169,671
Minimum quarterly distribution per unit (annualized)		$
Distributions (annualized):
Distributions to common unitholders		$
Distributions to subordinated units
Total distributions
Excess		$
Interest Coverage Ratio(4)			3.18x
Minimum Interest Coverage Ratio			2.00x
Net Senior Secured Leverage Ratio(4)			2.47x
Maximum Net Senior Secured Leverage Ratio			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 that are not reflected in our unaudited pro forma consolidated financial statements.

(3)	Includes $23.3 million in cash, $31.6 million of proceeds from an interim longwall financing arrangement and $79.4 million pro forma adjustment to the borrowings under our 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, 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.

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.

 

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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 March 31, 2015. We forecast that our cash available for distribution generated during the twelve months ending March 31, 2015 will be approximately $190.8 million. This amount would be sufficient to pay the minimum quarterly distribution of $         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 March 31, 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 March 31, 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 $         per unit each quarter (or $         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 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 June 30, 2014				Quarter Ending September 30, 2014				Quarter Ending December 31, 2014				Quarter Ending March 31, 2015				Twelve Months Ending March 31, 2015
		($ and tons in thousands, except average coal price)
Operating Data:
Coal produced in tons			5,536				5,335				6,066				6,201				23,139
Decrease (increase) to coal inventory in tons			(318	)			837				(103	)			(39	)			377
Coal purchased in tons			—				—				—				—				—
Coal sales in tons			5,218				6,173				5,963				6,162				23,516
Coal sales in tons—committed			4,805				5,827				5,275				3,800				19,707
Weighted average coal sales price per ton—committed		$	51.75			$	52.45			$	52.74			$	53.34			$	52.53
Coal sales in tons—uncommitted			413				346				689				2,362				3,809
Weighted average coal sales price per ton—uncommitted		$	38.29			$	43.75			$	40.33			$	47.22			$	44.69
Financial Data:
Coal sales—committed		$	248,646			$	305,611			$	278,181			$	202,719			$	1,035,157
Coal sales—uncommitted			15,802				15,135				27,766				111,520				170,223
Total revenues		$	264,448			$	320,745			$	305,947			$	314,239			$	1,205,379
Costs and expenses:
Cost of coal sales (excluding depreciation, depletion and amortization)		$	110,235			$	134,334			$	130,347			$	138,064			$	512,979
Transportation expense			58,181				67,692				64,490				74,000				264,363
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				10,000				10,300				40,300
Other operating income (expense), net			—				—				—				—				—
Gain (loss) on commodity contracts			—				—				—				—				—
Total costs and expenses		$	223,035			$	256,645			$	249,456			$	266,983			$	996,118
Operating income		$	41,413			$	64,100			$	56,491			$	47,256			$	209,261
Interest and other income (expense):
Interest expense		$	29,483			$	28,875			$	28,887			$	28,533			$	115,777
Interest income			—				—				—				—				—
Net income		$	11,930			$	35,225			$	27,604			$	18,723			$	93,483
Less: net income attributable to noncontrolling interests			—				—				—				—				—
Net income attributable to controlling interests		$	11,930			$	35,225			$	27,604			$	18,723			$	93,483

 

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		Quarter Ending June 30, 2014				Quarter Ending September 30, 2014				Quarter Ending December 31, 2014				Quarter Ending March 31, 2015				Twelve Months Ending March 31, 2015
		($ in thousands, except distributions per unit)
Net income attributable to controlling interests		$	11,930			$	35,225			$	27,604			$	18,723			$	93,483
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			29,483				28,875				28,887				28,533				115,777
Adjusted EBITDA(1)		$	86,032			$	108,719			$	101,110			$	91,875			$	387,736
Less:
Cash interest expense		$	16,934			$	39,504			$	16,329			$	39,172			$	111,939
Maintenance capital expenditures			21,255				21,255				21,255				21,255				85,020
Expansion capital expenditures			27,604				12,568				6,215				4,027				50,414
Plus:
Borrowings or cash on hand for expansion capital expenditures(2)		$	27,604			$	12,568			$	6,215			$	4,027			$	50,414
Cash available for distribution		$	47,843			$	47,960			$	63,526			$	31,448			$	190,777
Minimum quarterly and annual distributions per unit		$				$				$				$				$
Distributions:
Distributions to common unitholders		$				$				$				$				$
Distributions to subordinated unitholders
Total distributions
Excess (shortfall)(3)		$				$				$				$				$
Interest Coverage Ratio(4)			2.97x				3.14x				3.17x				3.35x				3.35x
Minimum Interest Coverage Ratio			2.00x				2.00x				2.00x				2.00x				2.00x
Net Senior Secured Leverage Ratio(4)			1.70x				1.58x				1.55x				1.53x				1.53x
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 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.

 

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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 March 31, 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 March 31, 2015 will be approximately $1.2 billion, as compared to approximately $957.4 million for the year ended December 31, 2013. Our forecast is based primarily on the following assumptions:

 

•

We estimate that we will produce approximately 23.1 million tons of coal for the twelve months ending March 31, 2015 as compared to approximately 18.0 million tons we produced for the year ended December 31, 2013. Production from our coal operations for the forecasted period is expected to increase from the year ended December 31, 2013 based on increased production at our Sugar Camp mining complex due to the addition of a second longwall system beginning May 2014 and increased production at our other mines. Combined they are expected to add 5.1 million tons of total production compared to the year ended December 31, 2013. 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 23.5 million tons of coal for the year ending March 31, 2015 as compared to the 18.6 million tons we sold for the year ended December 31, 2013. Coal sold for the forecasted period is expected to increase from the year ended December 31, 2013 based on additional production from longwall mining systems at our Sugar Camp and Hillsboro complexes.

 

•

We estimate that our coal revenues per ton will be $51.26 for the twelve months ending March 31, 2015, as compared to $51.50 for the year ended December 31, 2013. The decrease is primarily due to supply contracts that expired in 2013 at favorable prices compared to lower market prices in 2014.

 

•

The forecast includes commitments to sell approximately 19.7 million tons, or approximately 84% of our forecasted sales at a weighted average price of $52.53 per ton, during the forecasted period.

 

•

We are also forecasting to sell approximately 3.8 million tons, or approximately 16% 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 $44.69. 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 $513.0 million for the twelve months ending March 31, 2015, as compared to approximately $363.0 million for the year ended December 31, 2013. 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 is attributable primarily to increased production as well as a forecasted increase in cash cost per ton.

 

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We forecast that our cash cost of coal sales on a per ton basis for the twelve months ending March 31, 2015 will be $21.81, as compared to $19.52 for the year ended December 31, 2013. 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. Our forecasted cost of coal sales could vary significantly because of the large number of variables, many of which are beyond our control.

Transportation. We forecast transportation expense to be approximately $264.4 million for the twelve months ending March 31, 2015, as compared to approximately $197.8 million for the year ended December 31, 2013. The increase in transportation expense as compared to the year ended December 31, 2013 is due to an increase in tons sold as a result higher production.

Depreciation, Depletion and Amortization. We forecast depreciation, depletion and amortization expense to be approximately $177.2 million for the twelve months ending March 31, 2015, as compared to approximately $161.2 million for the year ended December 31, 2013. The increase in depreciation, depletion and amortization expense as compared to the year ended December 31, 2013 is due to an increase in depreciation related to an additional longwall system at Sugar Camp scheduled to begin operating in May 2014.

Selling, General and Administrative. We forecast selling, general and administrative expenses to be approximately $40.3 million for the twelve months ending March 31, 2015, as compared to approximately $32.3 million for the year ended December 31, 2013. The increase in expenses as compared to the year ended December 31, 2013, 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 March 31, 2015, as compared to operating income of approximately $0.3 million for the year ended December 31, 2013.

Change in Fair Value of Commodity Contracts. For the twelve months ending March 31, 2015 we have forecast no material income from the change in fair value of commodity contracts. For the year ended December 31, 2013 we recorded income of approximately $2.4 million.

Interest Expense. We forecast interest expense of approximately $115.8 million for the twelve months ending March 31, 2015, as compared to $115.9 million for the year ended December 31, 2013. The decrease in interest expense as compared to the year ended December 31, 2013, is due to an increase in debt prior to this offering related to the 2013 Refinancing offset by a decrease in debt related to the use of proceeds from this offering.

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 March 31, 2015 based on the following assumptions:

 

•

We forecast our maintenance capital expenditures to be $85.0 million for the twelve months ending March 31, 2015, as compared to actual maintenance capital expenditures of approximately $76.4 million for the year ended December 31, 2013. The increase is primarily due to higher maintenance capital expenditures related to Sugar Camp, Hillsboro and additional expenditures necessary to maintain the new longwall system at Sugar Camp after start-up, which is scheduled to begin operating in May 2014. Previously, the capital expenditures at those mines were for expansion capital and did not include maintenance capital. These capital expenditures include the rebuild, replacement, repair and maintenance of mining equipment associated with our continuous miners and longwall systems, belts

 

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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 $50.4 million for the twelve months ending March 31, 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 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 March 31, 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                     , 2014, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $         per unit, or $         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                     , 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:

 

•

$         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 $         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);

 

•

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

 

•

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

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

 

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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.

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

 

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including but not limited to the acquisition of reserves, equipment or a new mine or the expansion of an existing 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 March 31, 2015, we expect to incur $50.4 million in expansion capital expenditures related to our fourth longwall scheduled to begin production in May 2014. 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 $         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                     , 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                     , 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                     , 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; less

 

•

any expenditures that are not operating expenditures solely because of the provision described in the last bullet point describing operating expenditures above; 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 “—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 “—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 $         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 $         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 $         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		up to $			100.0	%			0	%
First Target Distribution		above $             up to $			100.0	%			0	%
Second Target Distribution		above $             up to $			85.0	%			15.0	%
Third Target Distribution		above $             up to $			75.0	%			25.0	%
Thereafter		above $			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 $        .

 

		Quarterly Distribution Per Unit Prior to Reset		Unitholders				IDR Holders				Quarterly Distribution Per Unit Following Hypothetical Reset
First Target Distribution		up to $			100.0	%			0.0	%		above $             up to $             (1)
Second Target Distribution		above $             up to $			85.0	%			15.0	%		above $             up to $             (2)
Third Target Distribution		above $             up to $			75.0	%			25.0	%		above $             up to $             (3)
Thereafter		above $			50.0	%			50.0	%		above $

 

(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             common units outstanding and the distribution to each common unit would be $         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

First Target Distribution

up to $

—

—

Second Target Distribution

above $             up to $

—

Third Target Distribution

above $             up to $

—

Thereafter

above $

—

$

—

$

$

$

 

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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 common units outstanding and the distribution to each common unit would be $        . 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 $         million, by (2) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $        .

 

After Reset

Quarterly Distributions Per Unit

Distributions to Common Unitholders

Cash Distributions to IDR Holders

Total Distributions

Common Units(1)

Incentive Distribution Rights

Total

First Target Distribution

up to $

—

Second Target Distribution

above $             up to $

—

—

—

—

—

Third Target Distribution

above $             up to $

—

—

—

—

—

Thereafter

above $

—

—

—

—

—

$

—

$

$

 

(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 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.

 

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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.

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

 

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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.

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.

 

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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 information derived from our audited financial statements for the years ended December 31, 2013, 2012, 2011, 2010 and 2009. 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.

 

		For the Years Ended December 31,
		2013				2012				2011				2010				2009
		(in thousands, except per ton sold data)
Statements of Operations
Revenues
Coal sales		$	957,412			$	845,886			$	500,791			$	362,592			$	271,249
Costs and expenses
Cost of coal sales (excluding depreciation, depletion and amortization)			363,024				309,801				174,183				130,610				101,528
Transportation			197,839				171,679				98,394				58,482				48,933
Depreciation, depletion and amortization			161,216				124,552				70,411				55,647				39,017
Accretion on asset retirement obligations			1,527				1,368				1,705				2,011				1,655
Selling, general and administrative			32,291				41,528				38,894				28,367				22,610
Other operating (income) expense, net(1)			(280	)			(10,759	)			(791	)			(2,611	)			(3,208	)
Gain on commodity contracts			(2,392	)			(534	)			(2,395	)			—				—
Operating income			204,187				208,251				120,390				90,086				60,714
Other (income) and expense:
Loss on early extinguishment of debt			77,773				—				—				—				—
Interest income			(11	)			(1	)			(6	)			(67	)			(427	)
Interest expense			115,908				82,581				38,199				40,498				47,052
Net income from continuing operations			10,517				125,671				82,197				49,655				14,089
Net loss from discontinued operations			—				—				—				(40,893	)			(50,545	)
Net income (loss)			10,517				125,671				82,197				8,762				(36,456	)
Less: Net income (loss) attributable to non-controlling interests			2,236				(160	)			104				909				246
Net income (loss) attributable to controlling interests		$	8,281			$	125,831			$	82,093			$	7,853			$	(36,702	)
Statements of Cash Flows
Net cash provided by operating activities		$	179,526			$	209,691			$	103,143			$	61,388			$	85,480
Net cash used in investing activities		$	(209,275	)		$	(207,039	)		$	(332,821	)		$	(272,117	)		$	(386,794	)
Net cash provided by (used in) financing activities		$	25,145			$	(26,525	)		$	247,988			$	196,091			$	329,604
Balance Sheet Data (at period end)
Cash and investments in available-for-sale securities		$	23,284			$	27,888			$	51,761			$	33,451			$	57,031
Property, plant, equipment and mine development, net		$	1,414,074			$	1,401,285			$	1,323,800			$	995,425			$	634,250
Total assets		$	1,710,171			$	1,695,288			$	1,546,969			$	1,131,880			$	1,036,160
Total long-term debt(2)		$	1,519,213			$	1,061,949			$	897,411			$	605,390			$	345,753
Total members’ (deficit) equity		$	(148,116	)		$	280,103			$	394,205			$	282,066			$	133,103
Other Data
Adjusted EBITDA(3)		$	364,694			$	338,607			$	192,402			$	146,835			$	101,140
Capital expenditures		$	210,726			$	209,937			$	336,020			$	277,409			$	326,525
Tons produced(4)			17,991				15,080				9,028				6,813				5,921
Tons sold(4)			18,589				14,403				8,773				6,730				5,635
Average realized price per ton sold(5)		$	51.50			$	58.73			$	57.08			$	53.88			$	48.14
Cash costs per ton sold(6)		$	19.53			$	21.51			$	19.85			$	19.41			$	18.02

 

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(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 and $193.4 million for the years ended December 31, 2013 and 2012 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 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,
		2013				2012				2011				2010				2009
Net income from continuing operations attributable to controlling interests		$	8,281			$	125,831			$	82,093			$	48,746			$	13,843
Write-off of deferred offering costs			—				4,276				—				—				—
Loss on early extinguishment of debt			77,773				—				—				—				—
Interest income			(11	)			(1	)			(6	)			(67	)			(427	)
Interest expense			115,908				82,581				38,199				40,498				47,052
Depreciation, depletion and amortization			161,216				124,552				70,411				55,647				39,017
Accretion on asset retirement obligations			1,527				1,368				1,705				2,011				1,655
Adjusted EBITDA		$	364,694			$	338,607			$	192,402			$	146,835			$	101,140

 

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(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. 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 is currently in development with longwall production expected to commence in May 2014. 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.

(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 is currently under development, with longwall operations expected to commence in the second quarter of 2014. 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 is expected to begin production in May 2014;

 

•

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 supported by a flexible conveyor train (“FCT”) unit. 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 is expected to commence longwall operations in the

 

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second quarter of 2014. The timing of the additional development is dependent on several factors, including, but not limited to, permitting, demand, 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 competition from natural gas and high inventory levels at utilities, which in combination reduced demand from coal-fired plants. International prices have also declined as a result of excess supply in the market place. 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 impact our ability to mine and ship our coal and our customers’ ability to take delivery of coal.

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. Development of a second longwall mine at the Sugar Camp complex is currently in progress, with longwall operations expected to commence in May 2014.

Contract Position. We sell a significant portion of our coal under agreements with terms that range from one to seven years. As of December 31, 2013, we had 17.8 million tons committed and priced and 2.4 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 109 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 years ended December 31, 2013, 2012, and 2011, export tons represented 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.

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.

 

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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. Development of a second longwall mine at the Sugar Camp complex is currently in progress, with longwall operations expected to commence in the second quarter of 2014. 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:

 

		For the Year Ended December 31,
		2013				2012				2011
		(in millions)
Tons produced—operating mines			18.0				15.1				9.0
Tons produced—development mines			0.8				1.2				1.4
*Total			18.8				16.3				10.4

 

*	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 during this month. 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.

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

 

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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.

In April 2013, the Illinois Environmental Protection Agency (“IEPA”) issued Sugar Camp two violation notices regarding non-compliant effluent discharge from the mine site and improper dilution of high-chloride water. We believe that we are now in compliance with Sugar Camp’s permit and have proposed a plan which will resolve all outstanding violations and provide long term water treatment and disposal capacity for the operations. The proposed plan requires capital expenditures of $20 million, of which approximately $7.5 million has been invested through December 31, 2013 for the construction of the treatment facilities, in addition to timely approvals from the relevant Illinois regulatory agencies.

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

 

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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 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 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.

 

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To determine a VIE’s primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE’s economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, and must therefore consolidate the entity, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests held by us and other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary.

New Accounting Pronouncements

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,
		2013				2012				2011
		(In thousands)
Coal sales		$	957,412			$	845,886			$	500,791
Costs and expenses:
Cost of coal sales (excluding depreciation, depletion and amortization)			363,024				309,801				174,183
Transportation			197,839				171,679				98,394
Depreciation, depletion and amortization			161,216				124,552				70,411
Accretion on asset retirement obligations			1,527				1,368				1,705
Selling, general, and administrative			32,291				41,528				38,894
Gain on commodity contracts			(2,392	)			(534	)			(2,395	)
Other operating income, net			(280	)			(10,759	)			(791	)
Operating income			204,187				208,251				120,390
Other expenses:
Loss on early extinguishment of debt			77,773				—				—
Interest expense, net			115,897				82,580				38,193
Net income			10,517				125,671				82,197
Less: net income (loss) attributable to noncontrolling interests			2,236				(160	)			104
Net income attributable to controlling interests		$	8,281			$	125,831			$	82,093
Adjusted EBITDA reconciliation:
Net income attributable to controlling interests		$	8,281			$	125,831			$	82,093
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
Depreciation, depletion and amortization			161,216				124,552				70,411
Accretion on asset retirement obligations			1,527				1,368				1,705
Adjusted EBITDA(2)		$	364,694			$	338,607			$	192,402

 

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(1)

Interest expense 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. See “Certain Relationships and Related Party Transactions” and our consolidated historical financial statements, along with the notes thereto, included elsewhere in this prospectus.

(2)

Adjusted EBITDA is defined as earnings from continuing operations (as applicable) attributable to controlling interests before interest, income 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 limitation 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 users to perform their own analysis of our operating results.

Overview

Our net income for 2013 decreased substantially as compared to the prior year largely due to $77.8 million of expenses incurred to refinance our debt and higher interest expense during the period. In August 2013, we completed a successful refinancing of our debt under which we upsized our credit facility to $500 million and extended the maturity to August 2018 and we issued a $450 million term loan and $600 million of 7.875% Senior Notes due 2021. As part of this transaction we redeemed the previously outstanding $600 million of 9.625% Senior Notes due in 2017. We used the net proceeds from the financing to make a $375 million distribution to our members and the financing enabled us to extend out the maturities on our long-term debt and capitalize on historically low interest rates.

Our operating mines produced 18.0 million tons of coal during the year ended December 31, 2013, representing a 19% increase over the prior year. Our production has increased significantly from 2012 due to our Sugar Camp and Hillsboro longwall mines emerging from development in March 2012 and September 2012, respectively. Our low cost position has enabled us to grow our sales volume in a modestly improving domestic market. However, international coal pricing continues to remain weak. Our Adjusted EBITDA increased $26.1 million, or 7.7%, over the prior year to $364.7 million for the year ended December 31, 2013.

 

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Comparison of Year Ended December 31, 2013 to Year Ended December 31, 2012

Coal Sales. The following table summarizes coal sales information during the years ended December 31, 2013 and 2012:

 

		For the Year Ended December 31,
		2013				2012
		(In thousands, except per ton data)
Coal sales		$	957,412			$	845,886
Tons sold(1)			18,589				14,403
Coal sales realization(2)		$	51.50			$	58.73

 

(1)	Excludes tons sold of 0.8 million tons and 1.4 million tons during the years ended December 31, 2013 and 2012, respectively, for mines under development.

(2)	Coal sales realization is defined as coal sales divided by tons sold.

Coal sales for the year ended December 31, 2013 of $957.4 million represented an increase of $111.5 million, or 13.2%, compared to coal sales of $845.9 million for the year ended December 31, 2012. The increase in coal sales was primarily due to a 4.2 million ton increase in sales volumes driven by the increased production at Sugar Camp and Hillsboro, which came out of development on March 1, 2012 and September 1, 2012, respectively. Partially offsetting the volume increase was a $7.23 per ton decrease in coal sales realization in 2013 due to an increase in domestic shipments at lower prices relative to international sales as well as lower realization on both domestic and international shipments versus prior year due to the roll-off of some high-priced contracts. Tons sold domestically increased 4.5 million tons and tons sold internationally decreased 0.3 million tons as compared to the year ended December 31, 2012. Domestic shipments represented 66% of tons sold by our operating mines for the year ended December 31, 2013, as compared to 54% in the prior year. The increased mix of domestic shipments during this period reflects the relative strength of the domestic market to that of the international market on a netback price to the mine.

Cost of Coal Sales (excluding depreciation, depletion and amortization). The following table summarizes cost of coal sales (excluding depreciation, depletion and amortization) information for the years ended December 31, 2013 and 2012:

 

		For the Year Ended December 31,
		2013				2012
		(In thousands, except per ton data)
Cost of coal sales (excluding depreciation, depletion and amortization)		$	363,024			$	309,801
Tons sold(1)			18,589				14,403
Cash cost per ton sold(2)		$	19.53			$	21.51
Tons produced			17,991				15,080

 

(1)	Excludes tons sold of 0.8 million tons and 1.4 million tons during the years ended December 31, 2013 and 2012, respectively, for mines under development.

(2)	Cash cost per ton sold is defined as cost of coal sales (excluding depreciation, depletion and amortization) divided by tons sold.

Cost of coal sales (excluding depreciation, depletion and amortization) for the year ended December 31, 2013 was $363.0 million, representing an increase of $53.2 million from $309.8 million for the year ended December 31, 2012. The increase in cost of coal sales (excluding depreciation, depletion and amortization) is due to a 29.1% increase in sales volume, offset partially by a $1.98 per ton decrease in the cash cost per ton sold. Cash cost per ton sold was lower during the year ended December 31, 2013 due to a full year of operation of our

 

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Hillsboro mine which came out of development on September 1, 2012 and substantially improved cash costs at Sugar Camp due to lower production costs versus the prior year. During 2013, Sugar Camp’s operating mine produced with only one supporting continuous miner unit versus two continuous miner units in the prior year. The remaining two continuous miner units are dedicated to the second longwall mine currently in development, which has benefited our cash cost per ton sold for the year ended December 31, 2013. Development costs are capitalized and therefore not recognized in our cost of coal sales (excluding depreciation, depletion and amortization).

Transportation. Our cost of transportation for the year ended December 31, 2013 was $197.8 million, an increase of 15.2% compared to $171.7 million for the year ended December 31, 2012. The substantial increase in domestic sales volume, principally through the Sitran terminal which requires us to pay third-party costs to move coal to the terminal, drove the increase in transportation expense over the prior year, offset partially by a decline in international sales volumes and incremental rail rebates earned during the year ended December 31, 2013.

Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expenses for the year ended December 31, 2013 were $161.2 million, an increase of $36.7 million over depreciation, depletion and amortization expenses of $124.6 million for the year ended December 31, 2012. This increase was primarily the result of Sugar Camp and Hillsboro depreciation and amortization expenses being recorded to our consolidated statements of operations for the full year as Sugar Camp and Hillsboro began production on March 1, 2012 and September 1, 2012, respectively. The year ended December 31, 2012 includes only ten months of depreciation and amortization expenses for Sugar Camp and four months of depreciation and amortization expenses for Hillsboro.

Selling, General and Administrative. Our selling, general and administrative expenses for the year ended December 31, 2013 were $32.3 million, a decrease of $9.2 million compared to our selling, general and administrative expenses of $41.5 million for the year ended December 31, 2012. This decrease was due primarily to lower discretionary bonuses paid in 2013 as well as the write-off of $4.3 million in direct costs incurred to pursue an initial public offering during the year ending December 31, 2012.

Gain on Commodity Contracts. We recorded a gain on commodity contracts of $2.4 million during the year ended December 31, 2013, as compared to a gain of $0.5 million for the year ended December 31, 2012. Of the $2.4 million recorded net recorded gain, $2.5 million relates to contracts that are still outstanding as of December 31, 2013 and is therefore an unrealized gain.

Other Operating Income, Net. In April 2012, we entered into a $10.0 million settlement agreement with a customer related to a coal supply agreement. The settlement proceeds were recorded in other operating loss (income), net in our consolidated statements of operations during the year ended December 31, 2012.

Interest Expense, Net. Our interest expense, net for the year ended December 31, 2013 was $115.9 million, an increase of $33.3 million, or 40.3%, compared to interest expense, net of $82.6 million for the year ended December 31, 2012. Interest expense increased as compared to 2012 due primarily to a decrease in the amount of interest expense capitalized, the incremental interest expense related to the $200 million of additional 9.625% Senior Notes outstanding during 2013, a full year of interest on the $50.0 million sale-leaseback transaction of Sugar Camp’s loadout facility entered into during March 2012, and the interest on the $450.0 million Term Notes issued on August 23, 2013. Partially offsetting these increases was lower interest expense on our revolving credit facility due to lower average borrowings under this arrangement as well as a lower interest rate on our Revolving Credit Facility and 2021 Senior Notes as a result of the 2013 Refinancing. For the year ended December 31, 2013, $3.6 million in interest expense was capitalized compared to $19.0 million for the year ended December 31, 2012, as several large development projects transitioned from development during 2012.

Loss on Early Extinguishment of Debt. For the year ended December 31, 2013, we recorded a $77.8 million loss on the early extinguishment of debt to redeem our 2017 Senior Notes and to write off certain unamortized debt issuance costs and the unamortized net debt premium of the extinguished debt.

 

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Net Income. We realized net income of $10.5 million for the year ended December 31, 2013, a decrease of $115.2 million from net income of $125.7 million for the year ended December 31, 2012, due to principally to the $77.8 million loss recorded on the early extinguishment of debt to redeem our 2017 Senior Notes and to write off certain unamortized debt issuance costs and $33.3 million in higher recorded interest expense during the year ended December 31, 2013 as discussed above.

Net Income (Loss) Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests is due primarily to the throughput agreement with Hillsboro Transport, LLC (“Hillsboro Transport”), which we consolidate as a VIE, entered into in August 2013 under which Hillsboro pays Hillsboro Transport a fee of $0.99 for each ton of coal passed through the loadout.

Adjusted EBITDA. We realized Adjusted EBITDA of $364.7 million for the year ended December 31, 2013, a $26.1 million, or 7.7%, increase from our Adjusted EBITDA in 2012 of $338.6 million. The increase is largely attributed to higher production and sales levels during 2013 offset by lower coal sales realization during 2013, in addition to the other factors discussed above.

Comparison of Year Ended December 31, 2012 to Year Ended December 31, 2011

Coal Sales. The following table summarizes coal sales information during the years ended December 31, 2012 and 2011:

 

		For the Year Ended December 31,
		2012				2011
		(In thousands, except per ton data)
Coal sales		$	845,886			$	500,791
Tons sold(1)			14,403				8,773
Coal sales realization(2)		$	58.73			$	57.08

 

(1)	Excludes tons sold of 1.4 million tons and 0.9 million tons during the years ended December 31, 2012 and 2011, respectively, for mines under development.

(2)	Coal sales realization is defined as coal sales divided by tons sold.

Coal sales for the year ended December 31, 2012 of $845.9 million represented an increase of $345.1 million, or 68.9%, compared to coal sales of $500.8 million for the year ended December 31, 2011. The increase in coal sales was due to an increase in sales volume, as well as a slight increase in the average realization price per ton sold. We recognized coal sales volumes of 14.4 million tons during the year ended December 31, 2012, compared to 8.8 million tons during the year ended December 31, 2011. The increased sales volume is attributable to increased production at Sugar Camp and Hillsboro, which came out of development on March 1, 2012 and September 1, 2012, respectively. The $1.65 per ton increase in coal sales realization is due to a higher volume of tons exported, offset partially by a decrease in our realization per ton on international shipments as compared to the year ended December 31, 2011.

Cost of Coal Sales (excluding depreciation, depletion and amortization). The following table summarizes cost of coal sales (excluding depreciation, depletion and amortization) information for the years ended December 31, 2012 and 2011:

 

		For the Year Ended December 31,
		2012				2011
		(In thousands, except per ton data)
Cost of coal sales (excluding depreciation, depletion and amortization)		$	309,801			$	174,183
Tons sold(1)			14,403				8,773
Cash cost per ton sold(2)		$	21.51			$	19.85
Tons produced			15,080				9,028

 

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(1)	Excludes tons sold of 1.4 million tons and 0.9 million tons during the years ended December 31, 2012 and 2011, respectively, for mines under development.

(2)	Cash cost per ton sold is defined as cost of coal sales (excluding depreciation, depletion and amortization) divided by tons sold.

Cost of coal sales (excluding depreciation, depletion and amortization) for the year ended December 31, 2012 was $309.8 million, an increase of $135.6 million from our cost of coal sales (excluding depreciation, depletion and amortization) of $174.2 million for the year ended December 31, 2011. Approximately $111.8 million of the increase in cost of coal sales (excluding depreciation, depletion and amortization) is due to a 64.2% increase in sales volume. The remaining increase is attributed to a $1.66 per ton increase in the cash cost per ton sold from $19.85 per ton during the year ended December 31, 2011 to $21.51 per ton for the year ended December 31, 2012. The higher cash cost per ton sold is partially attributed to adverse geological conditions that were encountered periodically at our Sugar Camp and Macoupin mines during 2012, which resulted in higher supply costs and lower production levels thereby increasing the per ton cost of production as there was less tons produced to absorb operating costs.

Transportation. Our cost of transportation for the year ended December 31, 2012 was $171.7 million, an increase of $73.3 million, or 74.5%, compared to $98.4 million for the year ended December 31, 2011. This increase in transportation expense is due to the 64.2% increase in sales volumes over the prior year, a higher percentage of export shipments, and liquidated damages charges recording during 2012 for failing to meet minimum contractual throughput thresholds under certain of our transportation contracts.

Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expenses for the year ended December 31, 2012 were $124.6 million, an increase of $54.1 million over depreciation, depletion and amortization expenses of $70.4 million for the year ended December 31, 2011. This increase was primarily the result of Sugar Camp depreciation, depletion and amortization expenses being recorded to our consolidated statement of operations for the year ended December 31, 2012 as Sugar Camp completed development of its first longwall mine and began production on March 1, 2012. The year ended December 31, 2012 also includes four months of depreciation, depletion and amortization for Hillsboro, which emerged from development on September 1, 2012. Also contributing to the increase was $7.3 million in amortization of subsidence rights recorded during the year ended December 31, 2012.

Selling, General and Administrative. Our selling, general, and administrative expenses for the year ended December 31, 2012 were $41.5 million, an increase of $2.6 million compared to our selling, general, and administrative expenses of $38.9 million for the year ended December 31, 2011. Our selling, general, and administrative expenses were higher due to additional compensation expense during the year ended December 31, 2012 and the write-off of directs costs incurred to pursue an initial public offering. While we have not indefinitely abandoned the pursuit of an IPO, US GAAP required that these costs be expensed given the IPO was not actively pursued for a prolonged period. Partially offsetting these increases was a period over period increase in the capitalization of direct costs to mine development from the combined impact of the mines approaching their production phase and the separation of our support functions between the mine and corporate which allowed greater precision in determining direct costs to be capitalized during development.

Gain on Commodity Contracts. We realized a gain on the settlement of outstanding commodity contracts of $2.4 million during the year ended December 31, 2011, as compared to a gain of $0.5 million to adjust outstanding coal commodity contracts to fair market value during the year ended December 31, 2012.

Other Operating Income, Net. In April 2012, we entered into a settlement agreement with a customer related to a coal supply agreement dating back to 2009. Under the terms of the settlement agreement, the customer paid us $10.0 million. We have no future obligations under the settlement or original coal supply agreements. The settlement proceeds were recorded in other operating income, net in our consolidated statements of operations. There were no similar settlements during the year ended December 31, 2011.

 

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Interest Expense, Net. Our interest expense for the year ended December 31, 2012 was $82.6 million, an increase of $44.4 million, or 116.2%, compared to interest expense of $38.2 million for the year ended December 31, 2011. Interest expense increased primarily due to a decrease in the amount of interest expense capitalized during 2012 and higher outstanding balances on our Revolving Credit Facility and longwall financing arrangements as well as the incremental interest expense related to our $200 million 2017 Senior Notes offering on October 31, 2012. For the year ended December 31, 2012, $19.0 million in interest expense was capitalized compared to $36.7 million for the year ended December 31, 2011, as several projects transitioned into production during 2012. Additionally, interest expense on the Macoupin sales-leaseback financing transaction was lower in 2011 as a result of a change in mine plan during the fourth quarter of 2011, which resulted in a reduction of the estimated effective interest rate and, therefore, a reduction in interest expense of $10.7 million.

Net Income. We realized net income of $125.7 million for the year ended December 31, 2012, an increase of $43.5 million from net income of $82.2 million for the year ended December 31, 2011, due to higher production and sales levels during 2012 and the other factors stated above.

Adjusted EBITDA. We realized Adjusted EBITDA of $338.6 million for the year ended December 31, 2012, a $146.2 million, or 76.0%, increase from our Adjusted EBITDA in 2011 of $192.4 million, due to higher production and sales levels during 2012 and the other factors stated above.

Liquidity and Capital Resources

On August 23, 2013, we executed a refinancing (“2013 Refinancing”) of our long-term debt under which we increased the capacity of our credit facility to $500.0 million and extended the maturity to August 2018 (“Revolving Credit Facility”), issued a $450.0 million term loan due primarily in 2020 and $600.0 million of 7.875% Senior Notes due in 2021 (“2021 Senior Notes”), and redeemed the $600.0 million of outstanding 9.625% Senior Notes which were due in 2017 (“2017 Senior Notes”). The refinancing enabled us to extend out the maturities on our long-term debt as well as take advantage of favorable interest rates. The net proceeds from the refinancing were used to make a $375.0 million cash distribution to our members. In addition, $62.0 million of assets, which included 100% of the member units of Sitran, LLC and Adena Resources, LLC and the Hillsboro Energy loadout, were distributed to our members. As a result of these distributions and the $77.8 million loss recorded on the early extinguishment of the 2017 Senior Notes, our members’ equity is in a $148.1 million deficit position as of December 31, 2013. Members’ equity being in a deficit position does not impact any of our financial debt covenants nor do we believe it will materially impact our ability to access capital markets in the future. We expect that our cash flows from operations and available capacity under our Revolving Credit Facility will continue to support our operations for the next twelve months. Future longwall development and the associated expansion capital expenditures will continue to be implemented sequentially and will be dependent on our operating cash flow and to a greater extent on our access to the capital markets. 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). In the event that the capital markets are unavailable, we are not obligated or committed to use cash for expansion capital expenditures and would adjust the timing and pace of our growth accordingly.

Our primary uses of cash include, but are not limited to, the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, production taxes, debt service costs (interest and principal), lease obligations, transportation throughput agreements and member distributions. Since inception, we have made significant investments in capital expenditures to develop our four mining complexes and related transportation infrastructure. Development of a second longwall mine at our Sugar Camp complex is currently in progress with longwall operations expected to commence in the second quarter of 2014. We anticipate funding the remaining expansion capital expenditures for development and equipment for the second longwall mine at Sugar Camp, estimated between $50.0 million and $60.0 million, primarily with internally generated cash flow and draws under our Revolving Credit Facility, as necessary. We have also entered into a contract to purchase from a vendor an additional set of longwall shields and related equipment for approximately $63.0 million, of

 

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which $31.6 million in progress payments were paid in 2013. As discussed further below, in November 2013, we obtained financing for the acquisition of these longwall shields.

The following is a summary of cash provided by or used in each of the indicated types of activities during the years ended December 31, 2013, 2012, and 2011:

 

		For the Year Ended December 31,
		2013				2012				2011
		(In thousands)
Net cash provided by operating activities		$	179,526			$	209,691			$	103,143
Net cash used in investing activities		$	(209,275	)		$	(207,039	)		$	(332,821	)
Net cash provided by (used in) financing activities		$	25,145			$	(26,525	)		$	247,988

Net cash provided by operating activities was $179.5 million for the year ended December 31, 2013, compared to $209.7 million for the year ended December 31, 2012. The decrease in cash provided by operations was primarily a result of $72.1 million of cash utilized for the early extinguishment of the 2017 Senior Notes and incremental cash interest expense, offset partially by an increase in Adjusted EBITDA as compared to the year ended December 31, 2012 and net changes in our working capital accounts.

Net cash provided by operating activities was $209.7 million for the year ended December 31, 2012, compared to $103.1 million for the year ended December 31, 2011. The increase in cash provided by operations was primarily a result of the increase in net income compared to the prior year and net changes in our working capital accounts driven by the overall increase in our operations compared to the prior year.

Net cash used in investing activities was $209.3 million for the year ended December 31, 2013, compared to $207.0 million for the year ended December 31, 2012. For the years ended December 31, 2013 and 2012, we invested $210.7 million and $209.9 million, respectively, in property, plant, equipment and development. Significant capital expenditures were spent on our first Hillsboro and Sugar Camp longwall mines during the year ended December 31, 2012 and for our second Sugar Camp longwall mine during the year ended December 31, 2013. During the years ended December 31, 2013 and 2012, we received proceeds on the sale of equipment of $0.5 million and $2.9 million, respectively. We also settled certain outstanding commodity contracts during the year ended December 31, 2013 prior to the economically hedged sale transaction occurring therefore we recorded the $1.0 million of cash proceeds as an investing activity.

Net cash used in investing activities was $207.0 million for the year ended December 31, 2012, compared to $332.8 million for the year ended December 31, 2011. For the years ended December 31, 2012 and 2011, we invested $209.9 million and $336.0 million, respectively, in property, plant, equipment, and development, principally for our Hillsboro and Sugar Camp mines. We completed development of Sugar Camp’s first longwall mine on March 1, 2012 and Hillsboro’s first longwall mine on September 1, 2012. During the years ended December 31, 2012 and 2011, we financed $5.3 million and $60.1 million, respectively, of longwall equipment which is reported as a noncash item on our consolidated statements of cash flows.

Net cash provided by financing activities was $25.1 million for the year ended December 31, 2013, compared to $26.5 million used in financing activities for the year ended December 31, 2012. During the year ended December 31, 2013, we received proceeds, net of discounts, of $1,041.2 million from the issuance of the 2021 Senior Notes and $450 million term loan, we increased borrowings under our Revolving Credit Facility by $23.0 million, and we borrowed $31.6 million under an interim longwall financing arrangement, offset by the $600.0 million extinguishment of our outstanding 2017 Senior Notes, the payment of $23.7 million in issuance costs associated with the 2013 Refinancing, the payment of $411.9 million in distributions ($25.0 million of which was accrued for at December 31, 2012), the repayments of $33.7 million of principal under our longwall financing and capital lease arrangements and a $1.1 million repayment on our term loan. The net cash used in financing activities of $26.5 million for the year ended December 31, 2012 was primarily due to $206.0 million

 

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in proceeds received from the issuance of the 2017 Senior Notes in October 2012, $50.0 million in proceeds received under the Sugar Camp sales-leaseback financing arrangement with HOD and $58.0 million in proceeds received under a financing arrangement for longwall shields, offset by $88.0 million of net repayments on our Prior Credit Facility, $26.3 million of repayments on short-term debt and our longwall financing and capital lease arrangements, and $219.4 million paid-out in member distributions.

Net cash used in financing activities was $26.5 million for the year ended December 31, 2012, compared to $248.0 million provided by financing activities for the year ended December 31, 2011. The net proceeds for the year ended December 31, 2011 was primarily due to $228.7 million in borrowings under our Prior Credit Facility and $30.0 million in member contributions.

Long-Term Debt and Sale-Leaseback Financing Arrangements

2021 Senior Notes

On August 23, 2013, we completed a $600.0 million offering of our 2021 Senior Notes. The 2021 Senior Notes bear interest of 7.875%, paid semiannually each February 15 and August 15, beginning on February 15, 2014, with the entire principal balance due on August 15, 2021. We utilized the proceeds from the issuance together with the proceeds from our Senior Secured Credit Facilities to make a $375.0 million distribution to our members, to refinance the Prior Credit Facility, to purchase, redeem or otherwise acquire all of the 2017 Senior Notes and to pay related transaction costs, fees and expenses. The 2021 Senior Notes are guaranteed on a senior unsecured basis by all of the operating subsidiaries of Foresight Energy LLC, other than Foresight Energy Finance Corporation, the co-issuer of the 2021 Senior Notes. Upon consummation of this offering, the indenture governing the 2021 Senior Notes requires Foresight Energy LP to become a guarantor under the 2021 Senior Notes. Furthermore, the indenture for the 2021 Senior Notes includes limitations on restricted payments, which may impact the timing and amount of distributions that can be paid to unitholders.

See “Description of Indebtedness—Senior Notes” for a description of the 2021 Senior Notes.

Senior Secured Credit Facilities

On August 23, 2013, Foresight Energy LLC amended and restated its Prior Credit Facility. The amended and restated credit facilities provide for the five-year Revolving Credit Facility of $500.0 million and a seven-year term loan B facility in an aggregate principal of $450.0 million (the “Term Facility” and, together with the Revolving Credit Facility, the “Senior Secured Credit Facilities”). The Revolving Credit Facility expires on August 15, 2018 and the Term Facility expires on August 15, 2020. The Senior Secured Credit Facilities are guaranteed by all of the domestic operating subsidiaries of Foresight Energy LLC. Borrowings under our Revolving Credit Facility bear interest at a rate equal to, at our option, (1) British Bankers’ Association (as published by Reuters) LIBOR plus an applicable margin ranging from 2.50% to 3.50% or (2) a base rate plus an applicable margin ranging from 1.50% to 2.50%, in each case, determined in accordance with our consolidated net leverage ratio. Borrowings under our Term Facility bear interest of 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. We are also required to pay a commitment fee of 0.50% to the lenders under the Revolving Credit Facility in respect of unutilized commitments thereunder. In addition, we are required to pay a fronting fee equal to 0.125% per annum of the amount available to be drawn under letters of credit.

At December 31, 2013, we had borrowings of $259.0 million and $2.5 million in letters of credit outstanding under the Revolving Credit Facility and $449.0 million in principal outstanding under the Term Facility. There was $238.5 million of remaining capacity under the Revolving Credit Facility as of December 31, 2013. The weighted-average effective interest rate on borrowings under the Revolving Credit Facility and Term Facility as of December 31, 2013 was 3.5% and 5.5%, respectively.

The Senior Secured Credit Facilities are subject to customary debt covenants, including a consolidated interest coverage ratio and a consolidated net senior secured leverage ratio commencing on December 31, 2013.

 

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As of December 31, 2013, our consolidated interest coverage ratio and consolidated net senior secured leverage ratio were 3.18x and 2.47x, respectively. Our covenants required a consolidated interest coverage ratio of greater than 2.00x and a consolidated net senior secured leverage ratio of less than 3.50x as of December 31, 2013. Additionally, both the 2021 Senior Notes and the Senior Secured Credit Facilities include limitations on restricted payments which may impact the timing and amount of distributions that can be paid to unitholders.

See “Description of Indebtedness—Senior Secured Credit Facilities” for a description of the Senior Secured Credit Facilities.

Longwall Financing Arrangements and Capital Lease Obligations

In November 2013, we entered into an interim funding arrangement and a master lease agreement with a lender under which the lender will finance the installment payments required under a contract with a vendor for the purchase of a set of longwall shields and related parts and equipment. The financing arrangement is up to the expected purchase price of $63.0 million and bears interest at the one-month LIBOR plus 3.95%. Upon the delivery of the longwall shields on or before April 1, 2014, the interim funding arrangement will convert to a five-year lease that we anticipate will be accounted for as a capital lease obligation. As of December 31, 2013, $31.6 million was outstanding under this arrangement.

On March 30, 2012, we entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment during the third quarter of 2012, the interim longwall finance agreement was converted into six individual leases with maturities of four and five years beginning on September 1, 2012. The capital lease obligations bear interest ranging from 5.4% to 6.3% and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2013, $43.2 million was outstanding under these capital lease obligations.

On May 14, 2010, Hillsboro Energy LLC, as the borrower, and Foresight Energy LLC, as a guarantor, entered into a credit agreement with a financial institution to provide financing for longwall mining equipment and related parts and accessories (the “Hillsboro Credit Agreement”). The financing agreement provides for financing of loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall mine equipment. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semi-annually in March and September until maturity. Principal is due in 17 equal semi-annual payments through September 30, 2020. The outstanding balance as of December 31, 2013 was $72.2 million.

On January 5, 2010, Sugar Camp, as the borrower, and Foresight Energy LLC, as a guarantor, entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories (the “Sugar Camp Credit Agreement” and, together with the Hillsboro Credit Agreement, the “Longwall Financing Arrangements”). The financing agreement also provides for financing of the loan fees and eligible interest during the construction of the longwall mining equipment. The financing arrangement is collateralized by the longwall mining equipment. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semi-annually in June and December until maturity. Principal is due in 17 equal semi-annual payments through June 30, 2020. The outstanding balance as of December 31, 2013 was $72.8 million.

The guaranty agreements between us and the lender under both Longwall Financing Arrangements contain certain financial covenants that require, among other things, maintenance of minimum amounts and compliance with debt service coverage and leverage ratios, consistent with those in our Revolving Credit Facility. We met the required financial covenants at December 31, 2013, and we believe we are currently in compliance.

See “Description of Indebtedness” for a further description of these financing arrangements.

 

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Sale-Leaseback Financing Arrangements

In the first quarter of 2009, Macoupin sold certain of its coal reserves and rail facility assets to WPP, a subsidiary of NRP, and leased them back. The gross proceeds from this transaction of $143.5 million were used for capital expenditures relating to the rehabilitation of Macoupin and for other capital items. As Macoupin has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At December 31, 2013, the outstanding balance of the sale-leaseback financing arrangement was $143.5 million.

In the first quarter of 2012, Sugar Camp sold certain rail facility assets to 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 balance and for general corporate purposes. As Sugar Camp has continuing involvement in the assets sold, the transaction is treated as a financing arrangement. At December 31, 2013, the outstanding balance of the sale-leaseback financing arrangement was $72.8 million.

Off-Balance Sheet Arrangements

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

From time to time we use bank letters of credit to secure our obligations for certain contracts and other obligations. At both December 31, 2013 and December 31, 2012, we had $2.5 million and $2.0 million, respectively, in letters of credit outstanding.

We use surety bonds to secure reclamation and other miscellaneous obligations. As of December 31, 2013, we had $45.1 million of outstanding surety bonds with third parties. These bonds were primarily in place to secure post-mining reclamation. We are not required to post collateral for these bonds.

Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

We have commodity price risk as a result of changes in the market value of our coal. We try to minimize this risk by entering into fixed price coal supply agreements and, from time to time, commodity hedge agreements. As of December 31, 2013, we had 17.8 million tons committed and priced and 2.4 million tons committed and unpriced for 2014. We have 10.1 million tons committed and priced and 5.3 million tons committed and unpriced in fiscal year 2015. As of December 31, 2013, we have 2.0 million tons economically hedged with forward coal commodity contracts tied to the API 2 ARGUS/McColoskey’s coal price index to partially mitigate coal price risk on unpriced contracts through 2016. A 10% change in the API 2 index would result in approximately an $18.0 million change in the fair value of these derivative contracts.

Interest Rate Risk

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2013, of our $1,519.2 million in long-term debt and capital lease obligations outstanding, $739.5

 

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million of outstanding borrowings had interest rates that fluctuate based on changes in market interest rate. A one percentage point increase in the interest rates related to variable interest borrowings would result in an annualized increase in interest expense of approximately $4.0 million.

Credit Risk

We have credit risk associated with our customers and counterparties in our coal sales agreements and commodity hedge contracts. We have procedures in place to assist in determining the creditworthiness and credit limits for such customers and counterparties. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established. At December 31, 2013, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

Contractual Obligations

The following is a summary of our significant future contractual obligations as of December 31, 2013, by year (in millions):

 

		Total				Less than 1 year				1-3 years				4-5 years				More than 5 years
Long-term debt (principal and interest)(1)		$	2,113.4			$	150.2			$	233.7			$	483.2			$	1,246.3
Sale-leaseback financing arrangement(2)			331.3				21.0				42.0				42.0				226.3
Capital lease obligations (principal and interest)			47.4				14.5				27.3				5.6				—
Operating lease obligations			8.2				4.7				2.6				0.6				0.3
Take-or-pay transportation arrangements(3)			568.9				68.3				142.0				135.8				222.8
Coal reserve lease and royalty obligations(4)			670.2				57.7				115.3				115.3				381.9
Unconditional purchase obligations(5)			82.9				82.9				—				—				—
Total(6)		$	3,822.3			$	399.3			$	562.9			$	782.5			$	2,077.6

 

(1)

Includes our Revolving Credit Facility, 2021 Senior Notes, Term Facility, Sugar Camp and Hillsboro Longwall Financing Arrangements and interim longwall financing arrangement. The calculated interest expense assumes no early principal repayments and is based on the actual interest rates as of December 31, 2013.

(2)	Represents the minimum annual payments required under our Macoupin and Sugar Camp sale-leaseback financing arrangements. See note 8 of our audited historical consolidated financial statements included elsewhere in this prospectus.

(3)	Principally includes our various long- and short-term take or pay arrangements associated with rail and port commitments for the delivery of coal, including amounts relating to export facilities.

(4)	Comprised of the future minimum cash payments due under our various coal reserve lease and royalty obligations.

(5)

We have open purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements are not material and typically allow for cancellation or return without penalty. The commitments in the table above relate only to committed capital purchases as of December 31, 2013.

(6)

The contractual obligation table does not include asset retirement obligations. Asset retirement obligations result primarily from statutory, rather than contractual, obligations and the ultimate timing and amount of the obligations are an estimate. As of December 31, 2013, we have $21.2 million recorded to our consolidated balance sheet for asset retirement obligations.

 

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Coal and Surface Leases and Overriding Royalties

Currently, we have several leases with both affiliated and non-affiliated parties. We believe that all such leases with both affiliated and non-affiliated parties are on arm’s-length commercial terms. See “Certain Relationships and Related Party Transactions” for a description of transactions with affiliated parties.

Williamson

Williamson Energy, LLC leases the Williamson Rail Load Out facility through a sublease with Williamson Transport LLC, owned by NRP, a related party. The term of the surface sublease is through March 12, 2018. At the end of the term, Williamson Transport has the option to renew the sublease on terms mutually agreeable to both parties. If Williamson Transport elects not to renew the sublease, Williamson has the option to buy the Williamson Rail Load Out facility for its fair market value as determined by an independent appraiser. Williamson Energy, LLC also leases the land under the Williamson Rail Load Out facility from Williamson Transport LLC under two surface leases with initial terms through October 15, 2031 and an option to extend the leases in five year increments until all the coal leased from an NRP affiliate is mined on Williamson’s premises. Williamson Transport LLC has the option to put the land to Williamson for its fair market value as determined by an independent appraiser at any time during the lease terms.

Williamson Energy, LLC has a surface sublease agreement with Savatran for the construction, operation and maintenance of the rail spur at Williamson. The lease term of the sublease is through March 12, 2018. At the end of the term, Savatran has the option to renew the sublease. Williamson Energy, LLC has the option to buy the Savatran rail spur for its fair value as determined by an independent appraiser. Williamson Energy, LLC has a coal mining lease agreement with Independence, owned by NRP. The term of this agreement runs through March 13, 2021 and the agreement can be renewed for additional five year periods or until all merchantable and mineable coal has been mined and removed. Williamson Energy, LLC is required to pay Independence the greater of 9.0% of the gross selling price or $2.85 per ton for the coal mined from the leased premises. In addition to the tonnage royalty, Williamson Energy, LLC is required to pay a quarterly minimum royalty of $416,750 payable on the 20th of January, April, July and October in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the $416,750 quarterly minimum royalty, Williamson Energy, LLC may recoup any unrecouped quarterly deficiency payments made during the preceding nineteen quarters from the excess tonnage royalty on a first paid, first recouped basis. The lease also has a provision for a wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises. Williamson Energy, LLC has an overriding royalty agreement with Independence. As such, Independence will receive an overriding royalty interest in the amount of $0.30 per ton for each ton of clean coal mined from certain mineral reserves identified in the agreement that Williamson Energy, LLC controls or in the future will control that are sold to any third party for the life of the Williamson mining operations on the identified mineral reserves.

Williamson Energy, LLC has coal mining lease agreements with WPP, an affiliate of NRP. The leases allow for the mining, processing and transporting of coal reserves located in Illinois. The terms of the coal leases include the requirement for Williamson Energy, LLC to pay WPP minimum royalties, tonnage royalties and wheelage. The term of this lease is 15 years and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed. Williamson Energy, LLC is required to pay the greater of 8.0% of the gross selling price or $2.50 per ton for the first eight million tons of clean coal mined from the leased premises in any calendar year. For all tonnage mined in excess of the eight million tons, the royalty is the greater of 5.0% of the gross selling price or $1.50 per ton of clean coal mined from the leased premises. All royalties are for clean coal mined from the Herrin No. 6 seam of coal on the leased premises. In addition to the tonnage royalty, the quarterly minimum royalty is $2 million, payable on the 20th of January, April, July and October in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the $2 million quarterly minimum royalty, Williamson Energy, LLC may recoup any unrecouped quarterly deficiency payments made during the

 

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preceding nineteen quarters from the excess tonnage royalty on a first paid, first recouped basis. Furthermore, the lease provides for an overriding royalty of $0.10 per ton on the first 8.5 million tons mined from specific coal reserves outlined in the agreement. The lease also requires a wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises.

Williamson Energy, LLC is obligated to pay overriding royalties to WPP, an affiliate of NRP, pursuant to a special warranty deed dated August 22, 1990 between their predecessors in interest, Coal Properties Corporation, Grantor and Fairview Land Company. Under this deed, WPP is owed an overriding royalty in the amount of $0.25 per ton for each ton of coal mined and sold by Williamson Energy, LLC from the mineral reserves subject to the deed.

Williamson Energy, LLC leases coal reserves from Colt, an affiliated company. The term of this lease is for ten years with six renewal periods of five years each. Williamson Energy, LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for this lease, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million per year.

Hillsboro

Hillsboro Energy LLC entered into a coal mining lease agreement on September 10, 2009, with WPP. Under such agreement, Hillsboro Energy LLC leased certain mineral rights from WPP for a term of 20 years and can renew this lease for additional five year terms, with a maximum of six terms or until all merchantable and mineable coal has been mined and removed. Hillsboro Energy LLC is required to pay WPP the greater of 8.0% of the gross selling price or $4.00 per ton and a fixed royalty in the amount set forth in the agreement for the coal mined from the leased premises. Hillsboro Energy LLC paid a minimum royalty of $3.1 million on April 20, 2010, covering the period of January 1, 2010 through March 31, 2010. For the remaining three calendar quarters in 2010 and the four calendar quarters of 2011, the quarterly minimum royalty was $3.1 million for the prior quarter’s production. Beginning with the quarterly minimum royalty due April 20, 2012, the quarterly minimum royalty is $7.5 million payable on the 20th of January, April, July and October in each year until 2031, for the prior quarter’s production. Beginning with the quarterly minimum royalty due April 20, 2032, the quarterly minimum will be $125,000 for each quarter of 2032 and each subsequent quarter. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the applicable quarterly minimum royalty, Hillsboro Energy LLC may recoup any unrecouped quarterly deficiency payments made during the preceding twenty quarters in any year other than 2010 from the excess tonnage royalty on a first paid, first recouped basis.

Hillsboro Energy LLC leases coal reserves from Colt, an affiliated company, under two leases, the terms of which are identical but that each cover different reserves. The term of these leases is for five years with seven renewal periods of five years each. Hillsboro Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for each of these leases, which is recoupable only against actual production royalty from future tons during the period of 10 years following the date on which any such minimum royalty is $4.0 million.

Macoupin

In January 2009, NRP acquired additional coal reserves and infrastructure assets related to Macoupin for $143.5 million. Simultaneous with the closing, Macoupin Energy LLC entered into a lease transaction with affiliates of NRP for mining of the mineral reserves and for the rail and loadout facilities. The mineral reserve mining lease is for a term of 20 years and can be extended for additional five-year terms limited to six such renewals. The lease requires a tonnage royalty of the greater of 8% plus $0.60 per ton and $5.40 per ton with annual minimums of $16 million. The minimum royalty is recoupable on future tons mined. If during any quarter, tonnage royalty and tonnage fees paid under the rail load-out and rail loop leases discussed below exceed

 

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$4.0 million, Macoupin Energy LLC may recoup any unrecouped quarterly deficiency payments made during the preceding twenty quarters on a first paid, first recouped basis. The Macoupin rail load-out facility and rail loop facility leases are for terms of 29 years with 16 renewals for five years each. The leases require a payment for every ton of coal loaded through the facility for the first 30 years up to 3.4 million tons along with an annual rental payment. The fee per ton is $3.00. Macoupin Energy LLC is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order.

Macoupin Energy LLC leases coal reserves from Colt, an affiliated company, under two leases, the terms of which are identical but that cover different reserves. The term of these leases is for ten years with six renewal periods of five years each. Macoupin Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for each of these leases, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million.

Effective June 1, 2012, Macoupin Energy LLC leased additional coal reserves from Colt under another lease. The term of this lease is ten years with six renewal periods of five years each. Macoupin Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for this lease, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is as follows:

 

For calendar year 2013		$	500,000
For calendar year 2014 and thereafter		$	2,000,000

Sugar Camp

In 2005, Sugar Camp Energy, LLC entered into a mineral lease with RGGS Land & Minerals Ltd., L.P. The primary term of this lease is for twenty years with two ten year renewal periods available under certain conditions described in the lease. Sugar Camp Energy, LLC is required to pay the greater of a price per ton or a single-digit percentage of the gross sales price for each ton of coal mined from the premises. In addition to the tonnage royalty, the minimum royalty for this lease, which is recoupable on future tons mined, with limitations as outlined in the lease, was $4.0 million in 2010 and 2011 and then decreased to $2.0 million for the remainder of the primary term.

Sugar Camp Energy, LLC leases coal reserves from Ruger, an affiliated company. The term of this lease is for ten years with six renewal periods of five years each. Sugar Camp Energy, LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. There is no minimum royalty associated with this lease.

Sugar Camp Energy, LLC has two overriding royalty agreements with Ruger pursuant to which Sugar Camp Energy, LLC is given the right to mine certain reserves controlled by Ruger as lessee. Pursuant to these overriding royalty agreements, the total royalty that Sugar Camp Energy, LLC will be required to pay for each ton of coal mined is equal to the difference between (i) the actual production royalty paid by Sugar Camp Energy, LLC to the lessor of the reserves under the leases assumed by Sugar Camp Energy, LLC from Ruger and (ii) the amount which is equal to eight percent of the gross selling price of the coal mined under the leases. In addition to the overriding royalty, the minimum royalty for each of these agreements, which is recoupable only against actual overriding royalty during the period of five years following the date on which such overriding royalty was paid, is $1.0 million.

Transportation Infrastructure

Concurrent with the 2013 Reorganization, a throughput agreement was entered into between Hillsboro Energy LLC and Hillsboro Transport LLC for Hillsboro Transport LLC to operate the Clean Coal Handling

 

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System for Hillsboro Energy LLC. The agreement, which has an initial term of ten years, grants Hillsboro Transport LLC the right to be the exclusive provider of clean coal handling services for Hillsboro Energy. After the initial ten-year term of the throughput agreement, the parties can agree to continue renewing the agreement in five-year increments (up to 16 times). At the expiration of each term, Hillsboro Energy, LLC has an option to acquire the Clean Coal Handling System for its then fair value. As compensation for operating and maintaining the Clean Coal Handling System, Hillsboro Transport will receive $0.99 per ton for every ton of coal loaded through the Clean Coal Handling System, subject to a minimum quarterly payment of approximately $1.25 million beginning on January 1, 2014. Subsequent to the 2013 Reorganization date, Hillsboro Transport LLC was determined to be a variable interest entity and Hillsboro Energy LLC continues to consolidate Hillsboro Transport LLC as the primary beneficiary. See our audited historical consolidated financial statements, and notes thereto, included elsewhere in this prospectus.

Adena Resources has various contractual water rights contracts with various state and local governments that are used to provide water to certain of our mines. Concurrent with the distribution of Adena Resources to Foresight Reserves, each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into an agreement with Adena Resources providing for water resources to be available at each of the mines for use in mining operations. The agreements, which have an initial term of three years, will automatically renew for successive periods of one year unless either party opts out of the agreement. As compensation for furnishing water to the mines, the mines will pay Adena Resources the actual cost incurred by Adena Resources in furnishing water to the mine plus an annual administrative fee in the amount of $10,000. The mines are also responsible for reimbursing Adena Resources for any future capital expenditures necessary to fulfill its obligations under the agreements. Subsequent to the 2013 Reorganization date, Adena Resources was determined to be a variable interest entity and we continue to consolidate Adena Resources as the primary beneficiary. See our audited historical consolidated financial statements, and notes thereto, included elsewhere in this prospectus.

Other Leases

We lease office space with monthly payments that expire in 2017. We also lease railcars from various companies that require monthly payments. These leases expire at different times through December 31, 2017, and are customarily renewed and/or replaced.

 

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BUSINESS

We are a Delaware limited partnership formed in January 2012. We believe we are the lowest cost and highest margin bituminous thermal coal producer in the United States, based on publicly available information. 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 approximately $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, with a fourth longwall scheduled to begin production in May 2014. We have started permitting and preliminary engineering work as well as initial capital outlays 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 23.1 million tons in 2013 and the twelve months ending March 31, 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 March 31, 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.

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.

 

 

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

 

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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.

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 and 6.5 million tons in 2013. 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 December 31, 2013, we have secured coal sales commitments for approximately 20.2 million tons for 2014, 15.4 million tons for 2015 and 11.6 million tons for 2016, which represents approximately 87%, 67%, and 50%, respectively, of our expected production for the twelve-month period ending March 31, 2015.

 

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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. 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 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.

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 scheduled to begin production in May 2014, is 32.7 million tons for the life of our reserves (130 years based on our estimated production for the twelve months ending March 31, 2015). Our forecasted maintenance capital expenditures do not include actual or estimated 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		1		1		1		0		3
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
Future Operations:
Second Longwall				May 2014		2017-2019
Third Longwall				2016-2018		2018-2020
Fourth Longwall				2017-2019
Total number of Potential Longwall Mining Systems(3)		1		4		3		1		9
Current Annual Productive Capacity(4)		7.5		13.5		9.0		2.7		32.7
Long-term Annual Productive Capacity(5)		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.

(2)	As reported by MSHA through December 31 of the respective year.

(3)	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. The second longwall system at Sugar Camp is under development with longwall production expected to begin in May 2014.

(4)	Based on current annual productive capacity of Williamson, Sugar Camp, the second longwall at Sugar Camp currently under development, Hillsboro and Macoupin.

 

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(5)

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 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 130 years based on our estimated production for the twelve months ending March 31, 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. We believe that the size and contiguous nature of our reserves are a competitive advantage as they would take significant time and capital to replicate.

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 year 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

 

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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. Its 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 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 December 31, 2013, we have secured coal sales commitments for approximately 20.2 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 17.8 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 March 31, 2015 are 87%, 67% and 50% for calendar years 2014, 2015 and 2016, respectively.

Significant growth opportunities enabled by $2.0 billion of capital investment. At full run rate production, including our longwall that is scheduled to begin production in May 2014, 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.

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

 

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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 to 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 costs of mining and transporting coal to our primary domestic markets in the Southeast and the Ohio River compare 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, 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. 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 our marketing strategy 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     % 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. 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 in May 2014. 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

 

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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 71.8 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.

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 109 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.

2010 Reorganization

Simultaneously with the offering of our 2017 Senior Notes, we underwent a reorganization (the “2010 Reorganization”) pursuant to which:

 

•

Foresight Reserves contributed 100% ownership interest of Williamson Track, LLC, Savatran LLC and Sitran LLC (which are wholly-owned subsidiaries that conduct our transportation operations) and Adena Resources (a wholly-owned subsidiary which provides water and other miscellaneous rights) to Foresight Energy LLC;

 

•

Lower Wilgat, LLC distributed 100% of its ownership interest in Williamson Energy, LLC to Foresight Energy LLC;

 

•

Foresight Energy Finance Corporation, as co-issuer in the offering of our 2017 Senior Notes, was added to the corporate structure;

 

•

Foresight Energy LLC distributed 100% of its investment in entities that owned other mining operations, including Gatling LLC (a mine in West Virginia), Gatling Ohio LLC (a mine in Ohio), Meigs Point Dock LLC (a dock in Ohio), Lower Wilgat, LLC, Middle Wilgat, LLC and Upper Wilgat, LLC and all of their subsidiaries and affiliates (other than Williamson Energy, LLC) to Foresight Reserves;

 

•

Certain mineral rights that are not in our current mine plans were distributed by Macoupin Energy LLC, a subsidiary of Foresight Energy LLC, to a related entity of Foresight Reserves;

 

•

Certain mineral rights that are adjacent to our existing coal leases and are owned by subsidiaries of Foresight Reserves were leased to Foresight Energy LLC’s subsidiaries on a long-term basis; and

 

•

Foresight Reserves assumed certain accrued interest with respect to the debt owed to Williamson Royalty Ventures by Upper Wilgat and Foresight Energy LLC was relieved of any further obligation with respect thereto.

 

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In connection with these transactions, Foresight Reserves contributed $70 million in 2010 and $30 million in 2011 to Foresight Energy LLC.

See also “Certain Relationships and Related Party Transactions—Transactions with Foresight Reserves and Foresight Energy GP LLC—2010 Reorganization” and “Certain Relationships and Related Party Transactions—Other Related Party Transactions.”

2013 Reorganization

In connection with the closing of the 2013 Refinancing, we underwent a restructuring (the “2013 Reorganization”), pursuant to which:

 

•

Foresight Energy LLC distributed its 100% ownership interest in Sitran (which was a wholly-owned subsidiary that conducted our transloading operations on the Ohio River) and Adena Resources (which was a wholly-owned subsidiary that provided water and other miscellaneous rights) to its owners;

 

•

Each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into a transloading and storage agreement with Sitran. These agreements provide for the unloading of coal from each of Williamson, Sugar Camp, Hillsboro and Macoupin from railcars into stockpiles at Sitran and for the loading of coal from such stockpiles into barges;

 

•

Hillsboro Energy LLC distributed certain transportation assets known as the “Clean Coal Handling System,” along with associated surface property underlying those assets, to Foresight Energy LLC. The owners of Foresight Energy LLC in turn contributed the assets to Hillsboro Transport LLC, a subsidiary of Foresight Reserves;

 

•

Hillsboro Energy LLC and Hillsboro Transport LLC entered into a throughput agreement for Hillsboro Transport LLC to operate and maintain the Clean Coal Handling System to transport and load clean coal;

 

•

An agreement was reached between Sugar Camp, LLC and Foresight Reserves under which Foresight Reserves has the right to amend Sugar Camp’s existing lease with HOD LLC for the Sugar Camp Rail Loadout to add coal produced from the second longwall at Sugar Camp. Pursuant to such amendment, the consideration paid by HOD LLC for including coal to the effect and operation of such lease will be paid directly to Foresight Reserves;

 

•

Each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into agreements with Adena Resources for the use of certain water rights and facilities owned or controlled by Adena Resources;

 

•

Savatran and Hillsboro Energy LLC agreed to distribute to New River Royalty, LLC (an affiliate of Foresight Energy LLC) up to 2,500 acres of surface land;

 

•

Hillsboro Energy LLC entered into a development agreement with Colt, pursuant to which Hillsboro Energy LLC has the right to offer Colt the ability to develop additional longwall coal mines and associated transportation infrastructure in coal reserves leased by Colt to Hillsboro Energy LLC. If Colt develops a mine, Hillsboro Energy LLC would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement;

 

•

Macoupin Energy LLC entered into a development agreement with Colt, pursuant to which Macoupin Energy LLC will have the right to offer Colt the ability to develop an additional longwall coal mine and associated transportation infrastructure in coal reserves leased by Colt to Macoupin Energy LLC. If Colt develops a mine, Macoupin Energy LLC would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement; and

 

•

Sugar Camp Energy, LLC entered into a development agreement with Ruger, pursuant to which Sugar Camp Energy, LLC has the right to offer Ruger the ability to develop additional longwall coal mines and associated transportation infrastructure in coal reserves leased by Ruger to Sugar Camp Energy,

 

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LLC or where Sugar Camp Energy, LLC has the right to mine by virtue of an overriding royalty agreement with Ruger. If Ruger develops a mine, Sugar Camp Energy, LLC would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement.

See also “Certain Relationships and Related Party Transactions—Transactions with Foresight Reserves and Foresight Energy GP LLC—2013 Reorganization.”

Operations

 

Our operations and adjacent reserves are located in the Illinois Basin in southern and central Illinois. We control over 3 billion tons of proven and probable coal reserves with an average heat content range of 10,591 to 11,893 Btus per pound. We have four operating mining complexes each currently mining in the Herrin No. 6 seam with assigned reserves that we believe are sufficient to support more than twenty years of mining at each location. Each of our mining complexes have their own preparation plant designed to process the coal mined from that mining complex and facilities including slurry impoundments designed to store the resulting refuse. Although the Macoupin mining complex accepts limited amounts of external fly ash for beneficial uses on Macoupin’s permit area, none of our other mining complexes currently accept external refuse for deposition on their properties.

 

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Williamson, Sugar Camp and Hillsboro each operate one longwall mining system. A second longwall system is currently in development at Sugar Camp. A longwall mining system uses a shearer to cut the coal, self-advancing roof supports to protect the miners working at the longwall face and an armored face conveyor to transport the coal. The longwall mining system is highly productive due to the continuous nature of the coal production and the high volume of coal produced relative to the number of personnel required to operate the longwall mining system.

The table below summarizes our operations, mining methods, transportation, reserves and productive capacity including mines in development.

 

																				Production(6)
Complex		Location(1)				Mining Methods(2)				Transportation Access(3)		Proven and Probable Reserves(4)				Productive Capacity(5)				Year Ended December 31, 2013				Year Ended December 31, 2012
												(tons in millions)
Williamson			SILB				LW, CM			Rail (CN), Barge (OHR, MSR), Truck			388				7.5				6.7				7.5
Sugar Camp			SILB				LW, CM			Rail (CN, NS, CSX, BNSF), Barge (OHR, MSR), Truck			1,366				27.0				6.5				4.7
Hillsboro			CILB				LW, CM			Rail (UP, NS), Barge (OHR, MSR), Truck			880				24.0				4.8				2.4
Macoupin			CILB				CM, LW			Rail (UP, NS), Barge (OHR, MSR), Truck			459				8.7				0.7				1.7
*Total													3,092				67.2				18.8				16.3

 

(1)	SILB: Southern Illinois Basin; CILB: Central Illinois Basin.

(2)	LW: Longwall; CM: Continuous miner. Williamson, Sugar Camp and Hillsboro use CM for development sections only.

(3)	CN: Canadian National Railway Company UP: Union Pacific Railroad Corporation; NS: Norfolk Southern Corporation; CSX: CSX Corporation; BNSF: BNSF Railway Company; OHR: Ohio River; MSR: Mississippi River.

(4)	As of January 1, 2014.

(5)

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. 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, 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. See “Risk Factors” for a more detailed discussion of these and other risks and uncertainties.

(6)	As reported by MSHA through December 31 of the respective year.

*	Due to rounding, the amounts set forth above may not total to the amounts set forth in this row.

Williamson Mining Complex

Williamson is wholly-owned by our subsidiary Williamson Energy, LLC, and is the first mine that we developed in the Illinois Basin. As of January 1, 2014, Williamson’s assigned reserve base contained approximately 388 million tons of clean recoverable proven and probable coal with an average heat content of 11,847 Btus per pound.

 

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Permitting for Williamson began in March 2004 and construction began in July 2005. Slope development reached the coal seam at a depth of approximately 450 feet in mid-2006 and, following development of the slope bottom, commercial coal production began in November 2006. Longwall mining production commenced in the first quarter of 2008. Williamson was designed for an annual productive capacity of approximately 7.5 million tons per year. Williamson was the most productive underground coal mine in the United States in 2013 on a clean tons produced per man hour basis based on MSHA data.

Williamson operates in the Herrin No. 6 Seam, using two continuous miner units to develop the mains and gate roads for its longwall panels. The first two longwall panels it mined were 1,250 feet wide but subsequent and future longwall panels were and are planned to be 1,400 feet wide. The longwall panel lengths have ranged from 18,000 feet to over 26,000 feet and have seam height of approximately six feet.

Coal is washed at Williamson’s preparation plant, stockpiled and then shipped by rail or truck to market. Nearly all of Williamson’s coal is shipped via the CN railroad to the Ohio and Mississippi River to serve the domestic thermal market or to New Orleans to serve the international market. Williamson has access to several barge and vessel loading facilities on the Ohio and Mississippi Rivers and in New Orleans.

Williamson Energy, LLC has a contract mining arrangement with Mach, a third party mining contractor. Mach is paid on a cost-plus basis for coal that is produced and processed from Williamson’s mine. As of December 31, 2013, Mach employed 176 workers at Williamson, 133 of which worked underground. Mach maintains a bonus program for its employees to promote safety and productivity. Williamson does not employ a mining work force and conducts all of its mining operations exclusively through its contract operator, Mach.

Williamson Energy, LLC leases some of its coal reserves from a subsidiary of NRP as a result of transactions in 2005 and 2006. An NRP subsidiary also owns the Williamson rail loadout which we sold to them in 2006. We pay NRP a fee for coal shipped from this loadout. See “Certain Relationships and Related Party Transactions.”

Sugar Camp Mining Complex

Sugar Camp is wholly-owned by our subsidiary Sugar Camp Energy, LLC. As of January 1, 2014, its assigned reserve base contained approximately 1,366 million tons of clean recoverable proven and probable coal with an average heat content of 11,774 Btus per pound. Sugar Camp is located approximately 12 miles north of Williamson.

Permitting at Sugar Camp began in December 2004 and development of the slope and surface facilities began in October 2008. The slope reached the coal seam at a depth of approximately 750 feet in January 2010. Its first de minimis coal shipments occurred in late August 2010. The longwall system began production in the first quarter of 2012. Its longwall panels are 1,400 feet wide. The planned longwall panel lengths range from 18,000 feet to over 22,000 feet and have seam height of approximately six feet. Sugar Camp was the fourth most productive underground coal mine in the United States in 2013 on a clean tons produced per man hour basis based on MSHA data.

Sugar Camp operates in the same Herrin No. 6 Seam and uses a similar mine design and similar equipment as Williamson. We therefore expect that each longwall mining system at Sugar Camp will achieve the same high volume of production and productivity as the Williamson longwall mining system. Sugar Camp’s existing infrastructure, including its bottom development, slope belt, material handling system and rail loadout, was designed to support two longwalls. With additional mine development, Sugar Camp has the capacity to add two incremental longwall systems, which would form a new mining complex requiring new surface infrastructure and a new slope. Sugar Camp is designed to have an annual productive capacity of approximately 27 million tons.

Coal is washed at Sugar Camp’s preparation plant, stockpiled and then shipped by rail to market. Sugar Camp has direct access to the CN railroad which can deliver its coal to the Ohio and Mississippi Rivers to serve

 

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the domestic thermal market or to New Orleans to serve the international market. We have also developed additional transportation infrastructure to give Sugar Camp indirect access to the NS, CSX and BNSF railroads and have an opportunity for future potential access to the UP railroad. We believe that this broad access to five Class I railroads will give Sugar Camp more transportation optionality than its competitors.

Sugar Camp Energy, LLC has a contract mining arrangement with M-Class, a third party mining contractor. M-Class is paid on a cost-plus basis for coal that is produced and processed from Sugar Camp’s mine. As of December 31, 2013, M-Class employed 273 workers at Sugar Camp, 222 of which worked underground. M-Class maintains a bonus program for its employees to promote safety and productivity. Sugar Camp does not employ a mining work force and conducts all of its mining operations exclusively through its contract operators, M-Class and Viking.

Sugar Camp Energy, LLC leases its reserves from RGGS Land and Minerals, Ltd., L.P. and Ruger. An NRP subsidiary also owns the Sugar Camp rail loadout, which we sold to them in 2012. We pay NRP a fee for coal shipped from this loadout. See “Certain Relationships and Related Party Transactions.”

Hillsboro Mining Complex

Hillsboro is wholly-owned by our subsidiary Hillsboro Energy LLC. As of January 1, 2014, its assigned reserve base contained approximately 880 million tons of clean recoverable proven and probable coal with an average heat content of 10,960 Btus per pound.

Permitting at Hillsboro began in July 2006 and construction began in May 2009. Its longwall mining system started in September 2012. Its longwall panels are between 1,000 and 1,400 feet wide. The panel lengths are approximately 15,000 feet and have seam height of approximately seven feet. Hillsboro was the second most productive underground coal mine in the United States in 2013 on a clean tons produced per man hour basis based on MSHA data.

Hillsboro operates in the same Herrin No. 6 Seam and uses the same mine design and similar equipment as Williamson. However, as the initial mining area at Hillsboro has approximately one and a half more feet of coal thickness than Williamson, it uses a larger shearer and thus we currently expect that the production and productive capacity at Hillsboro will surpass Williamson. Hillsboro is designed for an annual productive capacity of approximately 24 million tons.

Coal is washed at Hillsboro’s preparation plant, stockpiled and then shipped by rail or truck to market. Hillsboro has direct access to the UP and NS railroads, which can deliver its coal directly to customers or to the Mississippi River to serve the domestic thermal market or the international market through New Orleans, and indirect access to the CN railroad.

Hillsboro Energy LLC has a contract mining arrangement with Patton Mining LLC, a third party mining contractor. Patton is paid on a cost-plus basis for coal that is produced and processed from Hillsboro’s mine. As of December 31, 2013, Patton employed 164 workers at Hillsboro, 122 of which worked underground. Patton maintains a bonus program for its employees to promote safety and productivity. Hillsboro Energy LLC leases its reserves from Colt and from a subsidiary of NRP. See “Certain Relationships and Related Party Transactions.” Hillsboro does not employ a mining work force and conducts all of its mining operations exclusively through its contract operator, Patton.

Macoupin Mining Complex

Macoupin is wholly-owned by our subsidiary Macoupin Energy LLC, and primarily includes the mining assets we acquired from ExxonMobil Coal USA, Inc. on January 22, 2009. As of January 1, 2014, Macoupin’s assigned reserve contained approximately 459 million tons of clean recoverable proven and probable coal in the Herrin No. 6 Seam with an average heat content of 10,591 Btus per pound. Following the acquisition from

 

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Exxon, Macoupin recovered underground equipment, power lines, water pipe, conveyor belt and structure from the prior mine works. Macoupin then sealed off the majority of the previously mined areas of the mine to reduce the size of the underground area it needed to maintain and essentially created a new underground mine. The surface facilities were also upgraded, including the rehabilitation of the preparation plant.

Coal production began in the third quarter of 2009 with a single continuous miner super-section utilizing battery powered coal haulers. An additional continuous miner unit was added in January 2011 using an FCT system rather than coal haulers. Macoupin’s Shay No. 1 continuous miner operation was designed for an annual productive capacity of approximately 2.7 million tons.

Macoupin’s low sulfur reserves were previously mined by Exxon using a longwall system. Macoupin can develop these reserves with a new longwall mine which would have a productive capacity of 6.0 million tons.

Coal is washed at Macoupin’s preparation plant, stockpiled and then shipped by rail or truck to market. Macoupin has direct access by both the UP and NS railroads and indirect access to the CN railroad. Coal is shipped via rail or truck directly to customers or to the Mississippi River where Macoupin enjoys access to a long-term throughput arrangement with a third party river terminal.

Macoupin Energy LLC has a contract mining arrangement with MaRyan Mining LLC, a third party mining contractor. MaRyan is paid on a cost-plus basis for coal that is produced and processed from Macoupin. As of December 31, 2013, MaRyan employed 61 workers at Macoupin, 47 of which worked underground. MaRyan maintains a bonus program for its employees to promote safety and productivity. Macoupin does not employ a mining work force and conducts all of its mining operations exclusively through its contract operator, MaRyan.

Macoupin’s favorable geology, new mine layout and efficient work force make it highly productive.

In 2009, Macoupin Energy LLC sold its reserves to a subsidiary of NRP and leased them back. Proceeds from this transaction were used to capitalize the mine. An NRP subsidiary also owns Macoupin’s rail loadout and rail loop, which Macoupin Energy LLC sold to them in 2009 in the same transaction as the reserves sale-lease back. Macoupin Energy LLC pays NRP a fee for coal shipped through this loadout and over the rail loop. See “Certain Relationships and Related Party Transactions.”

Transportation

Our coal is transported to our domestic customers and export terminal facilities by rail, barge and truck. Because our reserves and mines are favorably located near multiple rail and river transportation options, we believe we can negotiate advantageous transportation rates, allowing us to keep our transportation costs relatively low and provide broad market access for our coal.

We have direct and indirect rail access to domestic customers via five Class I railroads, river access to domestic customers via various Ohio and Mississippi river terminals and river and rail access to coal export terminals for shipping to international customers. We have agreements with rail carriers that vary in length from one to twenty years. Approximately 30.7% and 19% of our coal sales volume for 2013 and 2012, respectively was shipped to our domestic customers by barge, 35.9% and 37%, respectively to domestic customers by rail or truck and 33.5% and 44%, respectively was shipped to international customers. For the year ended December 31, 2012, 64%, 16% and 14% and for the year ended December 31, 2013, 69%, 12% and 9% of the coal shipped internationally was exported to customers in Europe, China and India, respectively, with the remaining 6% and 10%, respectively, shipped to customers in several other countries. Rates and practices of the transportation company serving a particular mine or customer may affect, either adversely or favorably, our marketing efforts with respect to coal produced from the relevant mine.

In connection with the 2013 Reorganization, each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into a transloading and storage agreement with Sitran, a high-capacity coal transloading facility on the Ohio River near Evansville, Indiana owned by our parent,

 

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Foresight Reserves. Prior to the 2013 Reorganization, Sitran was owned and operated by Foresight Energy. The terminal has the potential for a dual rail loop that will have capacity for two loaded and two empty unit trains. The facility currently has a single rail loop, a bottom discharge rail car unloader, stacking tubes to facilitate ground storage and blending and barge loading capabilities. Under these transloading arrangements, each mine will pay Sitran $1.50 per ton of coal offloaded, stored or transloaded at Sitran’s facility. Each agreement has an initial term of three years and will renew automatically for successive one year periods unless terminated by either party. The rates per ton of coal unloaded or loaded will escalate each year by four percent. Subsequent to the 2013 Reorganization date through December 31, 2013, the mines incurred $3.7 million in transloading fees with Sitran.

A subsidiary of our parent, Foresight Reserves, acquired the IC Rail Marine Terminal from the Canadian National Railway Company, which it renamed Convent Marine Terminal. Since that time, the ownership of the Convent Marine Terminal has been transferred from a subsidiary of Foresight Reserves to a subsidiary of F.R.L.P No. 2 LLC, an entity controlled by Christopher Cline and beneficially owned by Christopher Cline, trusts for his children and entities beneficially owned by his management team. The terminal is designed to ship and receive commodities via rail, river barge and ocean vessel. Rail service to the terminal is provided by the Canadian National Railway. Water borne material is received and shipped via the Mississippi River. Based on recent performance, the Convent Marine Terminal has 10 million tons of coal throughput capacity per year and is currently increasing throughput capacity to 25 million tons of coal per year. We have a contract for throughput at the terminal with our affiliate Savatran that continues through December 31, 2021 and is coterminous with Savatran’s rail transportation agreement with the CN for the movement of coal from Hillsboro, Macoupin, Sugar Camp and Williamson to the Convent Marine Terminal. Fees paid by us under the contract are based on the tonnages of coal it moves through the terminal, subject to minimum annual take-or-pay volume commitments throughout the duration of the contract. The minimum annual commitment amount under the rail transportation agreement is $40.5 million for 2014 and thereafter increases on average by 4.4% per year. For the years ended December 31, 2013 and 2012, we recorded $26.5 million and $26.3 million of expense, respectively, under the contract.

Coal Reserves

We believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our current reserve base is one of our strengths. We estimate that we owned or controlled 3 billion tons of proven and probable recoverable reserves at January 1, 2014. Our coal reserve estimate is based on a study prepared by Weir International, Inc., a mining and geological consultant. Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data. Our coal reserve estimates are periodically updated to reflect past coal production and other geologic and mining data. Acquisitions or sales of coal properties will also change these estimates. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam.

Our coal reserve estimates include reserves that can be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtaining mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. Further, the economics of our reserves are based on market conditions including contracted pricing, market pricing and overall demand for our coal. Thus, the actual value at which we no longer consider our reserves to be economic varies depending on the length of time in which the specific market conditions are expected to last. We consider our reserves to be economic at a price in excess of our cash costs to mine the coal and our ongoing replacement capital. See “Risk Factors—Risks Related to Our Business—We face numerous uncertainties in estimating our economically recoverable coal reserves.”

Certain of our mines are subject to private coal leases. Private coal leases normally have a stated term and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the

 

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exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease rental or minimum royalty, payable either at the time of execution of the lease or in periodic installments.

The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically.

All of our recoverable coal reserves are assigned reserves as of January 1, 2014. All of our reserves are considered high sulfur coal, with average sulfur content ranging between 1.71% and 3.33% and high Btu coal, with Btu content ranging between 10,591 and 11,893 Btu per pound. The following tables present our estimated recoverable coal reserves at January 1, 2014:

 

																														Theoretical Coal Quality (As Received Basis)
Property Control		Seam				Average Seam Thickness (Feet)				Area (Acres)				In-Place Tons(1) (000)				Clean Recoverable Tons(2) (000)												Sulfur (%)				Btu/lb
																		Proven				Probable				Total
Williamson Energy, LLC			6				5.81				29,057				321,633				136,223				54,537				190,761				2.20				11,893
Williamson Energy, LLC			5				4.24				39,070				308,215				111,507				85,437				196,943				1.71				11,799
Sugar Camp Energy, LLC			6				6.40				103,782				1,254,201				370,847				394,231				765,078				2.46				11,820
Sugar Camp Energy, LLC			5				4.75				104,303				925,724				238,407				362,134				600,541				2.44				11,712
Hillsboro Energy LLC			6				7.33				101,023				1,418,896				288,151				591,778				879,929				3.33				10,960
Macoupin Energy LLC			6				7.19				69,142				942,775				271,308				187,462				458,770				2.62				10,591
Total—Foresight Energy LLC															5,171,445				1,416,443				1,675,578				3,092,021

 

(1)	In-Place Tons are on a dry basis.

(2)	Clean Recoverable Tons are based on mining recovery, average theoretical preparation plant yield, 94% preparation plant efficiency, and product moisture.

Each of the mining companies leases the reserves they mine pursuant to a series of leases.

Williamson

Williamson Energy, LLC leases the Williamson Rail Load Out facility through a sublease with Williamson Transport LLC, owned by NRP. The term of the surface sublease is through March 12, 2018. At the end of the term, Williamson Transport LLC has the option to renew the sublease on terms mutually agreeable to both parties. If Williamson Transport LLC elects not to renew the sublease, Williamson Energy, LLC has the option to buy the Williamson Rail Load Out facility for its fair market value as determined by an independent appraiser.

Williamson Energy, LLC has a surface sublease agreement with Savatran for the construction, operation and maintenance of the rail spur at Williamson. The lease term of the sublease is through March 12, 2018. At the end of the term, Savatran has the option to renew the sublease. Williamson Energy, LLC has the option to buy the Savatran rail spur for its fair value as determined by an independent appraiser.

Williamson Energy, LLC has a coal mining lease agreement with Independence, owned by NRP. The term of this agreement is through March 13, 2021, and can be renewed for additional five year periods or until all merchantable and mineable coal has been mined and removed. Williamson Energy, LLC is required to pay Independence the greater of 9.0% of the gross selling price or $2.85 per ton for the coal mined from the leased premises. In addition to the tonnage royalty, Williamson Energy, LLC is required to pay a quarterly minimum royalty of $416,750 payable on the 20th of January, April, July, and October in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the $416,750 quarterly minimum royalty, Williamson Energy, LLC may recoup any unrecouped quarterly deficiency payments made during the preceding nineteen quarters from the excess tonnage

 

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royalty on a first paid, first recouped basis. The lease also has a provision for wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises. Williamson Energy, LLC has an overriding royalty agreement with Independence. As such, Independence will receive an overriding royalty interest in the amount of $0.30 per ton for each ton of clean coal mined from certain mineral reserves identified in the agreement that Williamson Energy, LLC does now or in the future will control that are sold to any third party for the life of the Williamson mining operations on the identified mineral reserves.

Williamson Energy, LLC has coal mining lease agreements with WPP, an affiliate of NRP. The leases allow for the mining, processing, and transporting of coal reserves located in Illinois. The terms of the coal leases include the requirement for Williamson Energy, LLC to pay WPP minimum royalties, tonnage royalties, and wheelage. The terms of these leases are 15 years from August 14, 2006 and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed. Williamson Energy, LLC is required to pay the greater of 8.0% of the gross selling price or $2.50 per ton for the first eight million tons of clean coal mined from the leased premises in any calendar year. For all tonnage mined in excess of the eight million tons, the royalty is the greater of 5.0% of the gross selling price or $1.50 per ton of clean coal mined from the leased premises. All royalties are for clean coal mined from the Herrin No. 6 seam of coal on the leased premises. In addition to tonnage royalty, the quarterly minimum royalty is $2 million, payable on the 20th of January, April, July, and October in each year this lease is in effect, for the prior quarter production. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the $2 million quarterly minimum royalty, Williamson Energy, LLC may recoup any unrecouped quarterly deficiency payments made during the preceding nineteen quarters from the excess tonnage royalty on a first paid, first recouped basis. Furthermore, the lease provides for an overriding royalty of $0.10 per ton on the first 8.5 million tons mined from specific coal reserves outlined in the agreement. The lease also requires a wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises.

Williamson Energy, LLC is obligated to pay overriding royalties to WPP, an affiliate of NRP, pursuant to a special warranty deed dated August 22, 1990 between their predecessors in interest, Coal Properties Corporation, Grantor and Fairview Land Company. Under this deed, WPP is owed an overriding royalty in the amount of $0.25 per ton for each ton of coal mined and sold by Williamson Energy, LLC from the mineral reserves subject to the deed.

Williamson Energy, LLC leases coal reserves from Colt, an affiliated company. The term of this lease is for ten years with six renewal periods of five years each. Williamson Energy, LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for this lease, which is recoupable only against actual production royalty from future tons mined during the period of five years following the date on which any such minimum royalty is paid, is $2.0 million per year.

Hillsboro

Hillsboro Energy LLC entered into a coal mining lease agreement on September 10, 2009, with WPP. Hillsboro Energy LLC leased certain mineral rights from WPP for a term of 20 years and can renew for additional five year terms, with a maximum of six terms or until all merchantable and mineable coal has been mined and removed. Hillsboro Energy LLC is required to pay WPP the greater of 8.0% of the gross selling price or $4.00 per ton and a fixed royalty in the amount set forth in the agreement for the coal mined from the leased premises. Hillsboro Energy LLC paid a minimum royalty of $3.1 million on April 20, 2010, covering the period of January 1, 2010 through March 31, 2010. For the remaining three calendar quarters in 2010 and the four calendar quarters of 2011, the quarterly minimum royalty was $3.1 million for the prior quarter’s production. Beginning with the quarterly minimum royalty due April 20, 2012, the quarterly minimum royalty is $7.5 million payable on the 20th of January, April, July, and October in each year until 2031, for the prior quarter’s production. Beginning with the quarterly minimum royalty due April 20, 2032, the quarterly minimum will be $125,000 for each quarter of 2032 and each subsequent quarter. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty exceeds the applicable quarterly minimum royalty, Hillsboro Energy LLC may recoup any unrecouped quarterly deficiency payments made during the preceding twenty quarters in any year other than 2010 from the excess tonnage royalty on a first paid, first recouped basis.

 

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Hillsboro Energy LLC leases coal reserves from Colt, an affiliated company, under two leases, the terms of which are identical but that each cover different reserves. The term of these leases is for five years from August 12, 2010 with seven renewal periods of five years each. Hillsboro Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for each of these leases, which is recoupable only against actual production royalty from future tons during the period of ten years following the date on which any such minimum royalty is $4.0 million.

Macoupin

In January 2009, Macoupin sold additional coal reserves and infrastructure assets related to Macoupin for $143.5 million. Simultaneous with the closing, Macoupin Energy LLC entered into a lease transaction with affiliates of NRP for mining of the mineral reserves and for the rail and loadout facilities. The mineral reserve mining lease is for a term of 20 years from January 2009 and can be extended for additional five-year terms limited to six such renewals. The lease requires a tonnage royalty of the greater of 8% plus $0.60 per ton and $5.40 per ton with annual minimums of $16.0 million. The minimum royalty is recoupable on future tons mined. If during any quarter, tonnage royalty and tonnage fees paid under the rail load-out and rail loop leases discussed below exceed $4.0 million, Macoupin Energy LLC may recoup any unrecouped quarterly deficiency payments made during the preceding twenty quarters on a first paid, first recouped basis, except that any quarterly deficiency payments made with respect to any period during 2009 are only recoupable for the succeeding twelve quarters. The Macoupin rail load-out facility and rail loop facility leases are for terms of 29 years with 16 renewals for five years each. The leases require a payment for every ton of coal loaded through the facility for the first 30 years up to 3.4 million tons along with an annual rental payment. The fee per ton is $3.00. Macoupin Energy LLC is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order.

Macoupin Energy LLC leases coal reserves from Colt, an affiliated company, under two leases, the terms of which are identical but that cover different reserves. The term of these leases is for ten years with six renewal periods of five years each. Macoupin Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for each of these leases, which is recoupable only against actual production royalty from future tons mined during the period of ten years following the date on which any such minimum royalty is paid, is $2.0 million.

Effective June 1, 2012 Macoupin Energy LLC leased additional coal reserves from Colt under another lease. The term of this lease is ten years with six renewal periods of five years each. Macoupin Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for this lease, which is recoupable only against actual production royalty from future tons mined during the period of ten years following the date on which any such minimum royalty is paid, is as follows:

 

For calendar year 2013		$	500,000
For calendar year 2014 and thereafter		$	2,000,000

Sugar Camp

In 2005, Sugar Camp Energy, LLC entered into a mineral lease with RGGS Land & Minerals Ltd., L.P. The primary term of this lease is for twenty years with two ten year renewal periods available under certain conditions described in the lease. Sugar Camp Energy, LLC is required to pay the greater of a price per ton or a percentage of the gross sales price for each ton of coal mined from the premises. In addition to the tonnage royalty, the minimum royalty for this lease, which is recoupable on future tons mined, with limitations as outlined in the lease, is $4.0 million in 2010 and 2011 then reduces to $2.0 million for the remainder of the primary term.

Sugar Camp Energy, LLC leases coal reserves from Ruger, an affiliated company. The term of this lease is for ten years from August 12, 2010 with six renewal periods of five years each. Sugar Camp Energy, LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. There is no minimum royalty associated with this lease.

 

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Sugar Camp Energy, LLC has two overriding royalty agreements with Ruger pursuant to which Sugar Camp Energy, LLC is given the right to mine certain reserves controlled by Ruger as lessee. Pursuant to these overriding royalty agreements, the total royalty that Sugar Camp Energy, LLC will be required to pay for each ton of coal mined is equal to the difference between (i) the actual production royalty paid by Sugar Camp Energy, LLC to the lessor of the reserves under the leases assumed by Sugar Camp Energy, LLC from Ruger and (ii) the amount which is equal to 8% of the gross selling price of the coal mined under the leases. In addition to the overriding royalty, the minimum royalty for each of these agreements, which is recoupable only against actual overriding royalty during the period of five years following the date on which such overriding royalty was paid, is $1.0 million.

Transportation

Macoupin Energy LLC leases the rail load-out facility and the rail loop facility associated with its mine under a separate lease for each facility. The leases are dated January 27, 2009. The leases are for terms of 29 years with 16 renewals for five years each. The leases require an aggregate payment of $3.00 ($1.50 for the rail loop facility and $1.50 for the rail load-out facility) for every ton of coal loaded through the facility for the first 30 years up to 3.4 million tons. After the expiration of the first 20-year term and the first two five-year renewal terms and for the remainder of the term, the annual rental payments shall be $10,000. Macoupin Energy LLC is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order. At any time after termination of the coal mining lease agreement and upon 90 days’ notice, Macoupin Energy LLC may purchase the premises for the then fair market value as determined by an independent appraiser.

Coal Sales Contracts

Approximately 20.2 million tons (or 93.10%) of our expected coal production in 2014 has been committed under contracts. Our primary domestic customers are electric utility companies in the eastern half of the United States. The majority of our customers purchase coal for terms of one year or longer, but we also supply coal on a short-term spot basis for some of our customers. For the year ended December 31, 2013, we derived approximately 10% of our total coal revenues from one customer. We believe the growth of our business, our ability to compete through our low cost structure and the diversification of our customer base limits our exposure to the loss of any one customer. However, if any of our largest customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to our largest customers on terms as favorable to us as the terms under our current contracts, our results of operations may be materially adversely affected.

The international thermal coal market has also been a substantial part of our business with direct and indirect sales to end users in Europe, South America, Africa and Asia. Over the past several years, we have exported approximately 34% of our coal production into these international markets, including 35% for the year ended December 31, 2013 and 6.9 million tons in the year ended December 31, 2012. We currently have 18.7 million tons of coal committed to these international markets under sales agreements that range from one to five years.

Our management and sales force actively monitor trends in contract pricing and seek to enter into long-term coal sales contracts at favorable prices. Many of our contracts allow us to substitute coal from other facilities. For 2014, we have 20.2 million tons of our projected production under contract with 28 separate customers. The following table describes our contracted position (in millions of short tons) for 2014, 2015 and 2016 as of December 31, 2013:

 

		2014								2015								2016
		Tons				Price				Tons				Price				Tons				Price
Committed and priced			17.8			$	51.07				10.1			$	49.18				5.0			$	52.06
Committed and unpriced			2.4								5.3								6.6

 

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

Most of our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, grindability, chlorine and ash fusion temperature. Failure to meet these conditions could result in substantial price reductions or termination of the contract, at the election of the customer. Although the volume to be delivered under a long-term contract is stipulated, the buyer or we may vary the timing of delivery within specified limits. Contracts also typically contain force majeure provisions allowing for the suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party, including labor disputes. Some contracts may terminate upon continuance of an event of force majeure for an extended period.

Some of our long-term contracts provide for a pre-determined adjustment to the stipulated base price at times specified in the agreement or at other periodic intervals to account for changes due to inflation or deflation in prevailing market prices.

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

Price reopener provisions are present in several of our long-term contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range of prices. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers.

Competition

The United States coal industry is highly competitive, both regionally and nationally. In the Illinois Basin, we compete primarily with coal producers such as Peabody Energy Corporation, Alliance Resource Partners, L.P., Murray Energy Corporation, Patriot Coal Corporation, James River Coal and Oxford Resource Partners. Outside of the Illinois Basin, we compete broadly with other United States based producers of thermal coal and internationally with numerous global coal producers.

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

Employees and Labor Relations

We do not have direct employees at Foresight Energy LLC. Corporate employees are employed by Foresight Energy Services LLC. Each of our operating subsidiaries have a contract in place with a third party contract operator for the mining and processing of all coal produced at the mine owned by the operating subsidiary. As of December 31, 2013, through the contracts described below, our operations had approximately 674 contractor employees. None of our operations have contractor employees represented by a union.

 

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Williamson

Williamson Energy, LLC has a contract with Mach pursuant to which Mach provides contract labor for the mining and processing of all coal produced at Williamson on a cost-plus basis. Mach is an unaffiliated entity but consolidated for accounting purposes. Williamson Energy, LLC has the right to terminate its contract with Mach, with or without cause, on ten days’ prior written notice.

Sugar Camp

Sugar Camp Energy, LLC has a contract with M-Class Mining LLC pursuant to which M-Class provides contract labor for the mining and processing of all coal produced from Sugar Camp’s first longwall mining system on a cost-plus basis. M-Class is an unaffiliated entity but consolidated for accounting purposes. Sugar Camp Energy, LLC has the right to terminate its contract with M-Class, with or without cause, on ten days’ prior written notice. Sugar Camp Energy, LLC also has a contract with Viking Mining LLC pursuant to which Viking provides contract labor for the mining and processing of all coal produced from Sugar Camp’s second longwall mining system scheduled to begin production in May 2014 on a cost-plus basis. Viking Mining LLC is an unaffiliated entity but consolidated for accounting purposes. Sugar Camp Energy, LLC has the right to terminate its contract with Viking, with or without cause, on ten days’ prior written notice.

Hillsboro

Hillsboro Energy LLC has a contract with Patton Mining pursuant to which Patton Mining provides contract labor for the mining and processing of all coal produced at Hillsboro on a cost-plus basis. Patton Mining is an unaffiliated entity but consolidated for accounting purposes. Hillsboro Energy LLC has the right to terminate its contract with Patton, with or without cause, on ten days’ prior written notice.

Macoupin

Macoupin Energy LLC has a contract with MaRyan Mining pursuant to which MaRyan provides contract labor for the mining and processing of all coal produced at Macoupin on a cost-plus basis. MaRyan Mining is an unaffiliated entity but consolidated for accounting purposes. Macoupin Energy LLC has the right to terminate its contract with MaRyan, with or without cause, on ten days’ prior written notice.

Legal Proceedings and Liabilities

From time to time, we are involved in lawsuits, claims or other proceedings with respect to matters such as personal injury, permitting, wrongful death, damage to property, environmental remediation, employment and contract disputes and other claims and actions arising in the ordinary course of business.

In November 2012, six citizens filed requests for administrative review of Revision No. 1 to Permit No. 399 for the Hillsboro mine. Revision No. 1 allowed for conversion of the currently permitted coal refuse disposal facility from a non-impounding to an impounding structure. Shortly after filing of the Revision, one citizen withdrew his request. Following a hearing on both IDNR’s and Hillsboro’s motions to dismiss, the hearing officer dismissed the claims of two of the remaining five petitioners and also limited some of the issues remaining for administrative review. The legal proceeding is ongoing. To date, no deadlines or final hearing date has been set in this matter.

We purchased the Shay No. 1 Mine at Macoupin (“Shay Mine”) in 2009. Prior to our acquisition of that mine, in 2003, ExxonMobil Coal USA, Inc. (“Exxon”), the prior owner of the Shay Mine, enrolled the mine in the IEPA’s Site Remediation Program (“SRP”) to address some concerns regarding groundwater contamination from the refuse areas. Under the SRP, Exxon and Macoupin collected and quantified requested data. In the fall of 2011, Macoupin proposed, and IEPA accepted, a compliance commitment agreement (“CCA”) with remediation

 

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steps designed to respond to the groundwater contamination concerns. Further, in May 2013, Macoupin submitted a Corrective Action Plan (“CAP”) with Groundwater Modeling to the IEPA to address the long-term compliance and corrective measures planned for the clean-up of groundwater contamination issues. In June 2013, the IEPA referred the CCA to the Illinois Attorney General’s office for enforcement on the basis that the compliance period for the CCA extended for too long of a period for the IEPA to monitor. We believe that the CAP for the groundwater issues will be finalized and implemented through a consent decree with the Illinois Attorney General’s office at some point in the future. We do not expect the costs of compliance with the CAP to be material during 2013 and 2014. Although we have accrued $11.5 million for this matter on December 31, 2013, we do not believe that our ultimate costs will meet or exceed this amount.

Also at Macoupin, the IDNR issued a permit on July 27, 2012, along with revisions to two existing permits at Macoupin, to allow underground coal slurry disposal. In August 2012, a citizen and an environmental group filed Requests for Administrative Review (“Macoupin Requests”) of the permit. In January 2014, the hearing officer granted summary judgment in favor of Macoupin. Additionally, the IDNR renewed a permit for the refuse disposal area. An environmental group has submitted a Request for Administrative Review of this permit renewal and the legal proceeding is ongoing. While we believe the IDNR decisions on the issuance of the permit for slurry disposal and renewal for existing refuse disposal area was proper, there can be no guarantee that the permit and the revisions to permits will not be vacated or substantially modified, which could result in additional costs or cessation of some or all operations at the mine.

In late April 2013, IEPA issued Sugar Camp two violation notices regarding non-compliant effluent discharges from the mine site and improper dilution of high chloride water. Sugar Camp believes that it is now in compliance with its permit and has proposed a plan which will resolve all outstanding violations and provide long-term water treatment and disposal capacity for the operations. The proposed plan requires capital expenditures of $20 million, of which approximately $7.5 million has been invested through December 31, 2013 for the construction of the treatment facilities, in addition to timely approvals from the relevant Illinois regulatory agencies.

In late January 2014, the IEPA issued Sugar Camp a violation notice regarding construction of an underground well without issuance of an appropriate permit. Sugar Camp has ceased all drilling activities at the site and is working with the IEPA to revise and finalize its permit application, which has been in process since May 2013, and to finalize a compliance commitment agreement relating to this violation.

In late March, 2014, the IEPA issued Sugar Camp a violation notice regarding non-compliant effluent discharge from the mining operation. Sugar Camp has reclaimed a temporary holding pond that may have contributed to the violation and is currently in compliance with its permit. It is expected that this violation will be mitigated by the compliance plan relating to the earlier April 2013 effluent discharge violations discussed above.

We believe we will reach agreement with the IEPA regarding a comprehensive compliance plan with respect to all outstanding Sugar Camp violations. However, there can be no assurances that we will reach an acceptable agreement with the IEPA or that we will not be referred to the Illinois Attorney General for enforcement or that we will not incur penalties for these violations. Failure to reach a satisfactory regulatory outcome could result in the assessment of fines or penalties or a temporary or permanent suspension of mining at the affected operations until a final solution is obtained.

We are also party to various other litigation matters, in most cases involving ordinary and routine claims incidental to our business. We cannot estimate with certainty our ultimate legal and financial liability with respect to such pending litigation matters. However, we believe, based on our examination of such matters, that our ultimate liability will not have a material adverse effect on our financial position, results of operations or cash flows.

 

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THE COAL INDUSTRY

Introduction

Coal is an abundant and affordable natural resource that is used primarily as a fuel for the generation of electric power. According to the BP Statistical Review, worldwide proven coal reserves totaled approximately 861 billion metric tonnes at 2012 year end. The United States has the largest proven reserve base in the world with approximately 237 billion metric tonnes, or 27.6% of total world coal proven reserves. According to the EIA, U.S. coal reserves represent over 250 years of domestic supply based on 2012 production rates. Coal is also the most abundant domestic fossil fuel, accounting for approximately 92% of the nation’s fossil energy reserves on a Btu basis, according to the National Mining Association.

Coal is ranked by heat content, with anthracite, bituminous, sub-bituminous and lignite coal representing the highest to lowest heat ranking, respectively. Coal is also categorized as either thermal coal or metallurgical coal. Thermal coal is used by utilities and independent power producers to generate electricity and metallurgical coal is used by steel companies to produce metallurgical coke for use in the steel making process. In the United States, thermal coal accounted for 867 million tons or approximately 98% of total domestic coal demand in 2012.

Coal is a major contributor to the world’s energy supply. According to the BP Statistical Review, coal represented approximately 30% of the world’s primary energy consumption in 2012, its highest share since 1970. In 2012, global coal consumption grew by 2.5% compared to 2011, making coal the world’s fastest growing fossil fuel. According to Wood Mackenzie, coal’s use in global electricity generation is forecasted to rise over 55% by 2030, primarily to meet electrification needs. The chart below demonstrates the increasing importance of coal for global energy consumption over time according to the BP Statistical Review:

World Energy Consumption by Fuel Type (million tonnes of oil equivalents)

 

 

Source: BP June 2013 Statistical Review.

Our Industry Segment

We produce thermal coal from our underground mining operations in the Illinois Basin. Domestically, we market our coal principally to scrubbed power generation facilities and industrial users and, internationally, we market our coal to a variety of intermediary and end-users in the power generation business. Through 2025, Wood Mackenzie projects that total demand for Illinois Basin thermal coal will rise at a compound annual growth rate of 3.8% from 2012 levels compared to a relatively flat projected compound annual growth rate of 1.1% for the overall demand for U.S. thermal coal. Similarly, Wood Mackenzie forecasts flat or declining thermal coal production through 2025 for all major U.S. coal producing regions other than the Illinois Basin and Powder River Basin.

 

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We effectively compete with all producers of thermal coal that supply coal to domestic or international consumers for these respective segments.

Coal Industry Trends

Over the last ten years, the U.S. coal industry supplied nearly half of the fuel supply needs for the domestic electric utility industry, accounting for an average of 984 million tons per year of coal production. In 2012, a challenging economy and a mild 2011-12 winter in the United States reduced demand for electric power generation and, consequently, thermal coal. During the same period, U.S. natural gas prices reached an all-time low, precipitating an oversupply of U.S. thermal coal and increased inventory stockpiles at utilities. These factors contributed to depressed prices and led to a domestic supply and demand imbalance. As an example, in the Illinois Basin, coal prices (based on pricing for 11,800 Btu, 4.8 pounds SO2 per mmbtu) fell more than 13% from an average of $51.43 per ton in 2011 to $44.33 per ton in 2012. In response to lower prices, certain U.S. coal producers reduced workforces, idled or closed high cost operations and deferred capital projects across all coal basins. As a result, total U.S. coal production is expected to decrease by approximately 1.3% from 1,024 million tons in 2012 to 1,011 million tons 2013, according to the Wood Mackenzie.

In 2013, rising natural gas prices and normalized weather patterns in the United States allowed the domestic coal markets to recalibrate. Natural gas spot prices increased 136% from their monthly low of $1.84 per mmbtu in April 2012 to $4.34 per mmbtu at the end of 2013. Meanwhile, domestic utility coal-fired generation is up 4.8% in 2013 compared to 2012, recovering from an average of 39% of total utility generation in 2012 to 40% of total utility generation in 2013. Continuing reduction in stockpile levels may also contribute to a further uptick in demand in the future. According to the EIA, nationwide stockpile levels were reduced by approximately 37.1 million tons in 2013 from 185.1 million tons as of year -end 2012 to 148.0 million tons as of year-end 2013.

According to the EIA, domestic thermal coal demand is expected to rebound 5.9% from 870 million tons in 2012 to 921 million tons in 2013. As utility stockpiles moderate, this increase in demand coupled with a tighter supply following substantial easing of production in 2012 is expected to place upward pressure on prices, particularly in the Powder River and Illinois Basins where low cost production is expected to offset declining production in other higher cost regions. According to Wood Mackenzie, Illinois Basin coal demand is expected to increase 7.6% from 135 million tons in 2013 to 145 million tons in 2014 while Illinois Basin coal prices (based on pricing for 11,800 Btu, 4.8 pounds SO2 per mmbtu) are forecast to increase 6.9% from $43.05 per ton in 2013 to $46.04 per ton in 2014.

 

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Several short-term and long-term factors are presently impacting coal consumption and production both in the United States and in global markets. These market dynamics include the following:

United States

 

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Coal continues to be a low cost and abundant resource. The power generation infrastructure in the United States is largely coal-fired. According to the EIA, coal had a 47% average market share of electrical generation in the United States from 2000 to 2012, principally because it is a relatively low cost, reliable and abundant fuel source. Lower levels of electrical demand, low natural gas prices, together with other cost factors such as fuel transportation and emission control costs, displaced some coal-fired generation in 2012. However, this trend began to reverse in 2013 as a result of rising gas prices and a lower number of coal supply sources. In its March Short Term Energy Outlook for 2014, the EIA projected the average cost of coal delivered to electric generating plants to be $2.36 on a dollars per mmbtu basis versus $5.09 per mmbtu for natural gas, making the estimated price of natural gas over twice the price of coal for 2014 and 17.8% higher than the average price of natural gas over the course of 2013. According to the EIA, the 2010 to 2014 average fuel prices per million Btu to electricity generators, using coal and competing fossil fuel power generation alternatives, are as follows:

Average Cost of Electricity Generation by Fossil Fuel

(Dollars per million Btu)

 

Electric Generation Type		2010A				2011A				2012A				2013A				2014E
Distillate Fuel Oil		$	16.60			$	22.43			$	23.51			$	23.10			$	23.06
Residual Fuel Oil		$	12.57			$	18.30			$	21.05			$	19.27			$	18.91
Natural Gas		$	5.09			$	4.73			$	3.42			$	4.32			$	5.09
Coal		$	2.27			$	2.39			$	2.38			$	2.35			$	2.36

 

Source: EIA, March 2014.

 

•

Increasing demand for coal produced in the Illinois Basin. As a result of its low delivered cost, high Btu content and the use of scrubbers, Wood Mackenzie projects total demand for Illinois Basin coal to grow from 135.0 million tons in 2013 to 207.4 million tons in 2025, a compounded annual growth rate of 3.6%. Demand for coal produced in the Illinois Basin is expected to grow at a faster rate than overall U.S. coal demand, due primarily to the Illinois Basin’s low delivered cost per Btu and the increased utilization of scrubbers by utilities in the United States. Illinois Basin coal generally has high sulfur content and demand for high sulfur coal has increased in the United States as utilities have added scrubbers over the last 10 years to comply with environmental regulations. According to Wood Mackenzie, 215 GWs or 70% of total coal-fired electric generating capacity in the United States, is estimated to have been scrubbed in 2013. Wood Mackenzie expects scrubbed capacity to increase to 258 GWs, or nearly 100% of total coal fired capacity, by 2025. In addition, high Btu coal, such as that produced in the Illinois Basin, is burned by utilities in both the Atlantic and Pacific seaborne markets. Assuming forecasted increases in Pacific Basin thermal coal demand continue, the export market will continue to be a viable component of overall Illinois Basin coal demand.

 

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Forecasted Illinois Basin Coal Demand

(Tons in millions)

 

End Use Sector		2013E				2014E				2015E				2020E				2025E				2013-2025 CAGR
South Atlantic			17.7				30.2				33.0				64.1				67.7				11.8	%
East North Central			53.8				50.4				52.1				65.8				61.3				1.1	%
East South Central			43.0				43.8				43.6				53.7				49.4				1.2	%
Other Domestic and Exports			20.3				20.9				24.3				18.8				28.9				3.0	%
Total ILB Demand			135.0				145.2				153.0				202.4				207.4				3.6	%

 

Source: Wood Mackenzie, November 2013.

 

•

Developments in U.S. regional coal markets. Coal production in Central Appalachia, which has traditionally been the second largest coal basin in the United States after the Powder River Basin (based on production), has been declining and is expected to continue to decline due primarily to the region’s high cost production profile, reserve degradation and the regulatory environment, which makes it difficult to obtain permits needed to conduct mining operations. In addition, increased environmental scrutiny and permitting constraints have significantly increased costs and lowered production from mountain-top mining, a mining method traditionally prevalent in Central Appalachia. Central Appalachian thermal coal production declined 59% from 219 million tons in 2002 to 91 million tons in 2012, according to Wood Mackenzie. Looking forward, Wood Mackenzie projects thermal coal production in Central Appalachia will decline 79.1% from an estimated 79 million tons in 2013 to 17 million tons by 2025. In addition, over the last several years, certain producers in Central Appalachia have shifted production from thermal coal to higher priced metallurgical coal, further decreasing coal available for sale to domestic utilities. We believe that all of these factors have led to a significant increase in cash costs of produced thermal coal in Central Appalachia and will continue to put cost pressures on producers, disadvantaging Central Appalachia coal on a delivered cost basis relative to other basins. We expect declining Central Appalachia production to be offset by production from other U.S. coal basins, including the Illinois Basin.

 

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Impact of natural gas on thermal coal demand. Historically, coal has been the primary source of fuel for electricity generation in the United States accounting for approximately one-half of the market, while natural gas supplied approximately 15% to 30% of the fuel used to generate electricity. From 2000 to 2007, the price of natural gas at Henry Hub averaged $5.70 per mmbtu; however, natural gas prices dropped significantly beginning in 2008 and reached a 10-year low in April 2012 of $1.84 per mmbtu.

As a result, from 2011 to 2012, natural gas electricity generation market share as a percentage of all power generated in the United States increased from 24.7% to 30.3%, while coal-supplied generation fell from 42.3% to 37.4% according to the EIA.

An expected consequence of low natural gas prices is lower future gas production. Consequently, according to Baker Hughes, the number of active natural gas drilling rigs dropped by 46%, from 811 rigs at the beginning of 2012 to 439 rigs at the beginning of 2013, and then fell an additional 15%, to 372 rigs as of January 2014.

In 2013, gas prices increased to an average of $3.72 per mmbtu and reached a high of $4.52 per mmbtu in December 2013. This rise in natural gas prices contributed to increasing the market share for utility coal-fired generation to 40% in 2013.

According to the EIA’s January Annual Energy Outlook 2014, gas-supplied electric generation is forecast to remain relatively flat at approximately 30% through 2025. Similarly, coal is projected to retain its position as the largest electricity generation source with an approximate 38% market share expected over the same projection period.

 

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Higher transportation costs for coal produced in the Western United States. Following the implementation of the Clean Air Act Amendments of 1990, many unscrubbed utilities chose to comply

 

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with reduced sulfur dioxide emissions mandates by purchasing emission credits or switching to lower sulfur fuels. One result of these actions was increased demand for low sulfur Powder River Basin coal. As a result, Powder River Basin production increased from approximately 397 million tons in 2002 to approximately 463 million tons in 2011. In 2012, however, low natural gas prices led Power River Basin coal demand to reverse, causing production in the basin to fall 44 million tons, or 9.5%, to 419 million tons. Another cost component that impacts Powder River Basin competitiveness is transportation. Most utilities consuming Powder River Basin coal negotiate long-term rail contracts with one of the two western railroads (Union Pacific and Burlington Northern Santa Fe) to control their transportation costs. From 1994 to 2004, reported average revenue per carload for these carriers increased 10.1%. Since the original transportation contracts began to expire in 2004, the reported average revenue per carload for these carriers has increased by 86.3% through December 31, 2013. The increased average cost of transportation for western coals is expected to result in higher delivered costs in the future.

 

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Increasing focus by utility coal buyers on delivered cost per Btu. Since 1990, the Clean Air Act’s restrictions on utility sulfur emissions made sulfur content an important part of a coal buyer’s selection of coal. Other determinants included heat content (a measurement of how much energy could be created by burning the coal), delivered price (a function of transportation distance, modality and rates) and other secondary coal characteristics. The increased adoption of scrubbers by utilities as referenced above has reduced the importance of sulfur content in a coal buyer’s decision making process, as most scrubbers can remove over 90% of sulfur-related gases prior to emission.

 

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Expected long-term increases in international demand for U.S. coal exports. In recent years U.S. coal exports have generally increased, supported by growing global economies and continued rapid growth in electric power generation and steel production capacity in Asia, particularly in China and India. U.S. coal exports rose 81.7 million tons in 2010 to approximately 117.7 million tons in 2013, a compound annual growth rate of 12.9%, according to the EIA. While current global coal prices are depressed, and near term U.S. seaborne coal demand should ease, in the long-term, we believe potential supply shortfalls in the Pacific region will ultimately reverse this recent trend leading to higher demand and improved pricing. Furthermore, an increase in demand for higher priced metallurgical coal may push any increase in Central Appalachian supply towards the metallurgical coal markets, which would further reduce supplies of thermal coal from this region. Because of these trends, we expect the Illinois Basin to continue to be an increasingly important supplier of coal to the seaborne thermal coal market.

 

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Increasingly stringent air quality legislation will continue to impact the demand for coal. A series of more stringent environmental requirements related to particulate matter, ozone, mercury, sulfur dioxide, nitrogen oxides, carbon dioxide and other air emissions have been proposed or enacted by federal or state regulatory authorities in recent years including the Mercury Air Toxic Standards regulation, which is expected to take effect in 2015. In addition, environmental regulators are currently considering implementing new proposed changes to greenhouse gas emission limits. While past air quality legislation reducing sulfur emissions has resulted in an increase in utilization of scrubbers, and thus increasing demand for high sulfur coal, we believe that additional air quality regulations ultimately will be adopted and will adversely impact future coal demand.

Seaborne Market

 

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Growth in seaborne thermal coal demand. According to Wood Mackenzie, coal consumption in the seaborne thermal coal market increased from approximately 622 million metric tonnes in 2008 to 896 million metric tonnes in 2012, a compounded annual growth rate of 9.6 %. Wood Mackenzie projects consumption of seaborne thermal coal to increase further to approximately 1.4 billion metric tonnes by 2025, a compounded annual growth rate of 3.7% from 2012. Growth in international coal import demand has resulted primarily from increased demand for thermal coal for electricity generation by emerging global economies, particularly by countries in the Pacific market where coal is the

 

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primary fuel source for new power generation. According to Wood Mackenzie, countries outside of the developed economies of Europe and Japan imported 65% of the world’s seaborne export thermal coal in 2012 and their share of the total seaborne thermal coal market is projected to increase to 84% in 2025.

 

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Increased seaborne thermal coal import demand by China. China, which historically was a net exporter of thermal coal, experienced a 176 million metric tonne increase in imports from 2008 to 2012, a compounded annual growth rate of 56%. Imports are expected to grow an additional 164% to 560 million metric tonnes by 2025, according to Wood Mackenzie. In 2012, China’s imports accounted for 24% of total seaborne demand. The chart below shows seaborne import demand and seaborne export supply for China from 2008 through 2025:

China Seaborne Thermal Coal Trade

(metric tonnes in millions)

 

 

Source: Wood Mackenzie, November 2013.

 

•

Increased seaborne thermal coal import demand by India. Coal demand in India has increased significantly, with imports rising from 34 million metric tonnes in 2008 to 94 million metric tonnes in 2012, a 29% compounded annual growth rate. India has announced plans to increase coal-fired power generation as a share of its overall generation portfolio. Wood Mackenzie estimates that India had 134 GWs of coal-fired generation in 2012 and expects this to increase by 91% to 257 GWs by 2025. This increase in coal-fired generation capacity is expected to create significant increases in seaborne thermal coal imports, as domestic thermal coal supply is projected to be insufficient to meet growth demand. According to Wood Mackenzie, between 2012 and 2025, India’s thermal coal imports are estimated to rise by 123% to 209 million metric tonnes, and India’s share of the seaborne thermal coal market is estimated to increase from 10% to 15%.

 

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Intermittent supply constraints from traditional thermal coal exporting countries. At times, some traditional export supply countries have faced supply constraints limiting their ability to keep up with the pace of seaborne thermal coal demand. Many of these countries have experienced a negative impact to their thermal export supply capabilities resulting from one or several factors, including labor shortages, limited port capacity, rail transportation capacity, reliability and distance, power generation shortages limiting coal processing, increased domestic consumption, unexpected weather impacts, new regulatory and environmental measures, political instability and declining coal qualities. In addition, rising operating cost pressures and increased capital intensity have combined with the near-term decline in thermal coal export prices to force shutdowns of some existing production and delays in new projects coming online. While some of these constraints have eased in recent years, we believe that many significant thermal coal importing countries in the Pacific market will continue their attempt to diversify their supply sources to guarantee security of supply by importing thermal coal from producers who had traditionally primarily serviced the Atlantic thermal market, including the United States.

 

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Continued demand for lower cost thermal coal in Europe. According to BP’s Energy Outlook 2030, European coal consumption is expected to decline 33% by 2030 due to several factors led by continued

 

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economic instability and increasing environmental and regulatory restrictions. However, during the same period, Wood Mackenzie forecasts coal production by Europe’s top producers, Germany, Spain and the United Kingdom, to decline by more than 46% due to the region’s declining coal reserve base and a reduction in government subsidies for coal mining. Also, the OECD Agency reports global growth in nuclear power capacity has slowed by approximately 10%, compared to previous projections, following the 2011 earthquake in Japan and the related nuclear incident. For example, Germany, already a significant coal consumer, has closed certain older nuclear facilities and the government is planning to shut down its remaining nuclear plants by 2022. These trends point towards potential supply shortfalls and increased demand for seaborne imports as a percentage of total thermal coal consumption in Europe. According to Wood Mackenzie, U.S. exports are expected to hold steady but account for an increasing percentage of total European import demand, increasing from an estimated 14% (23.6 million tons) in 2014 to an estimated 23% (22.0 million tons) in 2030.

Additionally, we believe European utilities are becoming increasingly focused on low cost fuel sources. Historically, natural gas has been a more expensive fuel for European utilities, when compared to the U.S. According to Wood Mackenzie, the European power sector’s 2013 average cost of natural gas per mmbtu was $10.67 compared to $3.26 per mmbtu for coal (as measured at the Antwerp/Rotterdam/Amsterdam port). We believe that a diminishing domestic coal supply coupled with European utilities’ increased focus on cost efficient power generation, will result in continued strong demand for thermal coal exports from the United States.

 

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Near-term over-supply in the seaborne thermal coal markets. Despite recent demonstrated growth trends in the seaborne markets and positive long-term fundamentals, a weak global economy has led to lower near-term demand and lower global spot prices. The API#2 spot price of coal delivered into northern Europe declined from $109.45 per metric tonne at January 1, 2012 to $90.70 per metric tonne at January 1, 2013 and to $81.55 per metric tonne at January 1, 2014. We believe that the current pricing environment will cause higher cost global suppliers to close, which will result in lower supply, and ultimately, improved global pricing.

Coal Demand

According to the World Coal Association, world hard coal consumption in 2013 was estimated at 6.6 billion metric tonnes, of which approximately 1.1 billion metric tonnes were sold internationally, primarily in the seaborne coal market. The seaborne market consists of coal shipped between countries via ocean-going vessels, excluding shipments between Canada and the United States via the Great Lakes.

Thermal coal consumption patterns are influenced by the demand for electricity, power generation infrastructure, transportation costs, governmental and environmental regulations, technological developments and the location, availability and cost of other fuels such as natural gas, nuclear power and hydroelectric power. Demand in the seaborne metallurgical coal market is influenced primarily by the worldwide demand for steel.

United States Coal Market

Thermal coal which is used to generate electricity and supports industrial uses accounts for 98% of coal consumed in the United States. Metallurgical coal is predominantly consumed in the production of metallurgical coke used in steelmaking blast furnaces. Power generation from coal-fired units accounted for 37.4% of all power generated in the U.S. in 2012 compared to 30.3% from natural gas and 19.0% from nuclear power.

According to the EIA, between 1975 and 2010, thermal coal consumption in the United States more than doubled, reaching over 1.0 billion tons in 2010. As a result of the recent global economic downturn, which reduced demand for electricity generation, as well as natural gas switching and regulatory and environmental pressures, total domestic thermal coal consumption decreased to approximately 870 million tons in 2012. However, the EIA recently reported that due primarily to recent increased gas prices, coal consumption rose by

 

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approximately 35 million tons in 2013. Despite the retirement of coal-fired generation capacity and increased share of natural gas and other fuel sources in electric generation, the EIA forecasts that the U.S. coal industry will retain its position as the predominant supplier of fuel to the domestic utility industry through 2030. According to the EIA’s Annual Energy Outlook 2014, domestic thermal coal consumption is expected to increase to approximately 970 million tons by 2025 and coal’s share of domestic power generation is projected to average 38% throughout the forecast period.

The following table sets forth the consumption of coal in the United States by consuming sector as actual or forecasted, as applicable, by the EIA for the periods indicated:

U.S. Coal Consumption (tons in millions)

 

		2011A				2012A				2013E				2014E				2015E				2020E				2025E
Electric Power			932				825				874				896				893				892				919
Industrial			46				43				45				46				47				49				49
Steel Production			21				21				21				21				22				22				22
Commercial/Institutional			3				2				2				2				2				2				2
Coal-to-Liquids			0				0				0				0				0				0				0
Total U.S. Coal Consumption			1,003				891				942				965				964				965				993

 

Source: EIA Annual Energy Outlook 2014, December 2013.

In the United States, the reliance on coal-fired generation is attributable to the abundance and low cost of coal. In 2012 and 2013, the cost of coal was approximately 30% and 46% lower respectively on a dollar per million Btu basis than natural gas, the next least expensive and readily available fuel source. While other cost factors such as fuel transportation and emission control costs ultimately help determine which fossil fuel source is used to generate electricity, according to the EIA, coal is expected to remain the largest energy source for electric power generation in the United States representing an average 38% share of domestic electricity generation through 2025.

U.S. Scrubber Market

Utilities in the United States are increasingly purchasing coal on a heat content basis (measured in dollars per million Btus) and less on a sulfur content basis as sulfur mitigation systems, or scrubbers, are installed by utilities to comply with emissions requirements of state and federal air regulations. The Illinois Basin is characterized by low cost, high Btu, high sulfur coal. Coal produced in Illinois competes nationally against other coal basins due to its low cost, access to widespread transportation outlets and its high heat rate. The Clean Air Act Amendments of 1990 restricted emissions of sulfur by electric utilities, which caused most utilities to comply with the new regulations by using lower sulfur coal or by purchasing sulfur emission credits. As the emission regulations continue to evolve, these compliance strategies will no longer be effective and as a result utilities are increasingly electing to install scrubbers at their coal-fired baseload electric generating facilities to meet air emission requirements.

The Clean Air Act Amendments of 1990 were principally responsible for a 38% decline in Illinois Basin coal production from 141 million tons in 1990 to 88 million tons in 2000, as many of the large coal mining operations in Illinois were idled or closed. The increase of scrubber utilization has led to high demand for high sulfur coal, which in turn has supported a 44.7% increase in the Illinois Basin coal production since 2000. We believe that the low sulfur premium historically favorable to the Powder River Basin and Central Appalachia will be reduced and the lower Btu and higher delivered cost per Btu coals from those regions will lose market share to high-Btu, low-cost coal from the Illinois Basin. According to Wood Mackenzie, total Illinois Basin coal demand

 

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including exports is expected to grow by 79.9 million tons, or 62.7%, from 127.5 million tons in 2012 to 207.4 million tons in 2025, largely as a result of additional scrubbed capacity and the shifting from Central Appalachia and Powder River Basin to Illinois Basin coal by Eastern utilities.

The following map of the Eastern United States shows coal-fired plants with operating and planned SO2 emission controls:

 

 

Source: Ventyx, the Velocity Suite.

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. In our primary market, which we define as coal fired power plants east of the Mississippi River, Wood Mackenzie projects that there was 200 GW of generating capacity in 2013, of which 142 GW was scrubbed. Taking into account 29 GW of unscrubbed capacity phase-outs, 7 GW of scrubbed capacity phase-outs, 28 GW of unscrubbed to scrubbed conversion and 1 GW of additional scrubbed capacity coming on-line, by 2020 Wood Mackenzie projects that there will be 164 GW of coal fired generating capacity east of the Mississippi River, of which 164 GW will be scrubbed.

 

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According to Wood Mackenzie’s projections, demand for coal from scrubbed power plants east of the Mississippi River, excluding non-utility generation, will increase from 309 million tons per year in 2013 to 513 million tons per year in 2020. Of that, demand for Illinois Basin coal is expected to increase from 102 million tons per year in 2013 to 185 million tons per year in 2020.

Projected Eastern U.S. Scrubbed Generation Capacity and Scrubbed Coal Demand

 

Eastern U.S. Coal-Fired Electric Generation Capacity (GW)		Eastern U.S. Scrubbed Coal Demand (MM Tons)

 

Source: Wood Mackenzie, November 2013.

Note: Projected Eastern U.S. scrubbed coal demand excludes non-utility generation.

According to Wood Mackenzie, the significant growth in Illinois Basin demand due to scrubber installations will come primarily from the South Atlantic (the states of Delaware, Florida, Georgia, Maryland, North Carolina, South Carolina, Virginia and West Virginia) and the East North Central (the states of Illinois, Indiana, Michigan, Ohio and Wisconsin). Wood Mackenzie projects these two regions will contribute 57 million tons of increased demand for Illinois Basin coal from 2013 to 2025, accounting for the majority of the domestic coal demand from the region, with the East South Central (the states of Alabama, Kentucky, Mississippi and Tennessee) and export markets primarily accounting for the remainder.

 

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As stated above, the largest projected growth in the scrubbed market is in the South Atlantic region where Wood Mackenzie expects scrubbed coal-fired electricity generation to increase from an expected 81% of total coal-fired generation in 2013 to 100% in 2025, contributing to an increase in Illinois Basin coal demand of approximately 50 million tons over the same period. In the East North Central region, scrubbed coal-fired electricity generation is expected to increase from an expected 59% of total coal fired generation in 2013 to 100% in 2025, contributing to an addition of 7.5 million tons to Illinois Basin demand over the same period. The following table shows forecast regional demand for Illinois Basin coal for electric generating units by generating region and the percentage of projected scrubbed fleet capacity, based on Wood Mackenzie data:

Illinois Basin Consumption by Electric Power Generating Region

 

Regional Demand for ILB Coal (short tons in millions)		Regional Coal-fired Generation Capacity (% Scrubbed)

 

 

Source: Wood Mackenzie, November 2013.

Note: SAT, ENC, and ESC correspond to South Atlantic, East North Central, and East South Central regions, respectively.

 

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Seaborne Coal Market

Wood Mackenzie estimated total seaborne thermal coal demand in 2013 would be approximately 951 million metric tonnes. The seaborne coal markets for thermal coal consist of the Atlantic market and the Pacific market. The Atlantic market largely consists of countries in Europe, the Mediterranean region, North America, South America and Central America. The Atlantic market’s largest consuming countries for seaborne thermal coal are the United Kingdom, Germany, Italy, Turkey, Spain and France. The Pacific market largely consists of countries in Asia and Oceania. The Pacific market’s largest consuming countries for imported seaborne thermal coal are China, Japan, Korea, Taiwan and India. The table below highlights the historical and forecasted growth in the seaborne thermal coal market according to Wood Mackenzie:

Global Thermal Seaborne Demand

(metric tonnes in millions)

 

 

Source: Wood Mackenzie, November 2013.

According to Wood Mackenzie, Atlantic market and Pacific market seaborne thermal coal demand was 215 million and 681 million metric tonnes, respectively, for 2012. Nearly all major coal-consuming countries in Asia are expected to experience significant demand growth; however, China and India are expected to account for the largest portion of the increase. Wood Mackenzie projects total demand for seaborne thermal coal to increase from 896 million metric tons in 2012 to over 1.4 billion metric tonnes by 2025. The following charts illustrate estimated demand growth for U.S. seaborne exports by basin between 2013 and 2030:

 

U.S. Thermal Coal Supply to Atlantic Basin		U.S. Thermal Coal Supply to Pacific Basin

 

 

Source: Wood Mackenzie, November 2013.

Coal Production and Supply

China is the world’s largest producer of coal with approximately 47% of the world’s coal production, according to the 2013 BP Statistical Review. In 2012, China was followed by the United States (13%), Australia (6%), Indonesia (6%), India (6%), Russia (4%) and South Africa (4%).

 

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United States Coal Production

According to the EIA, in addition to being the second largest coal producer in the world, the United States is the largest holder of coal reserves in the world, with over 250 years of supply at current production rates according to the EIA. U.S. coal production was 1.0 billion tons in 2012 according to the EIA. Although total annual domestic coal production has been relatively stable at approximately 1.0 billion tons since 1990, the basins contributing to the industry have experienced significant changes. Notably, low cost production from the Powder River Basin and Illinois Basin has offset high cost production from Central and Northern Appalachia over the reported time frame. Wood Mackenzie forecasts that thermal coal production in the United States will increase 16.3% from 2012 to 2025, and will primarily support scrubbed domestic coal-fired generating units together with increasing demand from the seaborne markets. The following table sets forth historical production statistics in each of the major U.S. coal producing regions for the periods indicated based on EIA data:

United States Historical Coal Production by Region

 

Coal Basin		1990				1995				2000				2005				2010				2012				2000-2012 Increase (Decrease)
		(tons in millions)
Powder River Basin			197				285				361				430				469				419				16.0	%
Central Appalachia			291				270				264				240				189				149				(43.7	)%
Northern Appalachia			164				137				140				141				128				125				(10.5	)%
Illinois Basin			141				109				88				95				107				128				44.7	%
Other			225				228				225				227				191				203				(9.7	)%
Total U.S. Coal Production			1,018				1,030				1,078				1,133				1,084				1,024				(5.0	)%

 

Source: Wood Mackenzie, January 2014.

Wood Mackenzie forecasts that the Illinois Basin will experience the largest coal production growth rate among major coal producing regions in the U.S. We believe this is largely a result of heightened regulatory and permitting scrutiny, deteriorating geologic conditions, rising mining costs and increased transportation expenses impacting the Appalachian Basin. The following table sets forth forecasted production statistics in each of the major U.S. coal producing regions for the periods indicated based on Wood Mackenzie data:

United States Forecasted Coal Production by Region

 

		2013E				2015E				2020E				2025E				2013-2025 Forecasted CAGR
		(tons in millions)
Powder River Basin(1)			418				503				536				545				2.2	%
Central Appalachia(1)			79				33				18				17				(12.2	)%
Northern Appalachia(1)			108				127				111				92				(1.4	)%
Illinois Basin(1)			131				153				202				207				3.9	%
Metallurgical			84				82				79				78				(0.6	)%
Other			191				203				222				223				1.3	%
Total U.S. Coal Production			1,011				1,100				1,168				1,161				1.2	%

 

Source: Wood Mackenzie, November 2013.

(1)	Regional data represents forecasted thermal coal production.

Wood Mackenzie estimates that Illinois Basin coal production will grow at a compound annual rate of 3.9%, from 131 million tons in 2013 to 207 million tons in 2025. Production from other U.S. thermal coal basins,

 

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excluding the Illinois Basin, is estimated to increase at a compound annual rate of 0.8% during the same period. Importantly, Illinois Basin coal production is projected to grow more sharply over the initial portion of this period (6.4% CAGR for 2013-2020) than over the latter part of the 12-year projection period (0.5% CAGR for 2020-2025).

United States Forecasted Thermal Coal Production Growth

 

2013-2020 Compound Annual Production Growth		2013-2025 Compound Annual Production Growth

 

 

Source: Wood Mackenzie, November 2013.

Coal Producing Regions

Coal is mined in over half of the states in the United States, but domestic coal production is primarily attributed to three coal producing regions: the Interior, Appalachia and the Western region. Within those three regions, the major producing centers are the Illinois Basin in the Interior region, Central Appalachia and Northern Appalachia and the Powder River Basin in the Western region. The type, quality and characteristics of coal vary within each region.

Illinois Basin

The Illinois Basin includes western Kentucky, Illinois and Indiana. The area includes reserves of bituminous coal with a heat content typically ranging from 9,700 to 12,800 Btu/lb and sulfur content ranging from 1.0% to 6.0%. Most of the coal produced in the Illinois Basin is used to produce electricity, with small amounts used in industrial applications. We believe that production of high sulfur coal in the Illinois Basin will continue to gain market share against other basins as scrubbed utilities continue to demand economically delivered high heat content coal.

The Illinois Basin is divided into several regions, including northern Illinois, central Illinois, southern Illinois, West Kentucky and Indiana, each of which has differing coal quality characteristics, transportation options and logistics. Despite its high sulfur content, coal from the Illinois Basin can generally be used by electric power generation facilities that have installed pollution control devices, such as scrubbers, to reduce emissions. Our operations are located in the southern and central regions of the Illinois Basin.

According to Wood Mackenzie, coal production in the Illinois Basin was 128 million tons in 2012, an increase of 8.9% over 2011. Wood Mackenzie forecasts that coal production in the Illinois Basin will increase from a forecasted 131 million tons in 2013 to 207 million tons in 2025, a 58% increase.

Northern Appalachia

Northern Appalachia includes Ohio, Pennsylvania, Maryland and northern West Virginia. The area includes reserves of bituminous coal with heat content generally ranging from 11,100 to 13,900 Btu/lb and sulfur content

 

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typically ranging from 1.0% to 5.0%. Thermal coal produced in Northern Appalachia is marketed primarily to electric utilities, industrial customers and the export market while metallurgical coal production is marketed to domestic and international steelmakers.

According to Wood Mackenzie, total Northern Appalachia thermal coal production was 104 million tons in 2012, a decrease of 2.7% from 2011. Wood Mackenzie forecasts that thermal production in Northern Appalachia will decline from 108 million tons in 2013 to 92 million tons in 2025, a 15% decline.

Central Appalachia

Central Appalachia includes eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The area includes reserves of bituminous coal with a heat content typically ranging from 11,500 to 14,200 Btu/lb and sulfur content typically ranging from 0.5% to 4.0%. Thermal coal produced in Central Appalachia is marketed primarily to electric utilities, industrial customers and the export market, while metallurgical coal production is marketed to domestic and international steelmakers. The combination of reserve depletion, increased regulatory standards, higher mining costs and increased geologic complexity in Central Appalachia is expected to lead to substantial production declines over the long-term. In addition, the widespread installation of additional scrubbers is expected to enable lower cost coal from the Illinois Basin and Northern Appalachia to replace coal from Central Appalachia.

According to Wood Mackenzie, total Central Appalachia thermal coal production was 91 million tons in 2012, a decline of 30.2% from 2011. Wood Mackenzie forecasts that thermal coal production in Central Appalachia will decline from 79 million tons in 2013, to 17 million tons in 2025, a 79% decline.

Powder River Basin

The Powder River Basin, or PRB, is located in Wyoming and Montana. The PRB produces sub-bituminous coal with sulfur content typically ranging from 0.2% to 0.8% and heat content typically ranging from 7,800 to 9,700 Btu. After strong growth in production over the past 20 years, growth in demand for PRB coal is expected to moderate in the future due to the slowing demand for low sulfur, low Btu coal as scrubbers proliferate, rail transportation rates increase and operating costs grow as a result of higher strip ratios.

According to Wood Mackenzie, coal production in the PRB was 419 million tons for 2012, a decrease of 9.5% from 2011. Wood Mackenzie forecasts that coal production in the PRB will increase from a forecasted 418 million tons in 2013 to 545 million tons in 2025, an increase of 30%.

Seaborne Coal Supply

Seaborne thermal coal is supplied to both the Atlantic market and the Pacific market. Colombia, Russia, South Africa, the United States and Indonesia continue to be the principal suppliers to the Atlantic seaborne thermal coal market. In 2013, Wood Mackenzie estimates the Atlantic market will account for 266 million metric tonnes of thermal coal, representing approximately 28% of the global thermal seaborne export market. Indonesia, Australia, Columbia, South Africa and Russia are the principal suppliers of the Pacific seaborne thermal coal market. In 2013, Wood Mackenzie estimates the Pacific market will account for 685 million metric tonnes of thermal coal, representing approximately 72% of the global thermal seaborne export market.

A key expected long-term trend in the seaborne thermal coal market is the developing supply imbalance in the Pacific market. As demand continues to rise in developing nations such as China and India, traditional coal exporters are expected to increase supply accordingly to meet demand. Coal producers in countries that have historically been key suppliers to Asia have experienced infrastructure constraints, rising tax and government regulations, port capacity limitations and increasing domestic demand and export restrictions, among other issues. While the Pacific market is currently in an oversupply situation, we believe that in the long-term, there

 

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will be potential for low cost producers from the United States to penetrate the Pacific markets. The chart below, based on Wood Mackenzie data, highlights the projected supply for thermal coal exports from the traditional coal producing countries:

Global Thermal Seaborne Coal Supply by Country

(metric tonnes in millions)

 

						Supply to Seaborne Market												2012-2025 CAGR
Country of Origin		2012 Actual				2013 Forecast				2015 Forecast				2025 Forecast
Australia			173				196				199				373				6.1	%
Colombia			82				80				92				126				3.4	%
Russia			100				98				97				85				(1.2	)%
South Africa			73				79				83				84				1.1	%
Indonesia			356				396				435				560				3.5	%
U.S.			58				44				35				157				7.9	%
Other Supply			63				58				47				50				(1.7	)%
Total Supply			904				951				987				1,436				3.6	%

 

Source: Wood Mackenzie, November 2013.

U.S. Coal Exports

The relatively high transportation cost associated with moving coal from the mine to an export port has traditionally been a limiting factor for the United States’ global competitiveness. Historical coal export volumes have fluctuated over the last decade ranging between 48 million tons in 2004 and 118 million tons in 2013. Of the 118 million tons of coal exported in 2013, 52 million tons was thermal coal with the balance being metallurgical coal. As shown in the table below, between 2004 and 2013 export thermal and metallurgical coal from the United States both increased 145% over the same time period.

United States Coal Exports

(tons in millions)

 

Product Type				2004				2005				2006				2007				2008				2009				2010				2011				2012				2013
Thermal Coal					21				21				22				27				39				22				26				38				56				52
Metallurgical Coal					27				29				28				32				43				37				56				70				70				66
Total U.S. Coal Exports					48				50				50				59				82				59				82				107				126				118

 

Source: EIA, January 2014

Strong demand for thermal and metallurgical coal by Chinese and Indian consumers created an imbalance in the seaborne coal markets in 2010 and 2011. Prior to that period, a portion of the Atlantic market demand had primarily been supplied from Pacific market producers like Indonesia and South Africa. In an effort to optimize ocean freight rates and meet Chinese and Indian demand, many producers in those countries sent production to Pacific markets rather than the Atlantic markets, which led to tighter supplies in the Atlantic market. We believe that over the long-term, U.S. coal will play an increasingly important role in supplying global seaborne coal markets. We believe growth will be driven by access to infrastructure, excess port capacity and increasingly more competitive delivered costs on a per Btu basis. Wood Mackenzie forecasts that total U.S. thermal seaborne and landborne coal exports will reach 160 million tons in 2025, a 210% increase over expected 2013 levels.

 

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Coal Pricing

Coal prices vary significantly based on a number of factors, including quality, supply and demand, costs, availability of substitute fuels, economic conditions, governmental regulation and weather. The two principal components of the delivered price of coal are the price of coal at the mine and the cost of transporting coal from the mine to the point of use. Spot and forward prices for coal are generally based upon various published indices traditionally accepted by both buyers and sellers. For example, the API#2 index is a common international coal price index and in addition, certain coal market intermediaries publish daily price and forward price curve information for specific Illinois Basin coal specifications. The applicable index is typically adjusted to account for transportation or quality specification variances.

We use a number of domestic and international indices to assess our business and the coal market. Illinois Basin published pricing estimates and the API#2 index are commonly used as market price reference points.

U.S. Thermal Coal Market

From January 1, 2000 through December 31, 2013, thermal coal spot prices in Central Appalachia, Northern Appalachia, the Illinois Basin and the Powder River Basin increased 192%, 275%, 146% and 158%, respectively. Throughout this period, coal prices fluctuated due largely to short to medium-term supply/demand imbalances. Thermal coal prices increased substantially in 2008 largely due to strong domestic consumption and export demand, coupled with declining inventory levels. In 2009, this trend reversed as a result of the U.S. recession and global economic downturn.

The following chart sets forth representative per ton thermal coal prices in various U.S. markets reported on a weekly basis for the period from January 1, 2004 to December 31, 2013, as reported by Bloomberg L.P.

U.S. Coal Prices

($ per ton)

 

 

Source: Bloomberg L.P., as of December 31, 2013

Note:

Central Appalachian = FOB Big Sandy Barge, 12,000 Btu, less than 1% sulfur, 13.5% ash and 10% moisture. Northern Appalachian = Pittsburgh coal seam, FOB Railcar MGA (Monongahela), 12,500-13,000 Btu, 2%-3% sulfur and 7%-9% ash content. Illinois Basin = FOB Barge, maximum 11,800 Btu, maximum of 2% sulfur and ash content of 8%-9%. Powder River Basin = FOB railcar at mine, 8,800 Btu, less than 0.3% sulfur, 5.5% ash and maximum of 30% moisture.

Seaborne Thermal Coal Market

There is a range of thermal coal qualities sold in the international market, with pricing premiums or penalties assessed based on how the specific quality characteristics compare to the index quality. For the

 

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seaborne thermal coal markets, no single producer has sufficient market share to control prices. Thus, the sales prices for seaborne thermal coal in a particular market will normally fluctuate with changes in supply and demand for the coal, currency rates, prices of transportation and other fuels and government regulations.

Between 2008 and 2012, the seaborne thermal coal market experienced a rising pricing trend. Throughout this period, coal prices fluctuated due largely to short to medium-term supply and demand imbalances and either high or low (relative to normal levels) inventory stockpiles. The Atlantic seaborne coal prices rallied in 2010 and 2011 as the result of stronger global demand (especially in China and India) outpacing supply. The economic slowdown in Europe, China and the United States is primarily responsible for a weakening of global prices that occurred in 2011 and 2012. The following chart sets forth average historical coal prices and forward curve (as of January 16, 2014) for the API#2 Index and API#4 Index, as reported by S&P Capital IQ.

Seaborne Thermal Coal Prices

(US$ per metric tonne)

 

 

Source: S&P Capital IQ., as of January 16, 2014.

Note:

Represents year-end (12/31) spot pricing through 12/31/13; 2014 and on represents median consensus annual forward pricing as of 1/16/14.

API#2 =    Cost, Insurance and Freight (CIF) at Rotterdam terminal, 6,000 Kcal/kg, under 1% sulfur.

API#4 =    Freight on Board (FOB) at Richards Bay terminal, 6,000 Kcal/kg, under 1% sulfur.

Transportation

The U.S. coal industry is dependent on a consistent and reliable transportation network connecting the various supply regions to the domestic and international markets. Railroads and barges comprise the foundation of the domestic coal distribution system, collectively handling approximately three-quarters of all coal shipments. Truck and conveyor systems typically move coal over shorter distances.

Transportation is a significant component of the total cost of coal at a customer’s point of usage. The cost to transport coal from the mine to the customer can be large relative to the value of the coal as an energy source. Coal produced in the United States for domestic consumption is generally sold free on board (FOB) at the mine or terminal and the purchaser normally bears the transportation costs from the FOB point. Seaborne coal, however, is generally sold FOB at the loading port. Based upon individual coal customer needs, a coal producer may agree to provide transportation and transportation services for the delivery of the coal to the customer in exchange for a higher price.

Following the implementation of the Clean Air Act Amendments of 1990, many utilities that did not have scrubbers chose to comply with reduced sulfur dioxide emissions mandates by purchasing emission credits or switching to lower sulfur fuels. Powder River Basin production increased from 397 million tons in 2002 to 419 million tons in 2012 as demand for these predominantly lower sulfur coals increased. During this time, some

 

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utilities that burn PRB coal were able to negotiate long-term rail contracts with one of the two Western United States railroads to manage their transportation costs. From 1994 to 2004, reported revenue per carload for these carriers was essentially unchanged, rising 10.1%. As many of the original long-term, fixed price contracts expired, unit rail charges increased significantly. From 2004 to December 31, 2013, average revenue per carload increased by an average of 86.3%.

In the Eastern United States, major export terminals for coal include the Port of New Orleans in New Orleans, Louisiana; Alabama State Docks in Mobile, Alabama; Port of Houston in Houston, Texas; Shipyard River Terminal in Charleston, South Carolina; Hampton Roads in Norfolk, Virginia; and Port of Baltimore in Baltimore, Maryland. To receive these exports, countries importing coal in both the Atlantic and Pacific seaborne markets have an established import terminal infrastructure.

 

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ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Our operations are subject to a variety of U.S. federal, state and local laws and regulations, such as those relating to employee health and safety; water discharges; air emissions; plant and wildlife protection; the restoration of mining properties; the storage, treatment and disposal of wastes; remediation of contaminants; surface subsidence from underground mining and the effects of mining on surface water and groundwater conditions. In addition, we may become subject to additional costs for benefits for current and retired coal miners employed by our contract miners.

We believe that we are in material compliance with all applicable environmental, health, safety and related requirements, including all required permits and approvals. However, there can be no assurance that violations will not occur in the future, that we will be able to always obtain, maintain or renew required permits or that changes in these requirements or their enforcement or the discovery of new conditions will not cause us to incur significant costs and liabilities in the future. Certain of our current and historical mining operations use or have used or store regulated materials which, if released into the environment, may require investigation and remediation. Under certain permits, we are required to monitor groundwater quality on and adjacent to our sites and to develop and implement plans to minimize and correct land subsidence, as well as impacts on waterways and wetlands, caused by our mining operations. In May 2013, we submitted a Corrective Action Plan for the remediation of impacts to groundwater from refuse disposal areas at our Macoupin Shay No. 1 Mine. While we cannot currently estimate our costs with any certainty, we do not expect these or other costs of compliance with existing environmental, health and safety requirements to be material during 2013 or 2014. Major regulatory requirements are briefly discussed below.

Mine Safety and Health

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

Black Lung

Under the United States Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who have been diagnosed with pneumoconiosis and are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production sold domestically of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. This tax is passed on to the purchaser under many of our coal supply agreements.

Our contract miners are required by federal and state statutes to provide benefits to their employees for claims related to black lung, and it is a cost which they are permitted to pass onto us during the terms of their contracts. All black lung taxes are current through December 31, 2013.

U.S. Environmental Laws

We are subject to various U.S. federal, state and local environmental laws. Some of these laws, as discussed below, impose stringent requirements on our coal mining operations. U.S. federal and state regulations require

 

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regular monitoring of our mines and other facilities to ensure compliance. U.S. federal and state inspectors are required to inspect our mining facilities on a frequent schedule. Future laws, regulations or orders, as well as future interpretations or more rigorous enforcement of existing laws, regulations or orders, may require increases in capital and operating costs the extent of which we cannot predict.

Surface Mining Control and Reclamation Act

The SMCRA, which is administered by the OSM, establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals from the OSM or the applicable state agency. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. Illinois has achieved primary control of enforcement through federal authorization.

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

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

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

The Abandoned Mine Land Fund, which is part of the SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to the SMCRA’s adoption in 1977. Prior to October 1, 2012, the fee was $0.315 per ton on surface-mined coal and $0.135 per ton on deep-mined coal. Effective October 1, 2012, the fee on surface-mined coal was lowered to $0.28 per ton and the fee on deep-mined coal was lowered to $0.12.

The SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act; the Endangered Species Act; the CWA; RCRA and CERCLA.

Various federal and state laws, including the SMCRA, require us to obtain surety bonds or other forms of financial security to secure payment of certain long-term obligations, including mine closure or reclamation

 

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costs. As of December 31, 2013, we had outstanding surety bonds of $45.1 million and $0.5 million in letters of credit related to these matters. Changes in these laws or regulations could require us to obtain additional surety bonds or other forms of financial security.

Clean Air Act

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

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

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

Fine Particulate Matter. The Clean Air Act requires the EPA to set standards, referred to as NAAQS, for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. The EPA promulgated NAAQS for particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM10, and for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns, or PM2.5. Meeting current or potentially more stringent new PM2.5 standards may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of the new PM2.5 standard will affect many power plants and coke plants, especially coal-fired power plants and all plants in non-attainment areas. Continuing non-compliance could prevent issuance of permits to facilities within the non-attainment areas

Ozone. Significant additional emissions control expenditures will be required at coal-fired power plants and coke plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers and coke plants will continue to become more demanding in the years ahead. More stringent NAAQS in the future for ozone could increase the costs of operating coal-fired power plants.

Cross-State Air Pollution Rule. The CSAPR, which was intended to replace the previously developed CAIR, requires states to reduce power plant emissions that contribute to ozone or fine particle pollution in other states. Under the CSAPR, emissions reductions were to have started January 1, 2012, for SO2 and annual NOx reductions, and May 1, 2012, for ozone season NOx reductions. Several states and other parties filed suits in the United States Court of Appeals for the District of Columbia Circuit in 2011 challenging the CSAPR. On August 21, 2012, the D.C. Circuit vacated the CSAPR and ordered the EPA to continue administering CAIR, pending the promulgation of a replacement rule. It is unclear what effect, if any, CAIR will have on our operations or results. On June 24, 2013, the United States Supreme Court agreed to review the D.C. Circuit’s August 21, 2012 decision regarding the CSAPR. It is unclear what the outcome of Supreme Court review will entail. More stringent emissions limitations required by the EPA’s now ineffective rule could increase the costs of operating coal-fired power plants and affect demand for coal.

 

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Mercury and Air Toxic Standards. On December 16, 2011, the EPA issued the MATS to reduce emissions of toxic air pollutants, including mercury, other metals and acid gases, from new and existing coal and oil fired power plants. Under the final rule, existing power plants will have up to four years to comply with the MATS by installing or upgrading pollution controls, fuel switching, or using existing emissions controls as necessary to meet the compliance deadline. These requirements could significantly increase our customers’ costs and cause them to reduce their demand for coal, which may materially impact our results or operations.

Greenhouse Gases. Increasing concern about GHG, including carbon dioxide, emitted from burning coal at electric generation plants has led to efforts at all levels of government to reduce their emissions, which could require utilities to burn less or eliminate coal in the production of electricity. Congress has considered federal legislation to reduce GHG emissions which, among other things, could establish a cap and trade system for GHG, including carbon dioxide emitted by coal burning power plants, and requirements for electric utilities to increase their use of renewable energy such as solar and wind power. Also, the EPA has taken several recent actions under the Clean Air Act to regulate GHG emissions. These include the EPA’s finding of “endangerment” to public health and welfare from GHG, its issuance in 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule, which requires large sources, including coal-fired power plants, to monitor and report GHG emissions to the EPA annually starting in 2011, and issuance of its Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which requires large industrial facilities, including coal-fired power plants, to obtain permits to emit, and to use best available control technology to curb, GHG emissions. The EPA also recently proposed new source performance standards for GHG for new coal and oil-fired power plants, which could require partial carbon capture and sequestration to comply. While the EPA’s actions are subject to legal challenges and efforts are underway in Congress to limit or remove the EPA’s authority to regulate GHG emissions, they will remain in effect unless altered by the courts or Congress.

Regional Emissions Trading. Nine Northeast and Mid-Atlantic states have cooperatively developed a regional cap and trade program, the RGGI, intended to reduce carbon dioxide emissions from power plants in the region. There can be no assurance at this time that this, or similar state or regional carbon dioxide cap and trade programs, in the states where our customers operate, will not adversely affect the future market for coal in the region.

Regional Haze. The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could adversely affect the future market for coal.

Resource Conservation and Recovery Act

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

Subtitle C of the RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under the RCRA. Following a large spill of coal ash waste at a coal burning power plant in Tennessee in June 2010, the EPA proposed two alternative sets of regulations governing the management and storage of coal ash: one would regulate coal ash and related ash impoundments at coal-fired power plants under federal regulations governing hazardous solid waste under Subtitle C of the RCRA and the other would regulate coal ash as a non-hazardous solid waste under Subtitle D. If the EPA determines to regulate coal ash as a hazardous waste, it would become subject to a variety of hazardous waste regulations, thus increasing the compliance obligations and costs of coal ash management. The EPA recently announced that it expects to issue a final rule towards the end of

 

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2014. In addition, environmental groups filed a notice of intent to sue the EPA for failing to update effluent limitation guidelines under the Clean Water Act for coal-fired power plants to limit discharges of toxic metals from handling of coal combustion waste. In April 2013, the EPA released its proposed revised effluent limitation guidelines to address toxic pollutants discharged from power plants, including discharges from coal ash ponds. If the EPA adopts new Clean Water Act requirements, compliance obligations for handling, transporting, storing and disposing of the material would likely increase. Potential changes to all of these rules could make coal burning more expensive or less attractive for electric utilities.

Most state hazardous waste laws exempt coal combustion waste and instead treat it as either a solid waste or a special waste. These laws may also be revised. Any costs associated with handling or disposal of coal ash as hazardous wastes would increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, potential liability for contamination caused by the past or future use, storage or disposal of ash could substantially increase.

Clean Water Act of 1972

The CWA established in-stream water quality standards and treatment standards for waste water discharge through the NPDES. Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.

TMDL regulations establish a process by which states may designate stream segments as “impaired” (not meeting present water quality standards). Industrial dischargers, including coal mines and plants, will be required to meet new TMDL effluent standards for these stream segments. The adoption of new TMDL regulations in receiving streams could hamper or delay the issuance of discharge and Section 404 permits, and if issued, could require new effluent limitations for our coal mines and could require more costly water treatment, which could adversely affect our coal production or results of operations. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality.” These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality streams will be required to meet or exceed new “high quality” standards. The designation of high quality streams at or in the vicinity of our coal mines could require more costly water treatment and could adversely affect our coal production or results of operations.

CERCLA and Similar State Superfund Statutes

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

Permits

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

The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the

 

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environmental data. The mine and reclamation plan incorporates the provisions of the SMCRA, the state programs and the complementary environmental programs that affect coal mining, including the CWA.

Required permits include mining and reclamation permits under the SMCRA, issued by the IDNR, and wastewater discharge, or NPDES, permits under the CWA, issued by the IEPA. In addition to the required permits, for surface operations, the mining companies also need to obtain air quality permits from IEPA, fill and dredge permits from the United States Army Corps of Engineers and flood plain permits from the IDNR. For refuse disposal operations, the mining companies may need to obtain impounding permits or underground slurry disposal permits from the IDNR. In addition, MSHA approval for ventilation, roof control and numerous specific surface and underground operations must be obtained and maintained. The authorization and permitting requirements imposed by these and other governmental agencies are costly and may delay development or continuation of mining operations. Due to the fact that the application review process may take years to complete and permit applications are increasingly being challenged by environmental and other advocacy groups, we may experience difficulty or delays in obtaining mining permits or other necessary approvals, or even face denials of permits altogether.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review, technical review and public notice and comment period before it can be approved. Some SMCRA and CWA permits can take over a year to prepare, depending on the size and complexity of the mine and often take six months or years to receive approval. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

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

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

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

 

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MANAGEMENT

Management of Foresight Energy LP

We are managed and operated by the board of directors and executive officers of our general partner, Foresight Energy GP LLC, a subsidiary of Foresight Reserves. As a result of owning our general partner, Foresight Reserves will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the NYSE. At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

Upon the closing of this offering, we expect that our general partner will have five directors, one of whom will be independent as defined under the standards established by the NYSE and the Exchange Act. We currently expect that within one year of the listing of our common units on the NYSE our general partner will have seven directors, three of whom will be independent. The NYSE does not require a listed publicly traded limited partnership, like us, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering. Foresight Reserves will appoint at least one member of the audit committee to the board of directors of our general partner by the date our common units first trade on the NYSE.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of Foresight Reserves. The amount of time that our executive officers will devote to our business and the business of Foresight Reserves will vary in any given year based on a variety of factors. We expect that our executive officers will devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. However, our executive officers’ fiduciary duties to Foresight Reserves and other obligations may prevent them from devoting sufficient time to our business and affairs.

Following the consummation of this offering, neither our general partner nor Foresight Reserves will receive any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner for all expenses they incur and payments they make 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. Please read “Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions.”

In evaluating director candidates, Foresight Reserves will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

 

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The following table shows information for the executive officers and directors of our general partner upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers. Some of our directors and all of our executive officers also serve as executive officers of Foresight Reserves.

 

Name		Age				Position
Christopher Cline			55			Chairman of the Board of Directors and Principal Strategy Advisor
Michael J. Beyer			55			Director and President & Chief Executive Officer
John F. Dickinson			65			Director
E. Hunter Harrison			69			Director
E. Bartow Jones			36			Director
Oscar A. Martinez			44			Senior Vice President—Chief Financial Officer
Christopher Moravec			58			Senior Vice President
Rashda M. Buttar			45			Senior Vice President—General Counsel & Corporate Secretary
H. Drexel Short			57			Senior Vice President

Christopher Cline is our Chairman of the Board of Directors and Principal Strategy Advisor. Mr. Cline has more than 30 years of experience in the coal industry. After attending Marshall University, he developed and operated over 25 coal mining, processing and transportation facilities in the Appalachian Region and the Illinois Basin, including some of the most productive longwall mining operations in the country. During the past five years, Mr. Cline has focused his efforts primarily on developing Foresight. The experience and qualifications that led to the conclusion that Mr. Cline should serve as a Director include his formation and leadership of the Partnership since its inception, significant and broad experience in the coal industry and his proven business acumen.

Michael J. Beyer is a director and our President and Chief Executive Officer. Mr. Beyer has more than 30 years of experience in management, operations, finance and acquisitions related to coal and other energy-related businesses. Before joining Foresight, Mr. Beyer served as President of AEP Coal, Inc. from 2002 to 2006, Vice President of Business Development at Enron Corp. from 1997 to 2002 and, prior thereto, Senior Vice President and Manager of the Natural Resource Department at PNC Bank. Mr. Beyer received his Masters in Business Administration from Duquesne University and his undergraduate degree in Mining Engineering from Pennsylvania State University. The experience and qualifications that led to the conclusion that Mr. Beyer should serve as a Director include his effective leadership of the Partnership’s operations, extensive experience in the energy and financial services industries and his strong operating and technical knowledge of all aspects of the Company’s business.

John F. Dickinson is a member of our Board of Directors. Since 1992, Mr. Dickinson has been the President of the Cline Group, the coal exploration and development group founded by Christopher Cline. Since September 2007, Mr. Dickinson has been a member of the Board of Managers of Foresight Reserves. Prior to joining the Cline Group in 1992, Mr. Dickinson worked for U.S. Steel Mining Company Inc. from 1969 to 1995, serving as President from 1988 to 1995. Mr. Dickinson has more than 45 years of experience in the coal industry. Mr. Dickinson received his undergraduate degree in Mining Engineering from Virginia Polytechnic Institute. The experience and qualifications that led to the conclusion that Mr. Dickinson should serve as a Director include his involvement with the Partnership since its inception, extensive experience in the coal industry and his strong operating and technical knowledge of exploration and mining.

E. Hunter Harrison is a member of our Board of Directors. Mr. Harrison is the Chief Executive Officer of Canadian Pacific Railway Limited (NYSE: CP) since 2012. Previously, Mr. Harrison served as President and Chief Executive Officer of Canadian National from 2003 to 2009 and as the Executive Vice President and Chief Operating Officer from 1998-2002. He served on CN’s Board of Directors for 10 years. Mr. Harrison has almost

 

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50 years of experience in the railroad industry. Mr. Harrison has served as a director on several railway companies and industry associations, including The Belt Railway of Chicago, Wabash National Corporation, The American Association of Railroads, Terminal Railway, TTX Company, CN, IC, and ICRR. The experience and qualifications that led to the conclusion that Mr. Harrison should serve as a Director include his deep and extensive experience in the railroad industry, his executive leadership of significant organizations and his management experience with public companies.

E. Bartow Jones has been a member of our Board of Directors since 2007. Mr. Jones is currently a Partner at Riverstone Holdings LLC where he served as a Managing Director from 2010 to 2014 and a Principal from 2007 to 2010. Mr. Jones has been with Riverstone since 2001. Mr. Jones currently serves on the boards of directors of Foresight Reserves, Niska Gas Storage Partners LLC, Targe Energy, LLC, Legend Production Holdings, Vantage Energy LLC, Vantage Energy II, LLC and Quintana Shipping Ltd, and he previously served on the boards of directors of Buckeye GP LLC, the general partner of Buckeye Partners, LP, and Mainline Management LLC, the general partner of Buckeye GP Holdings L.P. and PVR GP, LLC, the general partner of PVR Partners, L.P. Mr. Jones received his undergraduate degree in commerce with concentrations in both finance and accounting from the McIntire School of Commerce at the University of Virginia. The experience and qualifications that led to the conclusion that Mr. Jones should serve as a Director include his experience and role with portfolio companies, significant understanding of the challenges facing public companies and involvement with a range of various energy companies.

Oscar A. Martinez is the Senior Vice President—Chief Financial Officer. Before joining Foresight in August 2011, Mr. Martinez served as Vice President and Treasurer at Cloud Peak Energy, Inc. from 2009 to July 2011. Prior to joining Cloud Peak Energy, Inc., Mr. Martinez worked for Qwest Communications International, Inc. from 2002 to 2009 where he served most recently as the Vice President and Assistant Treasurer. Mr. Martinez also held positions in Corporate Strategy and Capital Markets with Qwest Communications International. Prior to joining Qwest, Mr. Martinez worked as an investment banker with JP Morgan Chase. Mr. Martinez received his Masters in Business Administration from Harvard Business School and his undergraduate degree in Business Administration from Trinity University.

Chris Moravec is a Senior Vice President of the Company. Before joining Foresight in June 2012, Mr. Moravec was the Executive Vice President of Rhino Resource Partners LP from 2007 to 2012. During this period, Mr. Moravec also served on the board of directors for Rhino Eastern, a West Virginia-based metallurgical coal operation structured as a joint-venture with Patriot Coal Corporation. Prior to joining Rhino Resource Partners LP, Mr. Moravec worked for PNC Bank providing both direct and investment banking services exclusively to the coal industry. Mr. Moravec received his undergraduate degree in Mining Engineering from West Virginia University and a Masters in Business Administration from the University of Pittsburgh.

Rashda M. Buttar is the Senior Vice President—General Counsel & Corporate Secretary. Before joining Foresight in September 2011, Ms. Buttar served as Vice President, Associate General Counsel and Corporate Secretary of Patriot Coal Corporation from 2007 to August 2011. Prior to joining Patriot Coal Corporation, Ms. Buttar served as the Assistant General Counsel and Assistant Corporate Secretary of TALX Corporation from 2003 to 2007. Ms. Buttar received her Juris Doctor from Saint Louis University School of Law and her undergraduate degree in Russian and Eastern European Studies and Political Science from Saint Louis University.

H. Drexel Short is the Senior Vice President. Mr. Short has more than 30 years of experience in managing underground coal mining operations, having begun his career as an underground mine production supervisor and superintendent. Prior to joining Foresight in 2007, Mr. Short served as Senior Vice President—Group Operations for A.T. Massey Coal Co., Inc. from 1995 to 2007, Chairman of the Board of Directors and Chief Coordinating Officer of Massey Coal Services, Inc. and President of Elk Run Coal Company (a subsidiary of Massey Energy). Mr. Short received his undergraduate degree in Mining Engineering from the University of Kentucky.

 

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Director Independence

In accordance with the rules of the NYSE, Foresight Reserves must appoint at least one independent director prior to the listing of our common units on the NYSE, one additional member within three months of that listing, and one additional independent member within 12 months of that listing.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will approve equity grants to directors and employees.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management.

Conflicts Committee

At least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest adverse to the interest of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Foresight Reserves, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

 

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EXECUTIVE COMPENSATION

We are providing compensation disclosure that satisfies the requirements applicable to emerging growth companies, as defined in the JOBS Act.

Summary Compensation Table for the Fiscal Year Ended December 31, 2013

The following summary compensation table and related narrative disclosure present the compensation provided during fiscal year 2013 to the principal executive officer and the next two most highly compensated executive officers of our general partner (our “named executive officers” or “NEOs”). In addition to our executive officers, Chris Cline, the Partnership’s founder, serves as our Principal Strategy Advisor. In this role, he is closely involved in setting strategy and guiding major decisions affecting the Partnership.

 

Name and Principal Position		Year				Salary ($)				Bonus ($)				Non-Equity Incentive Plan Compensation ($)				All Other Compensation ($) (2)				Total ($)
Michael J. Beyer,			2013			$	618,000			$	700,000				N/A			$	59,422			$	1,377,422
President and Chief Executive Officer
H. Drexel Short,			2013			$	750,000			$	300,000				N/A			$	13,033			$	1,063,033
Senior Vice President
Christopher Moravec,			2013			$	500,000			$	350,000			$	41,667	(1)		$	90,953			$	982,620
Senior Vice President

 

(1)

Amount included reflects the value of one-third of a long-term incentive compensation award granted to Mr. Moravec in December 2012 that became vested in December 2013. The award vests in three equal installments on each of the first three anniversaries of the grant date so long as Mr. Moravec remains continuously employed through each such date. For additional information regarding this award, please refer to “Narrative Disclosure to Summary Compensation Table—Long-Term Incentive Compensation Award” below.

(2)

The amounts noted in “All Other Compensation” for 2013 reflect the cost of (i) for Mr. Beyer: his country club membership dues of $19,702 that we paid on his behalf, personal travel on corporate aircraft of $29,299, annual life insurance premiums paid on a life insurance policy for his benefit and matching contributions made to the 401(k) plan on his behalf; (ii) for Mr. Short: a car allowance of $2,400, annual life insurance premiums paid on a life insurance policy for his benefit and matching contributions made to the 401(k) plan on his behalf; and (iii) for Mr. Moravec: a housing allowance of $57,000, a car allowance of $24,996, annual life insurance premiums paid on a life insurance policy for his benefit and matching contributions made to the 401(k) plan on his behalf.

Narrative Disclosure to Summary Compensation Table

Long-Term Incentive Compensation Award

In December 2012, we granted a long-term incentive compensation award to Mr. Moravec. The award vests in three equal installments on each of the first three anniversaries of the grant date so long as Mr. Moravec remains continuously employed through each such date. Each installment of the award that becomes vested prior to the completion of this offering is payable in cash on the next payroll date following the vesting date. Following the completion of this offering, each installment of the award that becomes vested will be paid to Mr. Moravec in the form of fully vested common units issued pursuant to our general partner’s Long-Term Incentive Plan, which is described in more detail below under “Additional Narrative Disclosure—Long-Term Incentive Plan.”

Bonuses

For 2013, discretionary bonuses were awarded to each of our NEOs in recognition of their respective individual contributions to the company, to successful mining operations and to our overall performance during the 2013 fiscal year.

 

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Outstanding Equity Awards at Fiscal Year-End 2013

Our named executive officers did not have any outstanding equity awards as of December 31, 2013.

Additional Narrative Disclosure

Retirement Benefits

We have not maintained, and do not currently maintain a defined benefit pension plan or nonqualified deferred compensation plan. In 2013, Foresight Energy Services LLC maintained a plan intended to provide benefits under section 401(k) of the Code pursuant to which eligible employees are permitted to contribute portions of their compensation into a tax-qualified retirement account. For fiscal 2013, the plan provided safe harbor matching contributions equal to 100% of the first 3% of eligible compensation contributed by a participant to his or her account and 50% of the next 2% of eligible compensation contributed.

Potential Payments upon Termination or a Change in Control

Pursuant to a phantom equity agreement between Foresight Energy Services LLC and Mr. Short, upon the termination of his employment from Foresight Energy Services LLC for any reason, Mr. Short would be entitled to a payment equal to the fair market value (calculated in accordance with the phantom equity agreement) of a one-percent limited partnership interest in 69.59409% of Foresight Reserves, L.P., plus the amount of all tax distributions he would have received had he owned equity in Foresight Reserves, L.P. in such percentage during the term of the agreement, less the amount of $3,000,000 previously paid to Mr. Short under the agreement. Foresight Energy Services LLC may pay a portion of such amount in cash and the remainder by delivery to Mr. Short of a secured promissory note guaranteed by Foresight Reserves, L.P. The note, which would be secured by a security agreement entered into by Foresight Energy Services LLC and Mr. Short in connection with the note, would accrue interest at the applicable federal rate (as determined for purposes of the Code) and would be payable in quarterly installments over a period of not longer than 10 years (three years if the payment to Mr. Short is less than $5,000,000). The note would become due and payable immediately upon a “Change of Control” (as defined in the phantom equity agreement) of Foresight Reserves, L.P. If Mr. Short’s employment had terminated effective December 31, 2013, Mr. Short would have been entitled to a payment estimated at $11,700,000.

In the event of a Change of Control of Foresight Reserves, L.P. while Mr. Short is employed by Foresight Energy Services LLC, Mr. Short would be entitled to a payment equal to one-percent of the net consideration the partners of Foresight Reserves, L.P. other than Riverstone Holdings LLC would receive in connection with such Change of Control, plus the amount of all tax distributions he would have received had he owned equity in Foresight Reserves, L.P. during the term of the agreement, less the amount of $3,000,000 previously paid to Mr. Short under the agreement. Following such payment, Mr. Short would cease to be entitled to any payment under the agreement in connection with a termination of employment (as described above). If a Change of Control had occurred on December 31, 2013, assuming the net consideration in the Change of Control was equal to the fair market value (calculated in accordance with the agreement) of a one-percent limited partnership interest in 69.59409% of Foresight Reserves, L.P., Mr. Short would have been entitled to a payment estimated at $11,700,000.

In addition, Mr. Short is entitled to a “gross-up” payment for any taxes, interests or penalties under Section 409A of the Code with respect to payments under the phantom equity agreement.

Mr. Short’s phantom equity agreement also contains restrictive covenants. For a period of one year following his termination of employment, Mr. Short shall be subject to non-competition and non-solicitation covenants with respect to Mr. Cline, Foresight Energy Services, LLC and their affiliates.

Long-Term Incentive Plan

Our general partner has adopted a Long-Term Incentive Plan, or LTIP, pursuant to which directors, officers (including the NEOs), certain employees and certain consultants of our general partner and its affiliates are

 

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eligible to receive awards with respect to our common units. The description of the LTIP set forth below is a summary of the material features of the LTIP. This summary, however, does not purport to be a complete description of all of the provisions of the LTIP and is qualified in its entirety by reference to the LTIP, a copy of which is filed as an exhibit to this registration statement.

The LTIP provides for the grant, from time to time, at the discretion of the board of directors of our general partner or of its predecessor, of unit options, unit appreciation rights, restricted units, phantom units, unit awards, other unit-based awards, distribution equivalent rights, performance awards and substitute awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of 7,000,000 common units may be delivered pursuant to awards under the LTIP. Units subject to awards that are forfeited, cancelled, exercised, paid or otherwise terminated without the delivery of units will be available for delivery pursuant to other awards under the LTIP. The LTIP is administered by the board of directors of our general partner (or of its predecessor) or a committee thereof, either of which we refer to herein as the “committee”. The LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding the directors, officers, employees and consultants of our general partner and its affiliates for superior performance, as well as by strengthening our general partner’s and its affiliates’ abilities to attract, retain and motivate individuals who are essential for our growth and profitability.

Unit Options and Unit Appreciation Rights. The LTIP permits the grant of options and unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units as of the exercise date over a specified exercise price, either in cash or in common units, as determined in the discretion of the committee. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the committee may determine, consistent with the LTIP; however, the exercise price of a unit option or unit appreciation right must be equal to or greater than the fair market value of a common unit on the date of grant.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the participant holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the participant to receive a common unit upon the vesting of the phantom unit (or on a deferred basis upon specified future dates or events) or, in the discretion of the committee, cash equal to the fair market value of a common unit. The committee may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the committee may determine are appropriate, including the period over which restricted or phantom units will vest. The committee may, in its discretion, base vesting on the participant’s completion of a period of service or upon the achievement of specified performance criteria or as otherwise described in an award agreement. Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units. The committee, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights, or DERs, are rights to receive an amount equal to all or a portion of the cash distributions made on our common units during the period a phantom unit remains outstanding. DERs may be granted as stand-alone awards or in tandem with phantom units or other awards under the LTIP.

Unit Awards. A unit award is an award of common units that are fully vested upon grant and are not subject to forfeiture. Unit awards may be paid in addition to, or in lieu of, cash or other compensation that would otherwise be payable to a participant. A unit award may be wholly discretionary in amount or it may be paid with respect to a bonus or other incentive compensation award, the amount of which is determined based on the achievement of performance criteria or other factors.

Other Unit-Based Awards. The LTIP also permits the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a unit. The vesting of an other unit-based award may be based on a participant’s continued service, the achievement of specified performance criteria or other measures. On vesting (or on a deferred basis upon specified future dates or events), an other unit-based award may be paid in cash and/or in units (including restricted units), as determined by the committee.

 

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Performance Awards. A performance award gives the participant the right to receive all or part of such award upon the achievement of specified performance criteria. Payment for performance awards may be made in cash or common units with an equivalent value, or in some combination thereof, as determined by the committee and specified in the applicable award agreement.

Substitute Awards. Substitute awards may be granted under the LTIP in substitution for similar awards held by individuals who become directors, officers, employees or consultants of our general partner or one of its affiliates as a result of a merger, consolidation, acquisition or other transaction by us or one of our affiliates of another entity or the assets of another entity.

Source of Common Units; Cost. Common units to be delivered with respect to awards under the LTIP may be common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us, one of our affiliates or any other person, new common units otherwise issuable by us or any combination of the foregoing. With respect to awards made to directors, officers, employees and consultants of our general partner and its affiliates, our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units or, with respect to unit options, for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from a participant at the time of the participant’s exercise of an option. Thus, we will bear the cost of all awards under the LTIP. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash by our general partner, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

Amendment or Termination of Long-Term Incentive Plan. The committee, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by our general partner. The committee also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially reduce the rights or benefits of a participant without the consent of the affected participant.

Director Compensation

Following the consummation of this offering, we will provide compensation to the non-employee directors of the board of directors of our general partner, as described below.

 

Element of Annual Non-Employee Director Compensation		Amount
Board Cash Retainer		$	125,000
Audit Committee Member Cash Retainer		$	15,000
Grant of Phantom Units(1)		$	75,000

 

(1)	The phantom units will vest pro rata over the three-year period from the date of grant.

It is anticipated that each non-employee director will be reimbursed for out-of-pocket expenses incurred in connection with attending meetings of the board of directors and its committees, and that each director (including each employee of our general partner who also serves as a director) will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law and our partnership agreement. Employees and executive officers of our general partner who also serve as directors will not receive additional compensation for such service.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, officers and owners, including Foresight Reserves, on the one hand, and us and our limited partners, on the other hand. Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

 

•

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

 

•

approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be deemed to be “in good faith” unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interest of the partnership. See “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

•

Amount and timing of asset purchases and sales;

 

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Cash expenditures;

 

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Borrowings;

 

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Entry into and repayment of current and future indebtedness;

 

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Issuance of additional units; and

 

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The creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of enabling our general partner or its affiliates to receive distributions on the incentive distribution rights.

In addition, our general partner may use an amount, initially equal to $         million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on the incentive distribution rights. All of these actions may affect the amount of cash or equity distributed to our unitholders and holders of incentive distributions rights. Please read “How We Make Distributions To Our Partners.”

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. See “How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Operating Surplus.”

The directors and officers of Foresight Reserves’ general partner have a fiduciary duty to make decisions in the best interests of the owners of Foresight Reserves, which may be contrary to our interests.

Because certain officers and certain directors of our general partner are also directors and/or officers of affiliates of our general partner, including Foresight Reserves, they have fiduciary duties to Foresight Reserves that may cause them to pursue business strategies that disproportionately benefit Foresight Reserves or which otherwise are not in our best interests.

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.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

Our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

 

•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was not adverse to the interest of the partnership, and, with respect to criminal conduct, did not act with the knowledge that its conduct was unlawful;

 

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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 for any acts or omissions 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 the conduct of our general partner or such officer or director engaged in by it acted in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful; and

 

•

in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. See “—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.

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

 

•

expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

 

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preparing and transmitting tax, regulatory and other filings, periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

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acquiring, disposing, mortgaging, pledging, encumbering, hypothecating, or exchanging our assets or merging or otherwise combining us with or into another person;

 

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negotiating, executing and performing contracts, conveyance or other instruments;

 

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distributing cash or cash equivalents;

 

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selecting, employing or dismissing employees, agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

 

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maintaining insurance for our benefit;

 

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forming, acquiring an interest in, and contributing property and loaning money to, any further limited partnerships, joint ventures, corporations, limited liability companies or other entity (including corporations, firms, trusts and unincorporated organizations);

 

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controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

 

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indemnifying any person against liabilities and contingencies to the extent permitted by law;

 

•

purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing additional options, rights, warrants, appreciation rights, phantom or tracking, profit and phantom interests and other derivative interests relating to, convertible into or exchangeable for our partnership interests; and

 

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entering into agreements with any of its affiliates, including to render services to us or to itself in the discharge of its duties as our general partner.

See “The Partnership Agreement” for information regarding the voting rights of unitholders.

Common units are subject to our general partner’s call right.

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 the price calculated in accordance with our partnership agreement. Please read “The Partnership Agreement—Limited Call Right.”

We may choose to not retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to 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, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, our sponsor may compete with us for investment opportunities and 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 and directors and our sponsor. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us.

 

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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 target distribution levels relating 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 our common unitholders in certain situations.

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, a baseline distribution amount 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.

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 distribution payments based on the initial target distribution levels that are less certain to be achieved. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read “How We Make Distributions To Our Partners—Partnership Interests—Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels.”

Fiduciary Duties

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

 

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The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

 

State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” meaning that it believed its actions or omissions were not adverse to the interest of the partnership, and will not be subject to any higher standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held.
		In making decisions, other than one where our general partner is permitted to act in its sole discretion, it will be presumed that in making its decisions our general partner, the board of directors of our general partner or conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.
Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

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By purchasing our common units, the purchaser agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, assuming that the underwriters do not exercise their option to purchase additional common units, Foresight Reserves and a member of management will own, directly or indirectly,     and         common units, respectively, and             and             subordinated units, respectively, representing an aggregate approximately     % limited partner interest in us respectively. In addition, Foresight Reserves and a member of management will own, and Foresight Reserves will control, our general partner. Foresight Reserves will also appoint all of the directors of our general partner, which will be issued the incentive distribution rights.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Affiliated entities principally include NRP and its affiliates, for which Chris Cline owns a beneficial interest in the general partner and limited partner interests, and Foresight Reserves and its affiliates, the owner of our general partner.

Transactions with Foresight Reserves and Foresight Energy GP LLC

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Foresight Energy LP.

Formation Stage

 

The consideration received by our general partner and its affiliates for the contribution of their interests		•                 common units;   •                  subordinated units;   •     the incentive distribution rights; and   •     We will distribute the $         million of net proceeds from this offering (after deducting the underwriting discounts, expenses and a structuring fee) to Foresight Reserves and a member of management on a pro rata basis. To the extent the underwriters exercise their option to purchase 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. Any common units not purchased by the underwriters pursuant to their option will be issued to Foresight Reserves and a member of management on a pro rata basis.   We will also agree to undertake a public or private offering of common units in the future upon request by Foresight Reserves and use the proceeds thereof (net of underwriting or placement agency discounts fees and commissions, as applicable) to redeem an equal number of common units from Foresight Reserves. Please read “—Agreements with Affiliates in Connection with the Transactions—Registration Rights Agreement.”

 

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Operational Stage

 

Distributions to our general partner and its affiliates		We will generally make cash distributions 100% to the unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.   Assuming we had sufficient available cash to pay the minimum quarterly distribution on all of our outstanding units for four quarters and were not restricted from paying cash distributions, our general partner and its affiliates would receive an annual distribution of approximately $             million on their units.
Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of Foresight Energy LP, but we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. In addition, pursuant to an administrative services agreement, Foresight Reserves will be entitled to reimbursement for certain expenses that it incurs on our behalf.

 

Liquidation Stage		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Administrative Services Agreement

In connection with the closing of this offering, we will enter into an administrative services agreement with Foresight Reserves.

Contribution Agreement

In connection with the closing of this offering, we will enter into a contribution agreement that will affect the transactions, including the transfer of the ownership interest in Foresight Energy LLC, and the use of the net proceeds of this offering. This agreement will not be the result of arm’s-length negotiations, and it, or any of the transactions that it provides for, may not be effected on terms at least as favorable to the parties to this agreement as could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

 

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Registration Rights Agreement

In connection with this offering, we will enter into a Registration Rights Agreement with Foresight Reserves. See “The Partnership Agreement—Registration Rights.”

2010 Reorganization

As part of the 2010 Reorganization, Foresight Reserves contributed Savatran (which includes the Williamson Track rail spur) and Sitran to Foresight Energy, LLC. Also, as part of the 2010 Reorganization, we entered into a series of mineral leases requiring minimum royalty payments and production royalty payments to Colt and Ruger. See “Certain Relationships and Related Party Transactions—Colt LLC and Ruger Coal Company, LLC Leases.”

2013 Reorganization

In connection with the closing of the 2013 Refinancing, we underwent a restructuring (the “2013 Reorganization”), pursuant to which:

 

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Foresight Energy LLC distributed its 100% ownership interest in Sitran (which was a wholly-owned subsidiary that conducted our transloading operations on the Ohio River) and Adena Resources (which was a wholly-owned subsidiary that provided water and other miscellaneous rights) to its owners;

 

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Each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into a transloading and storage agreement with Sitran. These agreements provide for the unloading of coal from each of Williamson, Sugar Camp, Hillsboro and Macoupin from railcars into stockpiles at Sitran and for the loading of coal from such stockpiles into barges;

 

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Hillsboro Energy LLC distributed certain transportation assets known as the “Clean Coal Handling System,” along with associated surface property underlying those assets, to Foresight Energy LLC. The owners of Foresight Energy LLC in turn contributed the assets to Hillsboro Transport LLC, a subsidiary of Foresight Reserves;

 

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Hillsboro Energy LLC and Hillsboro Transport LLC entered into a throughput agreement for Hillsboro Transport LLC to operate and maintain the Clean Coal Handling System to transport and load clean coal;

 

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An agreement was reached between Sugar Camp, LLC and Foresight Reserves under which Foresight Reserves has the right to amend Sugar Camp’s existing lease with HOD LLC for the Sugar Camp Rail Loadout to add coal produced from the second longwall at Sugar Camp. Pursuant to such amendment, the consideration paid by HOD LLC for including coal to the effect and operation of such lease will be paid directly to Foresight Reserves;

 

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Each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into agreements with Adena Resources for the use of certain water rights and facilities owned or controlled by Adena Resources;

 

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Savatran and Hillsboro Energy LLC agreed to distribute to New River Royalty, LLC (an affiliate of Foresight Energy LLC) up to 2,500 acres of surface land;

 

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Hillsboro Energy LLC entered into a development agreement with Colt, pursuant to which Hillsboro Energy LLC has the right to offer Colt the ability to develop additional longwall coal mines and associated transportation infrastructure in coal reserves leased by Colt to Hillsboro Energy LLC. If Colt develops a mine, Hillsboro Energy LLC would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement;

 

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Macoupin Energy LLC entered into a development agreement with Colt, pursuant to which Macoupin Energy LLC will have the right to offer Colt the ability to develop an additional longwall coal mine

 

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and associated transportation infrastructure in coal reserves leased by Colt to Macoupin Energy LLC. If Colt develops a mine, Macoupin Energy LLC would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement; and

 

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Sugar Camp Energy, LLC entered into a development agreement with Ruger, pursuant to which Sugar Camp Energy, LLC has the right to offer Ruger the ability to develop additional longwall coal mines and associated transportation infrastructure in coal reserves leased by Ruger to Sugar Camp Energy, LLC or where Sugar Camp Energy, LLC has the right to mine by virtue of an overriding royalty agreement with Ruger. If Ruger develops a mine, Sugar Camp Energy, LLC would have the right, but not the obligation, to buy the mine and use the transportation assets under a throughput agreement.

New Sitran Agreements

In connection with the 2013 Reorganization, each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into a transloading and storage agreement with Sitran. These agreements provide for the unloading of coal from each of Williamson, Sugar Camp, Hillsboro and Macoupin from railcars into stockpiles at Sitran and for the loading of coal from stockpiles into barges. Under these agreements each mine will pay Sitran $1.50 per ton of coal offloaded, stored or transloaded at Sitran’s facility. Each agreement has an initial term of three years and will renew automatically for successive one year periods unless terminated by either party. The rates per ton of coal unloaded or loaded will escalate each year by four percent. Subsequent to the 2013 Reorganization date and through December 31, 2013, the mines incurred $3.7 million in transloading fees with Sitran.

Hillsboro Throughput Agreement

Concurrent with the 2013 Reorganization, a throughput agreement was entered into between Hillsboro Energy LLC and Hillsboro Transport LLC for Hillsboro Transport LLC to operate the Clean Coal Handling System for Hillsboro Energy LLC. The agreement, which has an initial term of ten years, grants Hillsboro Transport LLC the right to be the exclusive provider of clean coal handling services for Hillsboro Energy. After the initial ten-year term of the throughput agreement, the parties can agree to continue renewing the agreement in five-year increments (up to 16 times). At the expiration of each term, Hillsboro Energy, LLC has an option to acquire the Clean Coal Handling System for its then fair value. As compensation for operating and maintaining the Clean Coal Handling System, Hillsboro Transport will receive $0.99 per ton for every ton of coal loaded through the Clean Coal Handling System, subject to a minimum quarterly payment of approximately $1.25 million beginning on January 1, 2014. Subsequent to the 2013 Reorganization date, Hillsboro Transport LLC was determined to be a variable interest entity and Hillsboro Energy LLC continues to consolidate Hillsboro Transport LLC as the primary beneficiary. See our audited historical consolidated financial statements, and notes thereto, included elsewhere in this prospectus. Subsequent to the 2013 Reorganization date, Hillsboro Transport earned net income of $2.0 million under the throughput agreement, which is recorded as income attributable to noncontrolling interests in our consolidated statement of operations.

Adena Water Resources Agreements

Adena Resources has various contractual water rights contracts with various state and local governments that are used to provide water to certain Foresight Energy mines. Concurrent with the distribution of Adena Resources to Foresight Reserves, each of Williamson Energy, LLC, Sugar Camp Energy, LLC, Hillsboro Energy LLC and Macoupin Energy LLC entered into an agreement with Adena Resources providing for water resources to be available at each of the mines for use in mining operations. The agreements, which have an initial term of three years, will automatically renew for successive periods of one year unless either party opts out of the agreement. As compensation for furnishing water to the mines, the mines will pay Adena Resources the actual cost incurred by Adena Resources in furnishing water to the mine plus an annual administrative fee in the amount of $10,000. The mines are also responsible for reimbursing Adena Resources for any future capital expenditures

 

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necessary to fulfill its obligations under the agreements. Subsequent to the 2013 Reorganization date, Adena Resources was determined to be a variable interest entity and Foresight Energy continues to consolidate Adena Resources as the primary beneficiary. See our audited historical consolidated financial statements, and notes thereto, included elsewhere in this prospectus. The costs incurred by Adena Resources subsequent to the 2013 Reorganization date were de minimis.

Hillsboro 2 and 3 Development Agreement

In connection with the 2013 Reorganization, Hillsboro entered into a development agreement with Colt (the “Hillsboro Development Agreement”). Pursuant to the Hillsboro Development Agreement, Hillsboro put in place the right to offer Colt the ability to develop one or two additional longwall coal mines, previously identified as the “Hillsboro 2” and “Hillsboro 3” longwall mines and associated transportation infrastructure in coal reserves leased by Colt to Hillsboro. If Colt accepts the offer to develop a mine and associated transportation related infrastructure, Hillsboro will automatically acquire the option to purchase the fully developed mines, but not the transportation assets, for fair market value. Hillsboro will have the right to exercise this fair market value purchase option during a twelve month period that begins when Colt has first sold 100,000 tons of clean coal produced by the longwall method from any new mine. Hillsboro will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Colt develops a mine and Hillsboro elects not to exercise its option to purchase the mine, Hillsboro will surrender its rights to the coal associated with that mine under its lease with Colt.

Macoupin Low Sulfur Longwall Development Agreement

In connection with the 2013 Reorganization, Macoupin entered into a development agreement with Colt (the “Macoupin Development Agreement”). Pursuant to the Macoupin Development Agreement, Macoupin put in place the right to offer Colt the ability to develop one longwall coal mine and associated transportation infrastructure in coal reserves previously identified by Macoupin for a low sulfur longwall mine. If Colt accepts the option to develop the mine and associated infrastructure, then Macoupin will automatically acquire the option to purchase the fully developed mine, but not the transportation assets, for fair market value. Macoupin will have the right to exercise this fair market value purchase option during a twelve month period that begins when Colt has first sold 100,000 tons of clean coal produced by the longwall method from the new mine. Macoupin will not have an option to purchase the fully developed transportation assets, but will pay a commercially reasonable fair market price for their use. In the event Colt develops a mine, and Macoupin elects not to purchase the mine, Macoupin will surrender its rights to the coal associated with that mine under its lease with Colt.

Sugar Camp 3 and 4 Development Agreement

In connection with the 2013 Reorganization, Sugar Camp entered into a development agreement with Ruger (the “Sugar Camp Development Agreement”). Pursuant to the Sugar Camp Development Agreement, Sugar Camp put in place the right to offer Ruger the ability to develop one or two additional longwall coal mines and associated transportation infrastructure in coal reserves either leased by Ruger to Sugar Camp or reserves where Ruger has granted Sugar Camp the right to mine coal and pay a royalty to Ruger. These areas have been previously identified by Sugar Camp as the “Sugar Camp 3” and “Sugar Camp 4” longwall mines. If Ruger accepts the option to develop the mine and associated infrastructure, then Sugar Camp will automatically acquires the option to purchase the fully developed mine, but not the transportation assets, for fair market value. Sugar Camp will have the right to exercise this fair market value purchase option during a twelve month period that begins when Ruger has first sold 100,000 tons of clean coal produced by the longwall method from any new mine. Sugar Camp will not have an option to purchase the fully developed transportation assets, will pay a commercially reasonable fair market price for their use. In the event Ruger develops a mine and Sugar Camp elects not to purchase the mine, Sugar Camp will surrender its rights to the coal associated with that mine under its lease and overriding royalty agreement with Ruger.

 

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Natural Resource Partners, L.P. Transactions

We have engaged in a series of transactions with NRP, an entity in which Christopher Cline directly and indirectly beneficially owns less than 4.9% of the limited partnership interests. Christopher Cline also directly and indirectly owns 31% of the limited partnership interests in NRP’s general partner. Foresight Reserves and its subsidiaries have sold to NRP or subsidiaries of NRP certain coal reserves and transportation assets in exchange for equity in NRP and its general partner as well as entering into a restricted business contribution agreement and leases under which we will make royalty payments and pay fees as we mine leased coal and use leased transportation facilities owned by NRP, all as more further described below.

In May 2005, we entered into coal mining lease agreements with Steelhead Development Company, LLC, an affiliate through common ownership. These reserves were subsequently sold to WPP, a subsidiary of NRP, as part of a three-stage transaction throughout 2005 and 2006. The amended and restated lease agreement allows for the mining, processing and transporting of approximately 144 million tons of coal reserves located in Illinois. The term of this agreement is 15 years and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed. Also, the lease requires our subsidiary, Williamson Energy, LLC, to pay minimum royalties, tonnage royalties based on the tonnage sold and wheelage. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Coal and Surface Leases and Overriding Royalties” for a description of the material terms of this lease. During the years ended December 31, 2013 and 2012, Williamson Energy, LLC paid $21.9 million and $20.3 million, respectively, in royalties and other payments to WPP under this coal lease.

On January 4, 2007, the Adena Entities sold NRP four additional entities which owned approximately 49 million tons of coal reserves in West Virginia and Illinois, including 12 million tons adjacent to leased reserves at Williamson in southern Illinois, as well as associated transportation and infrastructure assets at these mines. In conjunction with this transaction, the Adena Entities and NRP executed a restricted business contribution agreement. The restricted business contribution agreement obligates the Adena Entities and their affiliates to offer NRP any business owned, operated or invested in by the Adena Entities, subject to certain exceptions, that either (a) owns, leases or invests in hard minerals or (b) owns, operates, leases or invests in identified transportation infrastructure relating to certain future mine developments by the Adena Entities in Illinois. NRP’s acquisition of certain coal reserves and infrastructure assets related to our Macoupin, Hillsboro and Sugar Camp mining complexes, discussed more fully below, were deals consummated under the restricted business contribution agreement with the Adena Entities. We expect to consummate additional deals under the Restricted Business Contribution Agreement in the future, including an offer to NRP to purchase certain infrastructure assets at Hillsboro and a dock servicing mining projects in Southern Illinois.

One of the entities sold by the Adena Entities to NRP was Williamson Transport, which has surface rights at Williamson for the Williamson Rail Load Out facility. Williamson leases this property from Williamson Transport LLC under two surface leases with initial terms through October 15, 2031 and an option to extend the leases in five year increments until all the coal leased from an NRP affiliate is mined on Williamson’s premises. Williamson Transport has the option to put the land to Williamson for its fair market value as determined by an independent appraiser at any time during the lease term. Additionally, under a separate lease with an initial term through March 12, 2018, Williamson pays $5,000 per year for use of the premises and a fee currently at $1.77 per ton for each ton of coal produced at Williamson that is loaded through the Williamson Rail Load Out facility, which escalates approximately $0.02 per year throughout the term of the agreement. Williamson Transport may elect to renew or extend the sublease for successive five-year periods. If Williamson Transport elects not to renew the sublease, Williamson Energy, LLC has the option to buy the Williamson Rail Load Out facility for its fair market value as determined by an independent appraiser. Mach Mining, LLC receives a fee of $0.25 per ton from Williamson Transport for each ton of coal that is loaded through the Williamson Rail Load Out facility in exchange for operating the load out. During the years ended December 31, 2013 and 2012, Williamson Transport was paid $10.2 million and $11.7 million, respectively, under these leases (net of the operating fee paid to Mach Mining, LLC).

 

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Another of the entities sold by the Adena Entities to NRP on January 4, 2007 was Independence Energy, LLC, which had previously been owned by Foresight Reserves. We had previously entered into a coal mining lease with Independence Energy, LLC to lease a certain tract of approximately 3,500 acres adjacent to the Williamson mining complex to perform certain mining activities on the tract. The term of this agreement is 15 years and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed. In addition to tonnage royalties, minimums and wheelage fees under the lease, we entered into a separate agreement with Independence which requires us to make certain overriding royalty payments as well. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Coal and Surface Leases and Overriding Royalties” for a description of the material terms of this coal lease and overriding royalty agreement. During the years ended December 31, 2013 and 2012, Williamson Energy, LLC paid $6.0 million and $9.5 million, respectively, in royalties and other payments to Independence.

Williamson Energy, LLC is obligated to pay overriding royalties to WPP, an affiliate of NRP, pursuant to a special warranty deed dated August 22, 1990 between their predecessors in interest, Coal Properties Corporation, Grantor and Fairview Land Company. Under this deed, WPP is owed an overriding royalty in the amount of $0.25 per ton for each ton of coal mined and sold by Williamson Energy, LLC from the mineral reserves subject to the deed. During the years ending December 31, 2013 and 2012, Williamson Energy, LLC paid $0.5 million and $1.0 million, respectively, in overriding royalties to WPP under this agreement.

In January 2009, NRP acquired additional coal reserves and infrastructure assets related to Macoupin for $143.5 million. Simultaneous with the closing, Macoupin Energy LLC entered into a lease transaction with NRP subsidiaries, WPP and HOD LLC for mining of the mineral reserves and for the rail facility. The mineral reserve mining lease is for a term of 20 years and can be extended for additional five-year terms limited to six such renewals. The lease requires a tonnage royalty equal to the greater of (i) 8% of the gross selling price of the coal plus $0.60 per ton or (ii) $5.40 per ton to be paid on the first 3.4 million tons of coal mined and sold in any given calendar year. Additionally, for the first 20-year term of the lease, Macoupin Energy LLC is required to pay a recoupable quarterly minimum deficiency payment equal to the difference between the tonnage royalty and $4.0 million. The lease also requires a wheelage fee of 0.5% of the gross selling price of any foreign coal transported across the property. During the years ended December 31, 2013 and 2012, Macoupin Energy LLC paid $15.5 million and $14.9 million, respectively, in royalties and other payments to WPP under this mineral lease.

The Macoupin rail load-out facility and rail loop facility leases are for terms of 29 years with 16 renewals for five years each. Each of these leases requires a payment of $1.50 per ton for every ton of coal loaded through the facility for the first 30 years up to 3.4 million tons along with annual rental payments of $10,000 per year after the expiration of the first 30 years. Macoupin Energy LLC is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order. During the years ended December 31, 2013 and 2012, Macoupin Energy LLC paid $3.0 million and $4.6 million, respectively, in payments to HOD LLC under the rail facility leases.

In September 2009, NRP through its subsidiary WPP signed a definitive agreement to acquire, in eight transactions, based on development milestones approximately 200 million tons of coal reserves for $255 million related to Hillsboro from Colt, an affiliate of Foresight Reserves. As part of this agreement, our subsidiary Hillsboro Energy LLC leases this coal from NRP. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The transactions closed for an aggregate amount of $255.0 million. Under the related lease, which has a term of 20 years and can be renewed for additional five year terms, with a maximum of six terms or until all merchantable and mineable coal has been mined and removed, we are required to pay tonnage royalty equal to the sum of (i) the greater of (a) 8% of the gross selling price per ton and (b) $4.00 per ton and (ii) a fixed royalty of $0.64 per ton. Quarterly minimum deficiency payments due under the lease are based off of a quarterly minimum deficiency amount of $7.5 million beginning in the first quarter of 2012 through 2031. If tonnage payments do not equal or exceed $7.5 million in each quarter, Hillsboro Energy LLC is required to pay the difference. The quarterly minimum deficiency amount for each year after 2031 is $125,000. We are a guarantor, on a declining basis, of the first $54.8 million of Hillsboro Energy LLC’s minimum quarterly

 

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payments to WPP. Hillsboro Energy LLC is required to pay a wheelage charge of 0.5% of the gross selling price of any foreign coal transported across the property. During the years ended December 31, 2013 and 2012, Hillsboro Energy LLC paid $32.4 million and $32.2 million, respectively, to WPP under this lease. As of December 31, 2013, we paid WPP $39.5 million in advance minimum payments that remain eligible for recoupment.

In December 2009, Williamson Energy, LLC amended its lease with WPP to add approximately 89.2 acres of coal reserves to the leased premises and to provide for a tonnage royalty of 10.2% of the gross selling price on each ton of coal mined from these additional reserves by the longwall mining method. Williamson Energy, LLC is not required to pay any royalty on such coal mined by any method other than longwall mining. Williamson Energy, LLC simultaneously amended its overriding royalty agreement with Independence to provide for an overriding royalty payment of $0.38 per ton on each ton of such coal mined by the longwall mining method. Williamson Energy, LLC is not required to pay any overriding royalty on such coal mined by any method other than longwall mining.

Subsequent amendments to the WPP lease and Independence overriding royalty agreement executed by Williamson Energy, LLC in August 2010 and March 2013, respectively, added additional acreages of reserves to the leased premises. Unlike the acreage added in 2009, Williamson Energy, LLC pays standard royalties and overriding royalties on coal mined from this acreage by any mining method. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Coal and Surface Leases and Overriding Royalties” for a description of royalties and overriding royalties paid by Williamson Energy, LLC under its agreements with WPP and Independence.

In March 2012, NRP subsidiary HOD LLC acquired a rail load-out facility at Sugar Camp for $50.0 million. The transaction includes a lease of the rail load-out to Sugar Camp Energy, LLC. The lease requires Sugar Camp Energy, LLC to maintain and operate the load-out. Additionally, Sugar Camp Energy, LLC is required to pay to HOD LLC a tonnage fee on certain tonnages of coal loaded through the load-out during the first 20 years of the lease. Sugar Camp Energy, LLC has no maximum or minimum throughput obligations under the lease, but is required to pay a recoupable quarterly deficiency payment in any quarter when tonnage payments do not reach a minimum of $1.3 million, Sugar Camp Energy, LLC must pay to HOD LLC the difference between the tonnage payments paid in that quarter and $1.3 million. We are a guarantor, on a declining basis, of the first $15 million of Sugar Camp’s minimum quarterly payments to HOD LLC. The term of the load out lease is 20 years. After the first 20 years, Sugar Camp Energy, LLC may elect to extend the lease for additional 5 year terms up to a maximum of 16 times. Sugar Camp Energy, LLC has the option to purchase the rail load-out for fair market value at any time after the expiration of the first 20 years and for the remainder of the lease. During the years ended December 31, 2013 and 2012, Sugar Camp Energy, LLC made $6.2 million and $4.1 million, respectively, in payments to HOD LLC under the load out lease.

As part of the 2013 Reorganization, Sugar Camp Energy, LLC and HOD LLC amended the lease of the rail load-out to permit Sugar Camp Energy, LLC to load coal from its second longwall mine through this same load-out. The terms of the amended lease for the second longwall are substantially consistent with the current lease and we expect that the costs under the amended lease will not exceed those costs under the current lease. The proceeds from amendment will be paid to Foresight Reserves. The term of the current load out lease for the second longwall mine is 20 years. After the first 20 years, Sugar Camp Energy, LLC may elect to extend the lease for additional 5 year terms up to a maximum of 16 times.

In addition, we have entered into various ancillary agreements with NRP and its subsidiaries providing for acquisition of additional mineral rights within the assigned reserves of Williamson and Macoupin, all in support of our mining transactions with NRP for leased reserves.

As a result of these transactions and contracts, as of December 31, 2013, we had $4.9 million of net outstanding payables to NRP or its affiliates, $9.1 million in accrued interest and $193.4 million in sales-

 

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leaseback obligations recorded to our consolidated balance sheet. As of December 31, 2012, we had $9.1 million of net outstanding payables to NRP or its affiliates, $7.0 million in accrued interest and $193.4 million in sales-leaseback obligations recorded to our consolidated balance sheet.

Colt LLC and Ruger Coal Company, LLC Leases

As part of the 2010 Reorganization, we entered into a series of mineral leases requiring minimum royalty payments and production royalty payments with Colt LLC and Ruger Coal Company, LLC, affiliates both owned by Foresight Reserves.

Williamson Energy, LLC leases coal reserves from Colt. The term of this lease is for ten years with six renewal periods of five years each. Williamson Energy, LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for this lease, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million per year. During the years ended December 31, 2013 and 2012, Williamson Energy, LLC paid $2.1 million and $3.0 million, respectively, in royalties to Colt under this coal lease. As of December 31, 2013, we paid Colt $3.1 million in advanced minimum royalty payments that remain eligible for recoupment.

Hillsboro Energy LLC leases coal reserves from Colt, an affiliated company under two leases, the terms of which are identical but that each cover different reserves. The term of each of these leases is for five years with seven renewal periods of five years each. Hillsboro Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The minimum royalty for each of these leases, which is recoupable only against actual production royalty from future tons during the period of 10 years following the date on which any such minimum royalty, is $4.0 million. During the years ended December 31, 2012 and December 31, 2013, Hillsboro Energy LLC paid $8.0 million each year in royalties to Colt under this coal lease. As of December 31, 2013, Hillsboro Energy LLC paid Colt $19.6 million in advanced minimum royalty payments that remain eligible for recoupment.

Sugar Camp Energy, LLC leases coal reserves from Ruger. The term of this lease is for ten years with six renewal periods of five years each. Sugar Camp Energy, LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. There is no minimum royalty associated with this lease.

Sugar Camp Energy, LLC has two overriding royalty agreements with Ruger pursuant to which Sugar Camp Energy, LLC is given the right to mine certain reserves controlled by Ruger as lessee. Pursuant to these overriding royalty agreements, the total royalty that Sugar Camp Energy, LLC will be required to pay for each ton of coal mined is equal to the difference between (i) the actual production royalty paid by Sugar Camp Energy, LLC to the lessor of the reserves under the leases assumed by Sugar Camp Energy, LLC from Ruger and (ii) the amount which is equal to 8% of the gross selling price of the coal mined under the leases. In addition to the overriding royalty, the remaining future minimum royalty for each of these agreements, which is recoupable only against actual overriding royalty during the period of ten years following the date on which such overriding royalty was paid, is $1.0 million.

During the years ended December 31, 2013 and 2012, Sugar Camp Energy, LLC paid $7.4 million and $8.2 million, respectively, in royalties to Ruger under these coal lease and overriding royalty agreements described above. As of December 31, 2013, Sugar Camp Energy, LLC paid Ruger $2.0 million in advanced minimum royalty payments under the overriding royalty agreements that remain eligible for recoupment.

Macoupin Energy LLC leases coal reserves from Colt under two leases, the terms of which are identical but that cover different reserves. The term of these leases is for ten years with six renewal periods of five years each. Macoupin Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The remaining future minimum royalties for each of these leases, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is $2.0 million.

 

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Effective June 1, 2012 Macoupin Energy LLC leased additional coal reserves from Colt under another lease. The term of this lease is ten years with six renewal periods of five years each. Macoupin Energy LLC is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. The remaining future minimum royalties for this lease, which is recoupable only against actual production royalty from future tons mined during the period of 10 years following the date on which any such minimum royalty is paid, is as follows:

 

For calendar year 2013		$	500,000
For calendar year 2014 and thereafter		$	2,000,000

During the years ended December 31, 2013 and 2012, Macoupin Energy LLC paid $6.0 million and $4.7 million, respectively, in royalties to Colt under these coal leases. As of December 31, 2013, Macoupin Energy LLC paid Colt $13.0 million under these leases in advanced minimum payments that remain eligible for recoupment.

As of December 31, 2013 and 2012, the mines had $0.2 million and $0.3 million, respectively, in aggregate outstanding payables to Colt and Ruger under all of the leases above.

Mitigation Agreements

New River Royalty, LLC (formerly Williamson Development Company LLC), an affiliate owned by Foresight Reserves, entered into mitigation agreements with each of Hillsboro Energy LLC, Macoupin Energy LLC, Sugar Camp Energy, LLC and Williamson Energy, LLC on August 12, 2010 (“Mitigation Agreements”). The Mitigation Agreements are contracts providing for the mitigation by each of the coal mining companies of subsidence damage to any structures located on certain surface lands owned by New River Royalty, LLC. Under these agreements, the mining companies are obligated to either repair any significant damage to structures on New River Royalty, LLC’s surface lands caused by mine subsidence or compensate New River Royalty, LLC for the diminution in value of the structure caused by the subsidence damage, in satisfaction of their obligation under the Illinois Surface Coal Mining and Conservation and Reclamation Act, 225 ILCS 720/1.01 et. seq. As an alternative, under the Mitigation Agreements, the mining companies can elect to pay New River Royalty, LLC the appraised value of any structures expected to be impacted by subsidence activities prior to mining in exchange for a waiver of liability for any obligation to repair or compensate New River Royalty, LLC for any damage after subsidence occurs. Appraised values and diminution in value are determined by licensed appraisers.

Coal and Surface Leases and Overriding Royalties

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Coal and Surface Leases and Overriding Royalties” for a description of certain arrangements with affiliates.

Coal Transloading

In August 2011, an affiliated company owned by Foresight Reserves acquired the IC RailMarine Terminal in Convent, Louisiana. This terminal, commonly referred to as the Convent Marine Terminal, is owned by Raven Energy LLC. The ownership of Raven Energy LLC was distributed by Foresight Reserves to certain owners of Foresight Reserves. As a result, Christopher Cline and Cline Group management own 100% of Raven Energy LLC. The transportation agreement between Foresight Energy LLC and its subsidiaries and Raven Energy LLC is described in “Business—Transportation.”

Equipment Repair and Rebuild Agreement dated August 1, 2013 between Seneca Rebuild LLC and Foresight Energy Services LLC

On August 1, 2013, Foresight Energy Services LLC entered into an equipment repair and rebuild agreement with Seneca Rebuild LLC, an affiliate owned by Chris Cline. The agreement calls for Seneca Rebuild to be the

 

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primary provider of repair and rebuild services for mining machinery and equipment for our mines, subject to certain exceptions as set forth in the agreement. The initial term of the agreement is five years, ending in July 2018. The agreement requires Seneca Rebuild to provide a price quote for the performance of the work set forth in any repair or rebuild work order requested by one of the mines. The agreement permits the mines to obtain quotes from third parties for performance of the same work at any time before a written work order is executed with Seneca Rebuild and provides Seneca Rebuild an opportunity to match any lower quotes obtained by the mine. Through December 31, 2013, the mines have not utilized the services of Seneca Rebuild LLC.

Amendment to a certain Supply Agreement dated May 1, 2013 by and among Foresight Supply Company LLC, Buyer and certain suppliers (including an entity that is a joint venture in which Seneca Industries, Inc., a Foresight affiliate owns 50%).

In May 2013, Foresight Supply Company LLC entered into an amendment to an existing supply agreement with unaffiliated supplier parties that added a joint venture in which one of our affiliates owns 50%, as a supplier party to the agreement and amended certain terms of the agreement. The original supply agreement was executed as of November 1, 2011 between Foresight Supply Company LLC as buyer and certain supplier parties. On May 1, 2013, one of those suppliers and Seneca Industries, Inc., one of our affiliates, formed a jointly owned limited liability company whose primary purpose is the manufacture and sale of certain mine supplies primarily for use by us in the conduct of our mining operations. The existing supply agreement was amended as of May 1, 2013 to add such joint venture as a supplier party, extend term of the agreement and update the pricing provisions of the agreement. The agreement, as amended, is a requirements contract under which our coal mines are obligated to purchase at least 90% of their aggregate annual requirements for certain mine supplies from the supplier parties, subject to certain exceptions as set forth in the agreement. The initial term of the agreement is five years, ending in April 2018. The mine supplies covered under this arrangement are sold pursuant to a price schedule incorporated into the agreement that is reviewed and, if necessary, adjusted every six months during the term based on specified cost drivers for the supplies to result in an agreed upon fixed profit percentage for the joint venture as set forth in the agreement. We and our affiliates have purchased $9.0 million in mining supplies from the joint venture from the inception of the joint venture in May 2013 through December 31, 2013.

Other Related Party Transactions

In October 2006, we entered into surface leases with Williamson Development Company LLC, a Foresight Reserves affiliate, in relation to the coal preparation plant and rail load out facility at Williamson. New River Royalty, LLC, an affiliate of Foresight Reserves and the successor to Williamson Development Company, LLC through merger, currently holds the leases. The primary terms of the leases expire on October 15, 2021, but may be extended by New River Royalty, LLC for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson Energy, LLC is required to pay rent to New River Royalty, LLC in the amount of $100,000 per year under the leases ($50,000 under each lease). Additionally, New River Royalty, LLC, may require Williamson Energy, LLC to purchase any portion of either of the leased properties at any time while the leases are in effect for $3,000 an acre. Williamson Transport, LLC, an NRP affiliate, has the option to purchase any property optioned under the leases if Williamson Energy, LLC does not perform its purchase obligation within fifteen days of receiving notice of its purchase obligation.

We arrange air travel on an individual flight basis with affiliated entities controlled by the Cline Group. These expenses are incurred hourly (at estimated cost) by flight and are initially paid by the Cline Group. We then reimburse the Cline Group for the travel expenses incurred by us and our subsidiaries. We also utilize other assets controlled by the Cline Group from time to time and reimburse the Cline Group on a time-incurred basis. For the years ended December 31, 2013 and 2012, we reimbursed entities controlled by the Cline Group $1.5 million and $0, respectively, for usage of non-Foresight Energy LLC assets.

Several affiliates by common ownership which own or lease property on which we conduct mining have obtained subsidence rights either from the surface owner or lessor. Normally, these rights permit us to subside

 

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the surface owner’s property in exchange for subsidence mitigation. The extent of the mitigation is normally determined at the time we undermine the surface and the cost is normally not material to our operations. Because those subsidence rights were previously held by affiliates by common ownership, we have entered into global assignments of such rights in exchange for our obligation to satisfy all subsidence mitigation.

An agreement was reached between Sugar Camp, LLC and Foresight Reserves under which Foresight Reserves has the right to amend Sugar Camp’s existing lease with HOD LLC for the Sugar Camp Rail Loadout to add coal produced from the second longwall at Sugar Camp. Pursuant to such amendment, the consideration paid by HOD LLC for including coal to the effect and operation of such lease will be paid directly to Foresight Reserves.

Savatran and Hillsboro will, in connection with the 2013 Reorganization, distribute to New River Royalty, LLC up to 2,500 acres of surface land not needed for current or currently projected future operations. The estimated land value to be transferred shall not exceed $7.0 million based on land values published in the 2012 Farmland Values and Lease Trends published by the Illinois Society of Professional Farm Managers and Rural Appraisers and land values as determined by Savatran and Hillsboro based on their recent experience in surface land transactions.

In addition, in June 2013 and August 2013, Foresight Energy LLC approved and paid a cash distribution of $10.0 million and $375.0 million, respectively, to its members.

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

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons and a written code of business conduct and ethics. We expect that, under our code of business conduct and ethics, a director will be required to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. In determining whether to approve or ratify a transaction with a related party, we expect that the board of directors of our general partner will take into account, among other factors it deems appropriate, (1) whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances, (2) the extent of the related person’s interest in the transaction and (3) whether the interested transaction is material to the Partnership.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. Such a conflict of interest may arise, for example, in connection with negotiating and approving the acquisition of any assets from Foresight Reserves. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement. We do not expect that our code of business conduct and ethics or any policies that the board of directors of our general partner will adopt will require the approval of any transactions with related persons, including Foresight Reserves, by our unitholders. Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the beneficial ownership of units following the consummation of this offering and the related transactions by:

 

•

each person who is known to us to beneficially own 5% or more of such units to be outstanding;

 

•

our general partner;

 

•

each of the directors and named executive officers of our general partner; and

 

•

all of the directors and executive officers of our general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

Our general partner is owned 99.33% and 0.67% by Foresight Reserves and Michael J. Beyer, respectively.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of , if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The percentage of units beneficially owned is based on a total of             common units and              subordinated units outstanding immediately following this offering.

 

Name of Beneficial Owner

Common Units Beneficially Owned

Percentage of Common Units Beneficially Owned

Subordinated Units Beneficially Owned

Percentage of Subordinated Units Beneficially Owned

Percentage of Common and Subordinated Units Beneficially Owned

Foresight Energy GP LLC

—

—

—

Foresight Reserves

Michael J. Beyer

All executive offers and directors as a group (     persons)

 

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DESCRIPTION OF INDEBTEDNESS

The following description of certain indebtedness we have does not purport to be complete and is qualified in its entirety by reference to the provisions of the various agreements related thereto.

Senior Secured Credit Facilities

General

Our Senior Secured Credit Facilities provide for a $450 million term loan facility and a $500 million revolving credit facility with maturities dates of August 2020 and August 2018, respectively, including a $125 million letter of credit sub-facility and a $25 million swingline loan sub-facility. In addition, we may request up to $100 million in incremental revolving credit or term loan facilities plus additional amounts so long as the senior secured leverage ratio does not exceed 2.25:1.00, subject to certain conditions and receipt of commitments by existing or additional financial institutions or institutional lenders. All borrowings under our Senior Secured Credit Facilities are subject to the satisfaction of usual and customary conditions, including the absence of a default and the accuracy of representations and warranties.

Interest and fees

Borrowings under our Revolving Credit Facility will bear interest at a rate equal to, at our option, (1) British Bankers’ Association (as published by Reuters) LIBOR plus an applicable margin ranging from 2.50% to 3.50% or (2) a base rate plus an applicable margin ranging from 1.50% to 2.50%, in each case, determined in accordance with our consolidated net leverage ratio. Borrowings under our Term Facility will bear interest of 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. We are also required to pay a commitment fee of 0.50% to the lenders under the Revolving Credit Facility in respect of unutilized commitments thereunder. In addition, we are required to pay a fronting fee equal to 0.125% per annum of the amount available to be drawn under letters of credit.

Prepayments and commitment reductions

With respect to the Revolving Credit Facility, voluntary prepayments and commitment reductions will be permitted, in whole or in part, in minimum amounts without premium or penalty, other than customary breakage costs with respect to LIBOR loans. Our Term Facility requires payments each year in an amount equal to 1.0% of the original principal amount per annum in equal quarterly installments, with the remaining amounts payable at maturity. Mandatory tem loan prepayments are required to be made under our Term Facility based on our annual excess cash flow, sales of assets, extraordinary payment receipts and certain incurrence of indebtedness, subject, in each case, to customary exceptions and thresholds. Voluntary prepayments made under the Term Facility or the repricing thereof within the first six months of the effectiveness of the Senior Secured Credit Facilities are subject to a prepayment premium of 1.0% of the loans being prepaid or repriced.

Collateral and guarantors

Our obligations under the Senior Secured Credit Facilities will be unconditionally guaranteed by and our direct and indirect domestic subsidiaries (excluding immaterial subsidiaries or subsidiaries designated as unrestricted subsidiaries) and will be secured by first priority perfected liens on substantially all of our existing and future assets subject to certain exceptions, including all material personal, real or mixed property, a pledge of the capital stock of Foresight Energy Finance Corporation, the capital stock of our domestic subsidiaries and up to 65.0% of the voting capital stock of our future foreign subsidiaries that are directly owned by us or any of the guarantors. In addition, upon the consummation of the Qualified MLP IPO (as defined herein), the MLP shall guarantee the obligations under the Senior Secured Credit Facilities on an unsecured basis within 45 days of such consummation.

 

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Restrictive covenants and other matters

Our Revolving Credit Facility will require that we comply on a quarterly basis with certain financial covenants, including a minimum consolidated interest coverage ratio of 2.00:1.00 and a maximum senior secured net leverage ratio ranging from 3.50:1.00 for the fiscal quarter ending December 31, 2013 to 2.75:1.00 for the fiscal quarter ending December 31, 2014 and thereafter. Our consolidated interest coverage ratio is equal to the ratio of our consolidated EBITDA to our consolidated cash interest expense for borrowed money, in each case for the preceding four fiscal quarters. Our senior secured leverage ratio is equal to the ratio of our 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 unrestricted cash, cash equivalents and short term marketable debt securities to our consolidated EBITDA for the preceding four fiscal quarters.

In addition, our Senior Secured Credit Facilities will include negative covenants, subject to significant exceptions, restricting or limiting our ability and the ability of our subsidiaries to, among other things:

 

•

Create liens on assets;

 

•

Incur additional indebtedness;

 

•

Make investments, loans, guarantees or advances;

 

•

Engage in mergers and consolidations;

 

•

Make dispositions;

 

•

Pay dividends and distributions or repurchase capital stock;

 

•

Change the nature of our business;

 

•

Engage in certain transactions with affiliates;

 

•

Enter into agreements that restrict dividends among us and our subsidiaries;

 

•

Amend organization documents and certain material agreements;

 

•

Change our accounting policies or fiscal year;

 

•

Repay certain indebtedness;

 

•

Enter into agreements that restricts the pledge of property; and

 

•

Enter into certain swap contracts.

Our Senior Secured Credit Facilities contain certain usual and customary representations and warranties, affirmative covenants and events of default. If an event of default occurs, the lenders under our Senior Secured Credit Facilities are entitled to take various actions, including the acceleration of amounts due under our Senior Secured Credit Facilities and all actions permitted to be taken by a secured creditor.

Restricted Payments Covenant

In particular, our ability to make certain restricted payments including dividends under our Senior Secured Credit Facilities is tied to, among other things, and subject to specified exceptions, our pro forma compliance with the consolidated interest coverage ratio covenant described above. If we are in pro forma compliance with such financial covenant, our Senior Secured Credit Facilities would permit us to pay restricted payments in an amount equal to 50% of our cumulative consolidated net income since July 1, 2013. However, even if we are not in pro forma compliance with our consolidated interest coverage ratio covenant, we may still make certain restricted payments, including, without limitation, up to an amount equal to 100% of net cash proceeds received by or contributed to Foresight Energy LLC from certain qualified equity offerings and an additional 6% per annum (renewing annually) based on net cash proceeds received by or contributed to Foresight Energy LLC.

 

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Furthermore, on or after the consummation of a Qualified MLP IPO (which this offering qualifies as), we would be able to make restricted payments based on the amount of available cash on hand instead of the cumulative consolidated net income build-up basket.

Senior Notes

General

On August 23, 2013, Foresight Energy LLC and Foresight Energy Finance Corporation (the “Issuers”) issued $600 million aggregate principal amount of senior notes with a maturity date of August 15, 2021 (the “2021 Senior Notes”) pursuant to an indenture (the “Indenture”). The 2021 Senior Notes bear interest at a rate of 7.875% per annum based upon a 360-day year of twelve 30-day months, payable semi-annually on February 15th and August 15th, beginning February 15th, 2014, to the holders of record on February 1st and August 1st, respectively. Foresight Energy Finance Corporation is a wholly-owned subsidiary of Foresight Energy LLC solely to serve as the co-issuer of the 2021 Senior Notes and has no material assets or operations of its own.

Optional Redemption

Prior to August 15, 2016, the Issuers may redeem the 2021 Senior Notes in whole or in part at a price equal to 100% of the aggregate principal amount thereof plus a “make-whole” premium. In addition, prior to August 15, 2016, the Issuers may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes at a price equal to 107.875% of the aggregate principal thereof with the proceeds of a qualified equity offering, subject to at least 65% of the aggregate principal amount of the 2021 Senior Notes remaining outstanding after giving effect to any such redemption.

On or after August 15, 2016, the Issuers may redeem the 2021 Senior Notes at a price equal to 105.906% of the aggregate principal amount of the 2021 Senior Notes redeemed prior to August 15, 2017, 103.938% of the aggregate principal amount of the 2021 Senior Notes redeemed on or after August 15, 2017 and prior to August 15, 2018, 101.969% of the aggregate principal amount of the 2021 Senior Notes redeemed on or after August 15, 2018 and prior to August 15, 2019 and at 100.000% of the aggregate principal amount of the 2021 Senior Notes redeemed thereafter.

Repurchase at the Option of Holders

Upon the occurrence of a change of control (which, among other things, would include, following a Qualified MLP IPO, the acquisition of more than 35% of the voting stock of Foresight Energy GP LLC by a person other than a person controlled by any of the Qualifying Owners) or the receipt by the Issuers of asset sale proceeds in excess of $50.0 million which are not thereafter reinvested within 360 days (or in the event that a binding commitment to consummate such reinvestment is made within 360 days, 540 days), the Issuers are obligated to offer to repurchase the 2021 Senior Notes at a price equal to 101% of the aggregate principal amount thereof, in the case of a change of control triggering event, or 100% of the aggregate principal amount thereof, in the case of an asset sale.

While in connection with the closing of this offering, Foresight Reserves will contribute all of its membership interests in Foresight Energy LLC to Foresight Energy LP, a change of control will not occur under the 2021 Senior Notes since the Indenture specifically carves out a Qualified MLP IPO from the definition of change of control.

Guarantors

The Issuers’ obligations under the 2021 Senior Notes are unconditionally guaranteed on a senior unsecured basis by each of the guarantors (other than Foresight Energy Finance Corporation) under the Senior Secured Credit Facilities.

 

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Restrictive covenants and other matters

The 2021 Senior Notes include negative covenants, subject to significant exceptions, restricting or limiting the Issuers’ ability and the ability of the Issuers’ subsidiaries to, among other things:

 

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Create liens on assets;

 

•

Incur additional indebtedness;

 

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Make investments, loans, guarantees or advances;

 

•

Engage in mergers and consolidations;

 

•

Make asset sales;

 

•

Pay dividends and distributions or repurchase capital stock or certain indebtedness;

 

•

Change the nature of their business;

 

•

Engage in certain transactions with affiliates; and

 

•

Enter into agreements that restrict dividends among the Issuers and their subsidiaries.

The 2021 Senior Notes contain certain usual and customary events of default. If an event of default occurs, the holders of the 2021 Senior Notes are entitled to take various actions, including the acceleration of amounts due under the 2021 Senior Notes.

In addition, at any time that the 2021 Senior Notes have investment grade ratings (Baa3 and BBB-), certain of the negative covenants listed above will be suspended. Such covenants will be reinstated in the event that the ratings of the 2021 Senior Notes decline below investment grade.

Restricted Payments Covenant

Following a Qualified MLP IPO (which this offering qualifies as), the Indenture prohibits us from making distributions to unitholders if any default or event of default (as defined in the Indenture) exists. In addition, the Indenture limits our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the Indenture). 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 on a cumulative basis have reached $50.0 million plus certain other amounts referred to as “incremental funds” under the Indenture.

Sugar Camp Financing Arrangement

General

On January 5, 2010, Sugar Camp Energy, LLC, as the borrower, and Foresight Energy LLC, as a guarantor, entered into a credit agreement with financial institutions Calyon Deutschland Niederlassung Einer Französischen Société Anonyme and Credit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent (the “Sugar Camp Credit Agreement”) to provide financing for longwall mining equipment. In addition, the Sugar Camp Credit Agreement also provided for the financing of loan fees and eligible interest during the construction of the longwall equipment. This financing is secured by the assets purchased with the proceeds from the Sugar Camp Credit Agreement. At December 31, 2013, $72.8 million was outstanding under the Sugar Camp Credit Agreement.

 

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Payments and Interest

Interest accrues on the Sugar Camp Credit Agreement at a fixed rate per annum of 5.78% and is due semi-annually on the last day of June and December until maturity. Principal is to be repaid in 17 equal semi-annual payments commencing on June 30, 2012 through June 30, 2020.

Restrictive covenants and other matters

The Sugar Camp Credit Agreement includes financial and negative covenants, subject to exceptions, restricting or limiting Sugar Camp Energy, LLC’s ability to, among other things:

 

•

Create liens on assets;

 

•

Incur additional indebtedness;

 

•

Make investments, loans, guarantees or advances;

 

•

Engage in mergers and consolidations;

 

•

Change the nature of our business;

 

•

Engage in certain transactions with affiliates;

 

•

Create subsidiaries or enter into joint ventures; and

 

•

Amend organization documents and certain material agreements.

The Sugar Camp Credit Agreement contains certain usual and customary representations and warranties, affirmative covenants and events of default. In connection with this offering, Sugar Camp intends to enter into an amendment to the Sugar Camp Credit Agreement. If an event of default occurs, the lenders under the Sugar Camp Credit Agreement are entitled to take various actions, including the acceleration of amounts due under the Sugar Camp Credit Agreement and all actions permitted to be taken by a secured creditor.

Guaranty by Foresight Energy LLC

Our guaranty of the Sugar Camp Credit Agreement requires that we comply on a quarterly basis with financial covenants, including the following: (i) a minimum consolidated interest coverage ratio of 2.00:1.00; and (ii) a maximum senior secured leverage ratio of 3.50:1.00 for the fiscal quarter ending December 31, 2013 and March 31, 2014, 3.25: 1.00 for the fiscal quarter ending June 30, 2014, 3.00:1.00 for the fiscal quarter ending September 30, 2014 and 2.75:1:00 for the fiscal quarter ending December 31, 2014 and each fiscal quarter thereafter.

Hillsboro Financing Arrangement

General

On May 14, 2010, Hillsboro Energy LLC, as the borrower, and Foresight Energy LLC, as a guarantor, entered into a credit agreement with Credit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent (the “Hillsboro Credit Agreement” and, together with the Sugar Camp Credit Agreement, the “Longwall Financing Arrangements”) to provide financing for longwall mining equipment and related parts and accessories. In addition, the Hillsboro Credit Agreement also provided for the financing of loan fees and eligible interest during the construction of the longwall equipment. The financing is secured by the assets purchased with the proceeds from the Hillsboro Credit Agreement. At December 31, 2013, $72.2 million was outstanding under the Hillsboro Credit Agreement.

Payments and Interest

Interest accrues on the Hillsboro Credit Agreement at a fixed rate per annum of 5.555% and is due on June 15, 2012 and each last day of March and September until maturity, unless considered as eligible interest. Principal is to be repaid in 17 equal semi-annual payments commencing on September 30, 2012.

 

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Restrictive covenants and other matters

The Hillsboro Credit Agreement includes financial and negative covenants, subject to exceptions, restricting or limiting Hillsboro Energy LLC’s ability to, among other things:

 

•

Create liens on assets;

 

•

Incur additional indebtedness;

 

•

Make investments, loans, guarantees or advances;

 

•

Engage in mergers and consolidations;

 

•

Change the nature of our business;

 

•

Engage in certain transactions with affiliates;

 

•

Create subsidiaries or enter into joint ventures; and

 

•

Amend organization documents and certain material agreements.

The Hillsboro Credit Agreement contains certain usual and customary representations and warranties, affirmative covenants and events of default. In connection with this offering, Hillsboro intends to enter into an amendment to the Hillsboro Credit Agreement. If an event of default occurs, the lenders under the Hillsboro Credit Agreement are entitled to take various actions, including the acceleration of amounts due under the Hillsboro Credit Agreement and all actions permitted to be taken by a secured creditor.

Guaranty by Foresight Energy LLC

Our guaranty of the Hillsboro Camp Credit Agreement requires that we comply on a quarterly basis with certain financial covenants, including the following: (i) a minimum consolidated interest coverage ratio of 2.00:1.00; and (ii) a maximum senior secured leverage ratio of 3.50:1.00 for each fiscal quarter ending December 31, 2013 and March 31, 2014, 3.25: 1.00 for the fiscal quarter ending June 30, 2014, 3.00:1.00 for the fiscal quarter ending September 30, 2014 and 2.75:1:00 for the fiscal quarter ending December 31, 2014 and each fiscal quarter thereafter.

Capital Lease Obligations—Longwall Equipment

On March 30, 2012, we entered into an interim longwall finance agreement with a financial institution to fund the manufacturing of longwall equipment (the “Longwall Shield Facility”). Upon us taking possession of the longwall equipment during the third quarter of 2012, the interim longwall finance agreement was converted into six individual lease agreements with maturities of four and five years beginning on September 1, 2012. These leases are considered capital lease obligations because of bargain purchase options at the end of each lease. The capital lease obligations bear interest ranging from 5.40% to 6.30% and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2013, $43.2 million was outstanding under the capital lease obligations.

Interim Longwall Financing Arrangement

In November 2013, we entered into an interim funding arrangement and a master lease agreement with PNC Equipment Finance, LLC under which they will finance the installment payments required under a contract with a vendor for the purchase of a set of longwall shields and related parts and equipment. The financing arrangement is up to the expected purchase price of $63.2 million and bears interest at the one-month LIBOR plus 3.95%. The interim funding arrangement is secured by the longwall shields and related parts and equipment. Upon the delivery of the longwall shields on or before April 1, 2014, a master lease agreement is in place such that the interim funding arrangement will convert to a five-year lease that we anticipate will be accounted for as a capital lease obligation. As of December 31, 2013, $31.6 million was outstanding under this arrangement.

 

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DESCRIPTION OF COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interest in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “How We Make Distributions To Our Partners.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

American Stock Transfer & Trust Company, LLC will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by unitholders:

 

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

•

special charges for services requested by a holder of a common unit; and

 

•

other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 

•

represents that the transferee has the capacity, power and authority to enter into our partnership agreement;

 

•

automatically becomes bound by the terms and conditions of our partnership agreement; and

 

•

makes the consents, acknowledgements and waivers contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records from time to time (or shall cause the transfer agent to do so, as applicable).

 

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

•

with regard to distributions of cash available for distribution, please read “How We Make Distributions To Our Partners”;

 

•

with regard to the duties of, and standard of care applicable to, our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

 

•

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

 

•

with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized in January 2012 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of mining and transporting coal, our general partner may decline to do so in its sole discretion. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

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.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities, as well as to our general partner in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Distributions To Our Partners.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

 

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Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require:

 

•

during the subordination period, the approval of a majority of the common units, excluding those common units whose vote is controlled by our general partner or its affiliates, and a majority of the subordinated units, voting as separate classes; and

 

•

after the subordination period, the approval of a majority of the common units.

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

 

Issuance of additional units No approval right.		Amendment of the partnership agreement Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”
Dissolution of our partnership		Unit majority. Please read “—Dissolution.”
Continuation of our business upon dissolution		Unit majority. Please read “—Dissolution.”
Withdrawal of our general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to                     , 2024 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”
Removal of our general partner		Not less than 66 2⁄3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. 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. Please read “—Withdrawal or Removal of Our General Partner.”
Transfer of our general partner interest		No approval right. Please read “—Transfer of General Partner Interest.”
Transfer of incentive distribution rights		No approval right. Please read “—Transfer of Subordinated Units and Incentive Distribution Rights.”
Transfer of ownership interests in our general partner		No approval right. Please read “—Transfer of Ownership Interests in the General Partner.”

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights

 

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does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

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brought in a derivative manner on our behalf;

 

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asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

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asserting a claim arising pursuant to any provision of the Delaware Act; or

 

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asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware, (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

 

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to remove or replace our general partner;

 

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to approve some amendments to our partnership agreement; or

 

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to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining

 

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the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in one state and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units, subordinated units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. Our common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

 

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Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

 

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enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

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enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, Foresight Reserves and Michael J. Beyer will own approximately     % and     %, respectively, of our outstanding common units and 100% of our subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

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a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

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a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed);

 

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

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an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

 

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•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

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an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

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any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, or other entity, as otherwise permitted by our partnership agreement;

 

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a change in our fiscal year or taxable year and related changes;

 

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conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

 

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do not adversely affect the limited partners, considered as a whole, or any particular class of limited partners in any material respect;

 

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

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are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

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are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any

 

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of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

 

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the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

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the entry of a decree of judicial dissolution of our partnership; or

 

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

 

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Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

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the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

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neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Distributions To Our Partners—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to                     , 2024 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after                     , 2024, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 ²⁄₃% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33 ¹⁄₃% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, Foresight Reserves and a member of management will own                      and                     , respectively, of our outstanding limited partner units, including all of our subordinated units.

 

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Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

 

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all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis; and

 

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if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest and the incentive distribution rights of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and all its and its affiliates’ incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in the General Partner

At any time, Foresight Reserves and any successive owners of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited

 

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partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

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represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

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automatically becomes bound by the terms and conditions of our partnership agreement; and

 

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gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Foresight Energy GP as our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of:

 

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the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

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the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be

 

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lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Non-Taxpaying Holders; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our future subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend our partnership agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners (or their owners, to the extent relevant), has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by our subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

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obtain proof of the federal income tax status of our limited partners (and their owners, to the extent relevant); and

 

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permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of such person’s federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

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Obtain proof of the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant); and

 

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Permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by our general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which

 

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a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights, shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

 

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Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

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our general partner;

 

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any departing general partner;

 

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any person who is or was an affiliate of our general partner or any departing general partner;

 

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any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

 

•

any person who is or was serving as a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or our subsidiaries;

 

•

any person who controls our general partner or any departing general partner; and

 

•

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. 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 general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

 

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We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

 

•

a current list of the name and last known address of each record holder; and

 

•

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In addition, in connection with this offering, we expect to enter into a registration rights agreement with Foresight Reserves. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to Foresight Reserves and the common units issuable upon the conversion of the subordinated units upon request of 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. In addition, the registration rights agreement gives Foresight Reserves piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Foresight Reserves and, in certain circumstances, to third parties. Please read “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, Foresight Reserves will hold an aggregate of             common units and             subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

•

1% of the total number of the securities outstanding; or

 

•

the average weekly reported trading volume of our common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

Under our partnership agreement and the registration rights agreement that we expect to enter into, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement and the registration rights agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. 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. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

Prior to the completion of this offering, we expect to adopt a new long-term incentive plan (the “Long-Term Incentive Plan”). If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the Long-Term Incentive Plan. This registration statement on Form S-8 is

 

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expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the Long-Term Incentive Plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

Lock-up Agreements

Foresight Reserves, Michael J. Beyer, our general partner and certain officers and directors of Foresight Reserves and our general partner have or will have signed lock-up agreements under which they agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Barclays Capital Inc., Citigroup Global Markets Inc., and Morgan Stanley & Co. LLC, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units, with certain exceptions. Please read “Underwriting” for a description of these lock-up provisions.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below. Unless the context otherwise requires, references in this section to “we” or “us” are references to the partnership and its subsidiaries on and after the closing of this offering.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis in its units.

 

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Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the mining, transportation and marketing of minerals and natural resources, such as coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and each of our limited liability company subsidiaries will be disregarded as an entity separate from us for federal income tax purposes. The representations made by us and by our general partner upon which Vinson & Elkins L.L.P. has relied in rendering its opinion include, without limitation:

(a) Neither we nor any of our operating subsidiaries has elected to be treated as a corporation for federal income tax purposes; and

(b) For each taxable year, more than 90% of our gross income will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

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 interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

 

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Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2016, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of taxable income to cash distributions to the common unitholders will increase. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

•

the earnings from operations exceeds the amount required to make minimum quarterly distributions on all common units, yet we only distribute the minimum quarterly distributions on all units; or

 

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or

 

•

legislation is passed that would limit or repeal certain federal income tax preferences currently available with respect to coal exploration and development (please read “—Tax Treatment of Operations—Recent Legislative Developments”).

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units plus the unitholder’s share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any

 

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increases in such unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions, the unitholder’s share of our losses, and any decreases in its share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “liabilities” will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss) generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation and depletion recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

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service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

•

interest on indebtedness allocable to property held for investment;

 

•

interest expense allocated against portfolio income; and

 

•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction

Our items of income, gain, loss and deduction generally will be allocated among our unitholders in accordance with their percentage interests in us. At any time that we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

 

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An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner’s relative contributions to us , (ii) the interests of all the partners in profits and losses , (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

 

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Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax bases of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the

 

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classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Coal Depletion

In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%.

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Percentage depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Upon the disposition of the mineral property, a portion of the gain, if any, equal to the lesser of the deductions for depletion which reduce the adjusted tax basis of the mineral property plus deductible development and mining exploration expenses, or the amount of gain recognized on the disposition, will be treated as ordinary income to us. In addition, a corporate unitholder’s allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner’s allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.

Mining Exploration and Development Expenditures

We will elect to currently deduct mining exploration expenditures that we pay or incur to determine the existence, location, extent or quality of coal deposits prior to the time the existence of coal in commercially marketable quantities has been disclosed.

Amounts we deduct for mine exploration expenditures must be recaptured and included in our taxable income at the time a mine reaches the production stage, unless we elect to reduce future depletion deductions by the amount of the recapture. A mine reaches the producing stage when the major part of the coal production is obtained from working mines other than those opened for the purpose of development or the principal activity of the mine is the production of developed coal rather than the development of additional coal for mining. This recapture is accomplished through the disallowance of both cost and percentage depletion deductions on the particular mine reaching the production stage. This disallowance of depletion deductions continues until the amount of adjusted exploration expenditures with respect to the mine have been fully recaptured. This recapture is not applied to the full amount of the previously deducted exploration expenditures. Instead, these expenditures are reduced by the amount of percentage depletion, if any, that was lost as a result of deducting these exploration expenditures.

Mine development costs incurred during the development phase are capitalized and revenue from the incidental sale of coal while a mine is in the development phase is recorded as a reduction of the related mine development costs.

 

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Mine exploration and development expenditures are subject to recapture as ordinary income to the extent of any gain upon a sale or other disposition of our property or of your common units. Please read “—Disposition of Units.” Corporate unitholders are subject to an additional rule that requires them to capitalize a portion of their otherwise deductible mine exploration and development expenditures. Corporate unitholders, other than some S corporations, are required to reduce their otherwise deductible exploration expenditures by 30%. These capitalized mine exploration and development expenditures must be amortized over a 60-month period, beginning in the month paid or incurred, using a straight-line method and may not be treated as part of the basis of the property for the purposes of computing depletion.

When computing the alternative minimum tax, mine exploration and development expenditures are capitalized and deducted over a ten year period. Unitholders may avoid this alternative minimum tax adjustment of their mine exploration and development expenditures by electing to capitalize all or part of the expenditures and deducting them over ten years for regular income tax purposes. You may select the specific amount of these expenditures for which you wish to make this election.

Sales of Coal Reserves

If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the mined coal sold are held by us:

 

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for sale to customers in the ordinary course of business (i.e. we are a “dealer” with respect to that property);

 

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for use in a trade or business within the meaning of Section 1231 of the Code; or

 

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as a capital asset within the meaning of Section 1221 of the Code.

In determining dealer status with respect to coal reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property for sale in question.

We intend to hold our coal reserves for use in a trade or business and achieving long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales of coal reserves. Thus, the general partner does not believe we will be viewed as a dealer. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a “dealer” in coal reserves.

If we are not a dealer with respect to our coal reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Internal Revenue Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.

A unitholder’s distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Internal Revenue Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated

 

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as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.

If we are not a dealer with respect to our coal reserves and that property is not used in a trade or business, the property will be a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code. Gain or loss recognized from the disposition of that property will be taxable as capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period of such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.

Upon a disposition of coal reserves, a portion of the gain, if any, equal to the lesser of (1) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses or (2) the amount of gain recognized on the disposition, will be treated as ordinary income to us.

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentage is currently 9% for qualified production activities income.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine its Section 199 deduction, each unitholder will aggregate its share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account its distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the basis rules, the at—risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

Recent Legislative Developments

The White House has recommended various legislative changes affecting the U.S. federal income tax preferences relating to coal exploration and development in President Obama’s Proposed Fiscal Year 2015 budget (the “Budget Proposal”). Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development discussed above. The Budget Proposal would (1) repeal the 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

 

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for 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 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.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash or the fair market value of other property it receives plus its share of our liabilities with respect to such units. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation or depletion recapture. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder’s tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

 

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a short sale;

 

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an offsetting notional principal contract; or

 

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a futures or forward contract with respect to the partnership interest or substantially identical property.

 

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Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the 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. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in

 

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the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to validity of such filing positions.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans and other tax-exempt organizations, as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or non-U.S. persons should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-U.S. unitholders are taxed by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends), and will be treated as engaged in business in the United States because of their ownership of our units. Furthermore, it is probable that they will be deemed to conduct such activities through a permanent establishment in the United States within the meaning of any applicable tax treaty. Consequently, they will be

 

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required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain to the extent reflected in earnings and profits, and as adjusted for changes in the foreign corporation’s “U.S. net equity.” That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” part or all of a non-U.S. unitholder’s gain from the sale or disposition of units may be treated as effectively connected with that unitholder’s indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

 

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The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us: (1) the name, address and taxpayer identification number of the beneficial owner and the nominee; (2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(c) a tax-exempt entity;

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy-related penalties will be assessed against us.

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be 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 those jurisdictions. We will initially own assets and conduct business in various states (including Illinois, Missouri, Indiana and through one of our affiliates in Louisiana), each of which imposes a personal income tax on individuals and an income tax on corporations and other entities. We may also own property or do business in

 

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other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. 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.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of its investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

 

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INVESTMENT IN FORESIGHT ENERGY LP BY EMPLOYEE BENEFIT PLANS

An investment in our common units by an employee benefit plan is subject to certain additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under certain other laws or regulations that are similar to such provisions and the Internal Revenue Code (“Similar Laws”). As used herein, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans, tax deferred annuities or IRAs established or maintained by an employer or employee organization and any entity the underlying assets of which are considered to include “plan assets” of an employee benefit plan pursuant to 29 C.F.R. Section 2510.3-101, as modified by Section 3(42) of ERISA.

General Fiduciary Matters

ERISA and the Internal Revenue Code impose certain duties on persons who are fiduciaries of an employee benefit plan that is subject to Title I of ERISA or Section 4975 of the Internal Revenue Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Internal Revenue Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan. In considering an investment in our common units, among other things, consideration should be given to:

 

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

•

whether making the investment will comply with the delegation of control and prohibited transaction provisions under Section 406 of ERISA, Section 4975 of the Internal Revenue Code and any other applicable Similar Laws (see the discussion under “—Prohibited Transaction Issues” below);

 

•

whether in making the investment, the employee benefit plan will be considered to hold, as plan assets, (1) only the investment in our common units or (2) an undivided interest in our underlying assets (see the discussion under “—Plan Asset Issues” below); and

 

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan should determine whether an investment in our common units is authorized by the appropriate governing instrument and is a proper investment for the plan or IRA.

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also certain IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions, referred to as prohibited transactions, involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan or IRA, unless an exemption is applicable. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA Plan that engaged in such a prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Internal Revenue Code.

 

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Plan Asset Issues

In addition to considering whether the purchase of our common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in our common units, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code and any other applicable Similar Laws.

The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Internal Revenue Code and applicable Similar Laws is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and Similar Laws in light of the penalties, excise taxes and liabilities that may be imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

Barclays Capital Inc., Citigroup Global Markets Inc. and Morgan Stanley & Co. LLC are acting as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name below:

 

Underwriter		Number of Common Units
Barclays Capital Inc.
Citigroup Global Markets Inc.
Morgan Stanley & Co. LLC
J.P. Morgan Securities LLC
Goldman, Sachs & Co.
Deutsche Bank Securities Inc.
Total

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the underwriters’ over-allotment option described below) if they purchase any of the common units. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may also be increased or the offering may be terminated.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $         per common unit. After the common units are released for sale to the public, if all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. The representatives have advised us that the underwriters do not intend to confirm sales to discretionary accounts that exceed     % of the total number of common units offered by them.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

We, Foresight Reserves and Michael J. Beyer, our general partner and certain officers and directors of Foresight Reserves and our general partner have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Barclays Capital Inc., Citigroup Global Markets Inc. and Morgan Stanley & Co. LLC, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units, with certain exceptions.

At our request, the underwriters have reserved up to     % of the common units for sale at the initial public offering price to persons who are directors, officers or employees of Foresight Reserves or our general partner, or who are otherwise associated with us through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed units purchased by participants in the program.

 

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Except for certain officers and directors of Foresight Reserves and our general partner who have entered into lock-up agreements as contemplated in the immediately preceding paragraphs, each person buying common units through the directed unit program has agreed that, for a period of 180 days from the date of this prospectus, he or she will not, without the prior written consent of Barclays Capital Inc., Citigroup Global Markets Inc. and Morgan Stanley & Co. LLC, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units with respect to common units purchased in the program, with certain exceptions. For certain officers and directors of Foresight Reserves and our general partner purchasing common units through the directed unit program, the lock-up agreements contemplated in the immediately preceding paragraphs shall govern with respect to their purchases. Barclays Capital Inc., Citigroup Global Markets Inc. and Morgan Stanley & Co. LLC, in their sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice. Barclays Capital Inc., Citigroup Global Markets Inc. and Morgan Stanley & Co. LLC do not have any present intention or any understandings, implicit or explicit, to release any of the common units or other securities subject to these lock-up agreements prior to the expiration of the 180-day restricted period described above. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered hereby. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed units, and for the failure of any participant to pay for its common units.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

We have applied to have our common units listed on the New York Stock Exchange under the symbol “FELP.”

The following table shows the underwriting discounts and commissions that we will pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.

 

		No Exercise				Full Exercise
Per common unit		$				$
Total		$				$

We have agreed to reimburse the underwriters for certain out-of-pocket expenses of the underwriters payable by us, in an aggregate amount not to exceed $            .

We will pay              an aggregate structuring fee equal to     % of the gross proceeds of this offering for the evaluation, analysis and structuring of the partnership.

We estimate that the expenses of the offering, not including the underwriting discount and structuring fee, will be approximately $         million, all of which will be paid by us.

In connection with the offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters’ over-allotment option and stabilizing purchases. The underwriters also may impose penalty bids.

 

•

Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in the offering.

 

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•

“Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ over-allotment option.

 

•

“Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ over-allotment option.

 

•

Covering transactions involve purchases of common units either pursuant to the underwriters’ over-allotment option or in the open market after the distribution has been completed in order to cover short positions.

 

•

To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

 

•

To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the over-allotment option. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the underwriters’ over-allotment option.

 

•

Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

 

•

Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the underwriters, in covering short positions or making stabilizing purchases, repurchase common units originally sold by that syndicate member.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

A prospectus in electronic format may be available on the websites or through other online services maintained by one or more of the underwriters participating in this offering, or by their affiliates. The underwriters may agree to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s website and any information contained in any other website maintained by an underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Certain of the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking, investment banking and advisory services for us, Foresight Reserves or our respective affiliates from time to time in the ordinary course of their business for which they have received customary fees and reimbursement of expenses. Affiliates of certain of the underwriters are lenders under our Senior Secured Credit Facilities. Certain of the underwriters were also initial purchasers in connection with the offering of $600.0 million aggregate principal amount of 2021 Senior Notes. Other than the participation as lenders under our Senior Secured Credit Facilities or as described in this prospectus, none of the underwriters has provided or will provide financing, investment or advisory services to us during the 180-day period prior to or the 90-day period following the date of this prospectus.

 

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The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments. In addition, affiliates of certain of the underwriters purchase coal from us and our affiliates.

Because the Financial Industry Regulatory Authority, Inc., or FINRA, views the common units offered hereby as interests in a direct participation program, there is no conflict of interest between us and the underwriters under Rule 5121 of the FINRA Rules and the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

We, our general partner and Foresight Energy LLC have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

 

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

 

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

 

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Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a “recognised collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(1) if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the CIS Promotion Order) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

(2) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(3) in both cases (1) and (2) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).

Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Capital Investment Act (Vermögensanlagengesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in

 

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connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 2 no. 4 of the German Capital Investment Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

 

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LEGAL MATTERS

The validity of the common units being offered in this prospectus and other legal matters concerning this offering will be passed upon for us by Cahill Gordon & Reindel LLP, New York, New York. Certain tax and other legal matters will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. The underwriters will be represented by Shearman & Sterling LLP, New York, New York, and Baker Botts L.L.P., Houston, Texas.

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The balance sheets of Foresight Energy LP as of December 31, 2013 and December 31, 2012 appearing in this Prospectus and Registration Statement has been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The consolidated financial statements of Foresight Energy LLC and Subsidiaries at December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013 appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

EXPERTS—COAL RESERVES

Our coal reserve estimate is based on a study prepared by Weir International, Inc., a mining and geological consultant and has been included herein upon the authority of this firm as an expert.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the Securities and Exchange Commission a registration statement on Form S-1 under the Securities Act with respect to the common units we propose to sell in this offering. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement. For further information about us and the common units we propose to sell in this offering, we refer you to the registration statement and the exhibits and schedules filed as a part of the registration statement. Statements contained in this prospectus as to the contents of any contract or other document filed as an exhibit to the registration statement are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit to the registration statement. When we complete this offering, we will also be required to file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission.

You can read our Securities and Exchange Commission filings, including the registration statement, over the Internet at the Securities and Exchange Commission’s website at www.sec.gov. You may also read and copy any document we file with the Securities and Exchange Commission at its public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the Securities and Exchange Commission at 100 F Street, N.E., Washington, D.C. 20549. Please call the Securities and Exchange Commission at 1-800-SEC-0330 for further information on the operation of the public reference room.

 

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MARKET AND INDUSTRY DATA AND FORECASTS

In this prospectus, we rely on and refer to information regarding the coal industry, future coal production and consumption and future electricity generation in the United States and internationally from the EIA, Wood Mackenzie, BP Statistical Review, World Coal Institute, Ventyx, S&P Capital IQ, National Mining Association and Bloomberg L.P., none of whom are affiliated with us. Wood Mackenzie has consented to being named in this prospectus.

When we make statements in this prospectus about our position in our industry or any sector of our industry or about our market share, we are making statements of our belief. This belief is based on data from various sources (including government data industry publications, surveys and forecasts), on estimates and assumptions that we have made based on that data and other sources and our knowledge of the markets for our products.

We do not have any knowledge that the market and industry data and forecasts provided to us from third party sources are inaccurate in any material respect. However, we have been advised that certain information provided to us from third party sources is derived from estimates or subjective judgments, and while such third party sources have assured us that they have taken reasonable care in the compilation of such information and believe it to be accurate and correct, data compilation is subject to limited audit and validation procedures. We believe that, notwithstanding such qualification by such third party sources, the market and industry data provided in this prospectus is accurate in all material respects.

Our estimates, in particular as they relate to market share and our general expectations, involve risks and uncertainties and are subject to change based on various factors, including those discussed under the section entitled “Risk Factors.”

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus 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. You can identify these forward-looking statements by the use of forward-looking words such as “outlook”, “intends”, “plans,” “estimates,” “believes,” “expects,” “potential,” “continues,” “may,” “will,” “should,” “seeks,” “approximately,” “predicts,” “anticipates,” “foresees,” or the negative version of these words or other comparable words and phrases. Any forward-looking statements contained in this prospectus speak only as of the date on which we make it and are based upon our historical performance and on current plans, estimates and expectations. Our future results and financial condition may differ materially from those we currently anticipate as a result of the various factors. Among those factors that could cause actual results to differ materially are:

 

•

Availability of cash flow to pay minimum quarterly distribution on our common units;

 

•

Access to the necessary capital to fund the capital expenditures required to reach full productive capacity at our mines;

 

•

Adverse or abnormal geologic conditions, which may be unforeseen;

 

•

Our ability to develop our existing coal reserves and meet any expected development timeline;

 

•

Our ability to produce coal at existing and planned operations;

 

•

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

 

•

Our ability to meet certain provisions in our existing coal supply agreements, enter into new coal supply agreements or extend existing agreements;

 

•

Future legislation and changes in regulations or governmental policies or changes in enforcement or interpretations thereof;

 

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•

The outcome of pending or future litigation;

 

•

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

 

•

Competition from other fuels, which may affect the economic competitiveness of coal;

 

•

Defects in title or loss of any leasehold interests in our properties;

 

•

Changes in coal prices or the costs of mining or transporting coal;

 

•

Change in consumption patterns by utilities;

 

•

Competition both within the coal industry and outside of it;

 

•

The inherent risk of coal mining operations;

 

•

Labor availability, relations and other workforce factors;

 

•

Failure of contractor-operated sources to fulfill the terms of our contracts;

 

•

The impact of worldwide economic and political conditions;

 

•

Volatility in the capital and credit markets;

 

•

Customer deferrals of contracted shipments;

 

•

Difficulty in obtaining equipment, parts and raw materials;

 

•

Major equipment failures;

 

•

Availability, reliability and costs of transportation;

 

•

Delays in moving our longwall equipment;

 

•

Transportation interruptions such as floodings or derailments;

 

•

Uncertainties in estimating economically recoverable coal reserves;

 

•

Customer performance and credit risks;

 

•

The impact of wars and acts of terrorism;

 

•

Costs related to government regulation;

 

•

Environmental regulations and impact on customers’ demand for coal;

 

•

Material liabilities from hazardous substances and environmental contamination;

 

•

The unavailability of insurance to cover certain uninsurable environmental risks;

 

•

The contract prices we receive for coal;

 

•

Market demand for domestic and foreign coal, electricity and steel;

 

•

The consummation of financing, acquisition or disposition transactions and the effect thereof on our business;

 

•

The impact of our IPO Reorganization;

 

•

Our plans and objectives for future operations and the acquisition or development of additional coal reserves or other acquisition opportunities;

 

•

Our relationships with, and other conditions affecting, our customers;

 

•

Timing of reductions or increases in customer coal inventories;

 

•

Long-term coal sales arrangements;

 

•

The number of coal-fired plants built in the future versus expectations;

 

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•

Weather conditions or catastrophic weather-related damage;

 

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Earthquakes and other natural disasters;

 

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Changes in energy policy;

 

•

The availability and cost of competing energy resources;

 

•

Our ability to obtain services that have otherwise been provided by Foresight Reserves and Foresight Management;

 

•

Our existing or future indebtedness;

 

•

Changes in postretirement benefit and pension obligations;

 

•

Our assumptions concerning our reclamation and mine closure obligations;

 

•

Our liquidity, results of operations and financial condition; and

 

•

Other factors, including those discussed in “Risk Factors.”

Before you invest in our common units, you should be aware that the occurrence of the events described above and elsewhere in this prospectus could have a material adverse effect on our business, results of operations and financial position. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

 

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Table of Contents

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

		Page
Foresight Energy LP (formerly Foresight Energy Partners LP):
Report of Independent Registered Public Accounting Firm			F-2
Balance Sheets as of December 31, 2013 and 2012			F-3
Note to the Balance Sheets			F-4
Foresight Energy LLC and Subsidiaries:
Audited Consolidated Financial Statements as of and for the Years Ended December 31, 2013, 2012 and 2011:
Report of Independent Registered Public Accounting Firm			F-5
Consolidated Balance Sheets as of December 31, 2013 and 2012			F-6
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011			F-7
Consolidated Statements of Members’ Equity (Deficiency) for the Years Ended December  31, 2013, 2012 and 2011			F-8
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011			F-9
Notes to Consolidated Financial Statements			F-10

 

F-1

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Table of Contents

Report of Independent Registered Public Accounting Firm

The Partners

Foresight Energy LP (formerly Foresight Energy Partners LP)

We have audited the accompanying balance sheets of Foresight Energy LP (formerly Foresight Energy Partners LP) (the “Partnership”) as of December 31, 2013 and 2012. These balance sheets are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these balance sheets based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheets are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audits of the balance sheets provide a reasonable basis for our opinion.

In our opinion, the balance sheets referred to above present fairly, in all material respects, the financial position of Foresight Energy LP (formerly Foresight Energy Partners LP) at December 31, 2013 and 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

St. Louis, Missouri

March 28, 2014

 

F-2

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Table of Contents

FORESIGHT ENERGY LP (formerly Foresight Energy Partners LP)

BALANCE SHEETS

 

		December 31, 2013				December 31, 2012
		(In Thousands)
Assets		$	—			$	—
Liabilities		$	—			$	—
Partners’ equity:
Limited partner’s equity			1,000			$	1,000
General partner’s equity			—				0
Receivable from partners			(1,000	)			(1,000	)
Total partners’ equity			—			$	—
Total liabilities and partners’ equity		$	—			$	—

See accompanying note to balance sheets.

 

F-3

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Table of Contents

FORESIGHT ENERGY LP (FORMERLY FORESIGHT ENERGY PARTNERS LP)

NOTE TO BALANCE SHEETS

1. Description of Business and Basis of Presentation

Foresight Energy LP (formerly Foresight Energy Partners LP), the “Partnership” is a Delaware limited partnership formed on January 26, 2012 to be the parent of Foresight Energy LLC (“Foresight Energy”), an entity engaged primarily in the mining and sale of coal. Subsequent to December 31, 2013, Foresight Energy Partners LP changed its name to Foresight Energy LP.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering. In connection with the closing of the public offering, Foresight Reserves, L.P. (“Foresight Reserves”), a Delaware limited liability partnership, and Michael J. Beyer will each contribute their membership interest in Foresight Energy to the Partnership. The Partnership will then issue common units and subordinated units to Foresight Reserves and Michael J. Beyer in exchange for its ownership in Foresight Energy and will offer common units to the public by way of a public offering. Foresight Energy GP LLC (the “General Partner”), an entity owned by Foresight Reserves and Michael J. Beyer, will maintain its non-economic general partner interest in the Partnership. In addition, the Partnership will issue to the General Partner incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50%, of the distributions the Partnership makes above the highest target level.

Foresight Reserves has committed to contribute $1,000 to the Partnership. This contribution receivable is reflected as a reduction to partners’ equity.

 

F-4

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Table of Contents

Report of Independent Registered Public Accounting Firm

The Members

Foresight Energy LLC

We have audited the accompanying consolidated balance sheets of Foresight Energy LLC and Subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, members’ equity (deficiency), and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Foresight Energy LLC and Subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

St. Louis, Missouri

March 28, 2014

 

F-5

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Table of Contents

Foresight Energy LLC and Subsidiaries

Consolidated Balance Sheets

 

		December 31,				December 31,
		2013				2012
		(In Thousands)
Assets
Current assets:
Cash and cash equivalents		$	23,284			$	27,888
Accounts receivable			58,987				68,540
Due from affiliates			368				1,357
Inventories			71,290				91,610
Prepaid expenses			3,028				1,940
Prepaid royalties			6,330				13,034
Deferred longwall costs			14,265				10,072
Other current assets			8,544				4,309
Total current assets			186,096				218,750
Property, plant, equipment and development, net			1,414,074				1,401,285
Prepaid royalties			73,242				47,509
Other assets			36,759				27,744
Total assets		$	1,710,171			$	1,695,288
Liabilities and members’ (deficit) equity
Current liabilities:
Current portion of long-term debt and capital lease obligations		$	70,034			$	33,471
Accrued interest			27,645				30,340
Accounts payable			50,155				48,527
Accrued expenses and other current liabilities			37,515				24,834
Due to affiliates			9,572				11,751
Distribution payable			—				25,000
Total current liabilities			194,921				173,923
Long-term debt and capital lease obligations			1,449,179				1,028,478
Sale-leaseback financing arrangements			193,434				193,434
Asset retirement obligations			20,416				19,350
Other long-term liabilities			337				—
Total liabilities			1,858,287				1,415,185
Members’ (deficit) equity:
Controlling interests			(157,356	)			281,353
Noncontrolling interests			9,240				(1,250	)
Total members’ (deficit) equity			(148,116	)			280,103
Total liabilities and members’ (deficit) equity		$	1,710,171			$	1,695,288

See accompanying notes.

 

F-6

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Table of Contents

Foresight Energy LLC and Subsidiaries

Consolidated Statements of Operations

 

		Year Ended December 31,
		2013				2012				2011
		(In Thousands)
Coal sales		$	957,412			$	845,886			$	500,791
Costs and expenses:
Cost of coal sales (excluding depreciation, depletion and amortization)			363,024				309,801				174,183
Transportation			197,839				171,679				98,394
Depreciation, depletion and amortization			161,216				124,552				70,411
Accretion on asset retirement obligations			1,527				1,368				1,705
Selling, general and administrative			32,291				41,528				38,894
Gain on commodity contracts			(2,392	)			(534	)			(2,395	)
Other operating income, net			(280	)			(10,759	)			(791	)
Operating income			204,187				208,251				120,390
Other expenses:
Loss on early extinguishment of debt			77,773				—				—
Interest expense, net			115,897				82,580				38,193
Net income			10,517				125,671				82,197
Less: net income (loss) attributable to noncontrolling interests			2,236				(160	)			104
Net income attributable to controlling interests		$	8,281			$	125,831			$	82,093

 

See accompanying notes.

 

F-7

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Table of Contents

Foresight Energy LLC and Subsidiaries

Consolidated Statements of Members’ (Deficit) Equity

 

		Controlling				Noncontrolling
		Interests				Interests				Total
		(In Thousands)
Members’ equity (deficit) at January 1, 2011		$	283,031			$	(965	)		$	282,066
Cash contributed by members			30,000				—				30,000
Net income			82,093				104				82,197
Distributions			—				(58	)			(58	)
Members’ equity (deficit) at December 31, 2011			395,124				(919	)			394,205
Net income (loss)			125,831				(160	)			125,671
Non-cash member contribution			4,632				—				4,632
Distributions			(244,234	)			(171	)			(244,405	)
Members’ equity (deficit) at December 31, 2012			281,353				(1,250	)			280,103
Net income			8,281				2,236				10,517
Consolidation of variable interest entities			—				10,120				10,120
Distributions			(446,990	)			(1,866	)			(448,856	)
Members’ (deficit) equity at December 31, 2013		$	(157,356	)		$	9,240			$	(148,116	)

See accompanying notes.

 

F-8

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Table of Contents

Foresight Energy LLC and Subsidiaries

Consolidated Statements of Cash Flows

 

		Year Ended December 31,
		2013				2012				2011
		(In Thousands)
Cash flows from operating activities
Net income		$	10,517			$	125,671			$	82,197
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			161,216				124,552				70,411
Amortization of debt issuance costs and debt premium/discount			7,574				8,235				6,056
Deferred revenue recognized			(3,907	)			—				—
Non-cash debt extinguishment expense			5,625				—				—
Non-cash equity award			—				4,632				—
Write-off of deferred issuance costs			—				4,276				—
Other			1,950				1,124				942
Changes in operating assets and liabilities:
Accounts receivable			9,533				(36,463	)			(7,653	)
Amount due from/to affiliates, net			(1,190	)			(7,593	)			9,930
Inventories			12,095				(19,397	)			(33,059	)
Prepaid expenses and other current assets			(7,765	)			3,808				(7,999	)
Prepaid royalties			(17,064	)			(29,646	)			(20,322	)
Accounts payable			1,449				2,057				5,864
Accrued interest			(2,695	)			12,149				(6,154	)
Accrued expenses and other current liabilities			5,379				17,233				5,246
Other			(3,191	)			(947	)			(2,316	)
Net cash provided by operating activities			179,526				209,691				103,143
Cash flows from investing activities
Investment in property, plant, equipment and development			(210,726	)			(209,937	)			(336,020	)
Proceeds from sale of equipment			465				2,898				3,199
Settlement of derivative instruments			986				—				—
Net cash used in investing activities			(209,275	)			(207,039	)			(332,821	)
Cash flows from financing activities
Net increase (decrease) in borrowings under revolving credit facility			23,000				(88,000	)			228,723
Proceeds from other long-term debt			1,072,772				264,007				—
Payments on other long-term debt and capital lease obligations			(634,863	)			(19,663	)			(102	)
Payments on short-term debt			—				(6,627	)			—
Proceeds from sale-leaseback financing arrangement			—				49,950				—
Distributions paid			(411,891	)			(219,405	)			(58	)
Member contributions			—				—				30,000
Debt issuance costs			(23,729	)			(3,708	)			—
Deferred IPO issuance costs paid			(144	)			(3,079	)			—
Proceeds from loans from affiliates			—				—				10,575
Payments on loans from affiliates			—				—				(21,150	)
Net cash provided by (used in) financing activities			25,145				(26,525	)			247,988
Net (decrease) increase in cash and cash equivalents			(4,604	)			(23,873	)			18,310
Cash and cash equivalents, beginning of period			27,888				51,761				33,451
Cash and cash equivalents, end of period		$	23,284			$	27,888			$	51,761

See accompanying notes.

 

F-9

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Table of Contents

Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

1. Description of Business and Basis of Presentation

Foresight Energy LLC (“Foresight Energy”), a perpetual-term Delaware limited liability company, was formed on September 5, 2006, for the purpose of holding an ownership interest in various affiliated entities under common control. Over 99% of Foresight Energy is owned by Foresight Reserves, LP (“Foresight Reserves”), and the remaining interest is held by an executive of Foresight Energy. Foresight Energy’s principal operation is the development, mining, transportation and sale of coal mined in the Illinois Basin. Foresight Energy operates four underground mining complexes: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Hillsboro Energy, LLC (“Hillsboro”); and Macoupin Energy, LLC (“Macoupin”). The first Sugar Camp and Hillsboro mines emerged from development when longwall production began on March 1, 2012 and September 1, 2012, respectively. Mined coal is sold to a diverse customer base, including electric utility and industrial companies in the Eastern United States, as well as overseas markets. The consolidated financial statements include the accounts of Foresight Energy, its subsidiaries and variable interest entities (“VIEs”) for which Foresight Energy or its subsidiaries are the primary beneficiary (collectively, the “Company”). The Company operates in a single reportable segment. Intercompany transactions, including those between consolidated VIEs and Foresight Energy and its consolidated subsidiaries, are eliminated in consolidation.

2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and loss during the reporting period. Actual results could differ from those estimates.

Revenue Recognition

Once mines are in production, coal sales include sales to customers of coal produced and, from time to time, the re-sale of coal purchased from third parties. The Company recognizes sales at the time legal title and risk of loss pass to the customer at contracted amounts. For domestic coal sales, this generally occurs when coal is loaded onto rail cars at the mine or onto barges at terminals. For export coal sales, this generally occurs when coal is loaded onto an ocean vessel. Quality and weight adjustments are recorded as necessary based on contract specifications as a reduction or increase to coal sales and accounts receivable.

Transportation Expenses

Costs related to the handling and transporting of coal inventory to the point of sale are included in coal inventory in the consolidated balance sheets. Upon the recognition of the sale, these costs are included in transportation expenses in the consolidated statements of operations.

Cash and Cash Equivalents

The Company considers cash deposits with original maturities of less than three months to be cash and cash equivalents. Cash and cash equivalents are stated at cost, which approximates fair value.

Allowance for Doubtful Accounts

The Company evaluates the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age

 

F-10

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Table of Contents

Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

2. Summary of Significant Accounting Policies (continued)

 

of the receivables and disputed amounts. Historically, credit losses have been insignificant. At December 31, 2013 and 2012, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

Inventories

Inventories are valued at the lower of average cost or market. Parts and supplies inventory consists of spare parts for equipment and supplies used in the mining process. Raw coal represents coal stockpiles that require processing through a preparation plant prior to shipment to a customer. Clean coal represents coal stockpiles that will be sold in its current condition. Coal inventory costs include labor, equipment costs, supplies, transportation costs incurred prior to the transfer of title to customers, depreciation, depletion, amortization and direct mine operating overhead.

Deferred Longwall Costs

The Company defers the direct costs associated with longwall moves, including longwall set-up costs, supplies and refurbishment costs of longwall equipment. These deferred costs are expensed on a units-of-production basis into cost of coal sales (excluding depreciation, amortization and depreciation) over the panel benefited by these costs, which has historically approximated one year.

Prepaid Royalties

Prepaid royalties consist of recoupable minimum royalty payments due under various lease agreements entered into by the Company. Prepaid royalties expected to be recouped within one year are classified as current assets in the Company’s consolidated balance sheets. The Company continually evaluates its ability to recoup prepaid royalty balances, which includes, among other factors, assessing mine production plans, sales commitments, future coal market conditions and remaining years available for recoupment. The contractual recoupment periods on the prepaid royalty balances generally range from five to ten years from the date the minimum royalty was paid.

Property, Plant, Equipment and Development, Net

Property, plant and equipment are recorded at cost. Costs which extend the useful lives or increase the productivity of the assets are capitalized, while normal repairs and maintenance that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Asset retirement obligations (AROs) for the various assets have been recorded as components of the specific assets. Interest costs applicable to major additions are capitalized during the construction period. Interest costs capitalized into property, plant, equipment and development, net for the years ended December 31, 2013, 2012, and 2011, were $3.6 million, $19.0 million, and $36.7 million, respectively. Property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Machinery and equipment under capital lease agreements are amortized on the straight-line method over the shorter of the useful life of the asset or the related lease term. The cost of acquiring land (subsidence) rights and mineral rights is amortized under the units-of-production over the mineral reserves benefited by the costs. The estimated useful lives of machinery and equipment, buildings and structures and other categories are as follows:

 

Machinery and equipment			3–20 years
Buildings and structures			3–40 years
Other			3–20 years

 

F-11

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Table of Contents

Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

2. Summary of Significant Accounting Policies (continued)

 

Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the mineral reserves benefited by the development. Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred. During the development phase, the Company establishes access to the mineral reserves and makes other preparations for commercial production. Development costs principally include clearing land, building roads, sinking shafts, driving slopes and developing ventilation and transportation passageways at the mines. Development costs also include the build out of the Company’s transportation infrastructure. Costs incurred during the development phase are capitalized and proceeds from the incidental sale of coal during development are recorded as a reduction of the related mine development costs. For reporting in the statements of cash flows, cash expended in the investment in mining rights, equipment and development during the development phase is reported net of capitalized coal sales. Mines in development included the first longwall at Sugar Camp through March 1, 2012 and the first longwall at Hillsboro through September 1, 2012. The second longwall at Sugar Camp has been under development since 2012 and longwall production is expected to begin in the second quarter of 2014.

Impairment of Long-Lived Assets

The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded during the years ended December 31, 2013, 2012 or 2011.

Debt Issuance Costs

The Company capitalizes costs incurred in connection with the issuance of debt and the establishment of credit facilities and capital leasing arrangements. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the effective interest method. Amortization expense of $7.7 million, $8.1 million and $5.4 million is included in interest expense for the years ended December 31, 2013, 2012, and 2011, respectively. As of December 31, 2013 and 2012, unamortized debt issuance costs of $33.6 million and $26.7 million, respectively, are included in other assets on the consolidated balance sheets.

Sale Leaseback Financing Arrangements

The Company is party to two arrangements in which it sold assets to an affiliate and immediately leased those assets back from the affiliates. Because the Company had continued involvement in the assets sold, the proceeds received on the sale of the assets were recorded as long-term financing liabilities in our consolidated balance sheets. Under both of these arrangements, the Company pays a fixed minimum payment, as well as contingent payments for volumes in excess of the contractual minimum payment. Interest is accrued on the outstanding principal amounts of the financing arrangements using an implied interest rate, which was initially determined at inception of the lease and is adjusted for changes in expected amounts and timing of future payments based on the mine plans. Payments are first applied against accrued interest and any excess is applied against the outstanding principal. The Company accounts for such changes by adjusting in the current period, the life-to-date interest previously recorded on the sale-leaseback to reflect the new effective interest rate as if it was applied from the inception of the transaction (i.e., retroactively applied). If there is a material change to the mine plans, the impact of a change in the effective interest rate to the consolidated statements of operations could be significant.

 

F-12

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Table of Contents

Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

2. Summary of Significant Accounting Policies (continued)

 

Asset Retirement Obligations

The Company’s asset retirement obligations (“ARO”) consist primarily of spending estimates related to reclaiming surface land, refuse areas, slurry ponds and support facilities at the Company’s underground mines in accordance with federal and state reclamation laws as required by each mining permit. These obligations are typically incurred at the time development of a mine commences for underground mines or when construction begins for support facilities, refuse areas and slurry ponds. The Company estimates its ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and a market risk premium and then discounted at a credit-adjusted, risk-free rate. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value and the capitalized cost is amortized over the useful life of the related asset on a units-of-production basis. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate.

Derivative Financial Instruments

The Company utilizes derivative financial instruments to manage exposures to coal prices. The Company may also hold certain coal derivative instruments for trading purposes. The Company records the fair value of each instrument as either an asset or liability in the consolidated balance sheets and the change in fair value of each instrument is recorded in the consolidated statements of operations.

Coal contracts provide for the physical purchase or sale of coal in quantities expected to be used or sold by the Company over a reasonable period in the normal course of business, and are not recognized on the consolidated balance sheets.

Fair Value

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs. A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value.

The hierarchy, as defined below, gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs.

 

•

Level 1 is defined as observable inputs, such as quoted prices in active markets for identical assets.

 

•

Level 2 is defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

 

•

Level 3 is defined as unobservable inputs in which little or no market data exists, therefore, requiring an entity to develop its own assumptions.

The carrying value of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments.

 

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Table of Contents

Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

2. Summary of Significant Accounting Policies (continued)

 

Variable Interest Entities (VIEs)

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

To determine a VIE’s primary beneficiary, the Company performs a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE’s economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether the Company is the primary beneficiary of a VIE, the Company performs a qualitative analysis that considers the design of the VIE, the nature of the Company’s involvement and the variable interests held by other parties. If that evaluation is inconclusive as to which party absorbs a majority of the entity’s expected losses or residual returns, a quantitative analysis would be performed to determine the primary beneficiary. The income attributable to consolidated variable interest entities is recorded as net income attributable to noncontrolling interests in the consolidated statements of operations.

Regulatory Matters

Federal, state, and, to a lesser extent, local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation of mining properties, the discharge of materials into the environment, surface subsidence, and the effects of mining on groundwater quality and availability. One of the primary regulatory matters affecting the Company’s mining operations pertains to the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSM). The Company obtains SMCRA permits and permit renewals for its mining operations from the Illinois Department of Natural Resources – Land Reclamation Division. The Company’s mine and reclamation plans incorporate the provisions of SMCRA, the state programs, and the complementary environmental programs that impact coal mining.

SMCRA stipulates compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (RCRA); and Comprehensive Environmental Response, Compensation, and Liability Acts (CERCLA). Besides OSM, other federal regulatory agencies involved in mining oversight activities include the Environmental Protection Agency (EPA) that regulates the Clean Water Act, RCRA, and CERCLA; the United States Army Corps of Engineers that regulates activities affecting navigable waters; and the United States Bureau of Alcohol, Tobacco, and Firearms that regulates the use of explosive blasting. The Illinois Department of Natural Resources (IDNR) and the Illinois EPA are authorized by OSM and EPA to regulate monitoring or carry out permitting specific aspects of mining operations that pertain to the applicable laws cited above. The Company endeavors to conduct its mining operations in compliance with all applicable federal, state, and local laws and regulations. Costs associated with regulatory compliance are accrued when incurred to the extent such costs can be reasonably estimated or otherwise determined.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

2. Summary of Significant Accounting Policies (continued)

 

Other Mining-Related Costs and Obligations

Significant components of mining costs include wages and related benefit costs which are paid to employees and the employees of the entities controlled by the Company. The Company’s current labor arrangements are not subject to United Mine Workers of America or other organized labor contracts or other voluntary programs with nonunion employees that frequently provide for long-term benefits, including defined benefit pensions and health care coverage for retired employees and future retirees and their dependents. The Company has obtained workers’ compensation coverage from an independent provider.

Income Taxes

Foresight Energy, its subsidiaries and controlled entities were established as limited liability companies (LLCs), thus for federal and, if applicable, state and local income tax purposes, are treated as pass-through entities. No provision for income taxes related to the operations of the Company has been included in the accompanying consolidated financial statements because, as LLCs, they are not subject to federal or state income taxes and the tax effect of its activities accrues to the unit holders. Net income for financial statement purposes may differ significantly from taxable income reportable to unit holders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the membership agreement. In the event of an examination of the tax return, the tax liability of the unit holders could be changed if an adjustment in the LLC’s income is ultimately sustained by the taxing authorities.

New Accounting Standards

There were no new authoritative accounting pronouncements that had a significant impact on the Company’s financial statements or impacted comparability with prior periods presented.

Supplemental Cash Flow Information

The following is supplemental information to the statements of cash flows for the years ended:

 

		December 31,
		2013				2012				2011
		(In Thousands)
Supplemental disclosure of cash flow information:
Cash interest paid, net of capitalization		$	111,043			$	65,127			$	38,423
Supplemental disclosures of noncash investing and financing activities:
Accrued member distribution		$	—			$	25,000			$	—
Noncash member distributions (see Note 3)		$	61,990			$	—			$	—
Financing of interest, debt issuance costs and equipment		$	—			$	14,829			$	73,367

3. Reorganization

Simultaneously with the closing of the debt refinancing on August 23, 2013 (see Note 7), the Company underwent a reorganization (the “2013 Reorganization”) pursuant to which it distributed 100% of its ownership interest in Sitran LLC (a wholly -owned subsidiary that conducts transloading operations on the Ohio River), Adena Resources LLC (a wholly -owned subsidiary that provides water and other miscellaneous rights to the

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

3. Reorganization

 

Company’s mines) and Hillsboro Energy’s loadout facility to its members. The Company recorded a non-cash distribution totaling $62.0 million in August 2013 to reflect these distributions to its members. Subsequent to the 2013 Reorganization, Adena Resources LLC and the Hillsboro Energy loadout continued to be consolidated as VIEs, which resulted in an increase in noncontrolling interest members’ equity of $10.1 million (see Note 13).

Additionally, up to 2,500 acres of land ancillary to the operations of the mines was approved for future distribution to the Company’s members and an agreement was reached between the Company, Foresight Reserves and HOD, LLC (“HOD”), a subsidiary of Natural Resources Partners, LP (“NRP”), which allows for Sugar Camp’s existing lease with HOD for the Sugar Camp loadout to be amended in the future to include coal produced from the second longwall at Sugar Camp on what is expected to be materially consistent terms as the original agreement discussed (see Note 8). Pursuant to such an amendment occurring, the consideration paid by HOD for adding the production from the second longwall at Sugar Camp to the lease will be paid directly to Foresight Reserves.

4. Accounts Receivable

Accounts receivable consists of the following:

 

		December 31, 2013				December 31, 2012
		(In Thousands)
Trade accounts receivable		$	54,084			$	66,363
Other receivables			4,903				2,177
		$	58,987			$	68,540

5. Inventories

Inventories consist of the following:

 

		December 31, 2013				December 31, 2012
		(In Thousands)
Parts and supplies inventory		$	30,155			$	25,486
Raw coal			4,250				2,305
Clean coal			36,885				63,819
		$	71,290			$	91,610

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

 

6. Property, Plant, Equipment and Development, Net

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

 

		December 31, 2013				December 31, 2012
		(In Thousands)
Land, land rights and mineral rights		$	114,058			$	109,715
Machinery and equipment			984,920				885,953
Machinery and equipment under capital leases			70,500				70,500
Buildings and structures			218,037				209,849
Development costs			619,117				561,244
Other			8,564				7,293
Property, plant, equipment and development			2,015,196				1,844,554
Less: accumulated depreciation, depletion and amortization			(601,122	)			(443,269	)
Property, plant, equipment and development, net		$	1,414,074			$	1,401,285

7. Long-Term Debt and Capital Lease Obligations

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

 

		December 31, 2013				December 31, 2012
		(In Thousands)
2017 Senior Notes		$	—			$	604,010
2021 Senior Notes			595,795				—
Term Loan			444,602				—
Revolving Credit Facility			259,000				236,000
Interim longwall financing arrangement			31,616				—
5.78% longwall financing arrangement			72,833				84,038
5.555% longwall financing arrangement			72,187				82,500
Capital lease obligations			43,180				55,401
Total long-term debt and capital lease obligations			1,519,213				1,061,949
Less: current portion			(70,034	)			(33,471	)
Long-term debt and capital lease obligations		$	1,449,179			$	1,028,478

On August 23, 2013, the Company executed a debt refinancing under which it increased the capacity on its revolving credit facility to $500.0 million and extended the term to August 2018 and issued a $450.0 million term loan due in 2020 with a 1% amortizing principal. The Company also issued $600.0 million of 7.875% Senior Notes due in 2021 and repurchased $600.0 million of outstanding 9.625% Senior Notes due in 2017 (the “2017 Senior Notes”) through a tender offer. The Company recorded a $77.8 million loss on the early extinguishment of debt for the $72.1 million in tender costs to redeem the 2017 Senior Notes and to write-off $5.7 million in unamortized debt issuance costs. The tender costs were recorded as an operating activity in the consolidated statement of cash flows. The net proceeds from the refinancing were used to fund the tender offer, to pay a $375.0 million member distribution and to pay transaction fees on the refinancing.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

7. Long-Term Debt and Capital Lease Obligations (continued)

 

Revolving Credit Facility

On August 23, 2013, Foresight Energy executed the second amendment to its credit agreement (the “Credit Agreement”) to increase the borrowing capacity under its senior secured revolving credit facility from $400.0 million to $500.0 million and extend the maturity date to August 23, 2018 (the “Revolving Credit Facility”). Borrowings under the Revolving Credit Facility bear interest at a rate equal to, at the Company’s option, (1) British Bankers’ Association (as published by Reuters) LIBOR plus an applicable margin ranging from 2.50% to 3.50% or (2) a base rate plus an applicable margin ranging from 1.50% to 2.50%, in each case, determined in accordance with the Company’s consolidated net leverage ratio. The weighted-average interest rate on borrowings under the Revolving Credit Facility as of December 31, 2013 and 2012 was 3.5% and 3.7%, respectively. The Company is also required to pay a 0.5% commitment fee to the lenders under the Revolving Credit Facility for unutilized commitments. At December 31, 2013, the Company had borrowings of $259.0 million outstanding under the Revolving Credit Facility and $2.5 million in outstanding letters of credit. There was $238.5 million of remaining capacity under the Revolving Credit Facility as of December 31, 2013.

The Revolving Credit Facility is subject to customary debt covenants, including a consolidated interest coverage ratio and a consolidated senior secured leverage ratio. The Company was in compliance with its debt covenants at December 31, 2013. The Credit Agreement and the 2021 Senior Notes discussed below carry limitations on restricted payments, which impact the timing and amount of distributions available to members. Borrowings under the Credit Agreement are guaranteed on a senior-secured basis by the domestic subsidiaries of the Company.

Term Loan

The Credit Agreement was also amended for the issuance of a $450.0 million senior secured term B loan (the “Term Loan”) on August 23, 2013. The Term Loan was issued at an original issuance discount of $4.5 million which will be amortized over the term of the loan. The Term Loan requires quarterly principal payments of approximately $1.1 million beginning on December 31, 2013. Mandatory term loan prepayments are required to be made based on annual excess cash flow, sale of assets, extraordinary payment receipts and certain incurrence of indebtedness, subject, in each case, to customary exceptions and thresholds. Voluntary prepayments made under the Term Loan or the repricing thereof within the first six months are subject to a prepayment premium of 1.0% of the loans being prepaid or repriced. The Term Loan matures on August 23, 2020, with all remaining unpaid principal due at that time. The Term Loan bears interest at LIBOR plus 4.5%, subject to a 1% LIBOR floor. As of December 31, 2013, the interest rate on the Term Loan was 5.5%.

2021 Senior Notes

On August 23, 2013, Foresight Energy issued $600.0 million of 7.875% senior notes due August 15, 2021 (the “2021 Senior Notes”). The proceeds from the issuance were used to redeem the 2017 Senior Notes. The 2021 Senior Notes are guaranteed on a senior unsecured basis by all of the domestic operating subsidiaries of Foresight Energy, other than Foresight Energy Finance Corporation, co-issuer of the notes. The interest on the 2021 Senior Notes is due semiannually on February 15 and August 15 of each year. The 2021 Senior Notes were issued at an initial discount of $4.3 million, which is being amortized using the effective interest method over the term of the notes.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

7. Long-Term Debt and Capital Lease Obligations (continued)

 

Prior to August 15, 2016, the Company may redeem some or all of the 2021 Senior Notes at a redemption price equal to the sum of the principal amount of the 2021 Senior Notes to be redeemed, plus accrued and unpaid interest, plus the applicable make whole premium. After August 15, 2016, the Company may redeem all or a part of the 2021 Senior Notes at the redemption prices (expressed as a percentage of principal) set forth below plus accrued and unpaid interest, if redeemed during the 12-month period commencing on August 15 of the years indicated below:

 

Year		Percentage
2016			105.91	%
2017			103.94	%
2018			101.97	%
2019 and thereafter			100.00	%

In addition, prior to August, 15 2016, the Company may redeem up to 35% of the 2021 Senior Notes with the proceeds from certain equity offerings at a redemption price of 107.875%, plus accrued and unpaid interest, if any, to the redemption date.

Longwall Financing Arrangements and Capital Lease Obligations

In May 2010, the Company entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement provided for financing of loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall mine equipment and guaranteed by Foresight Energy. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually in March and September until maturity. Principal is due in 17 equal semiannual payments through September 30, 2020. The outstanding balance as of December 31, 2013 was $72.2 million.

In January 2010, the Company entered into a credit agreement with a financial institution to provide financing for longwall equipment and related parts and accessories. The financing agreement also provided for financing of the loan fees and eligible interest during the construction of the longwall equipment. The financing arrangement is collateralized by the longwall mine equipment and guaranteed by Foresight Energy. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually in June and December until maturity. Principal is due in 17 equal semiannual payments through June 30, 2020. The outstanding balance as of December 31, 2013 was $72.8 million.

The guaranty agreements between the Company and the lender under both of the above longwall financing arrangements contain certain financial covenants that were amended effective August 23, 2013 to be identical to those of the Credit Agreement.

On March 2012, the Company entered into a finance agreement with a financial institution to fund the manufacturing of longwall equipment. Upon taking possession of the longwall equipment during the third quarter of 2012, this interim longwall finance agreement was converted into six individual leases with maturities of four and five years beginning on September 1, 2012 (collectively, the “Capital Lease Obligations”). These leases contain a bargin purchase option at the end of the lease term. The Capital Lease Obligations bear interest ranging from 5.4% to 6.3%, and principal and interest payments are due monthly over the terms of the leases. As of December 31, 2013, $43.2 million was outstanding under the capital lease obligations.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

7. Long-Term Debt and Capital Lease Obligations (continued)

 

In November 2013, the Company entered into an interim funding arrangement and a master lease agreement with a lender under which the lender will finance the installment payments required under a contract with a vendor for the purchase of a set of longwall shields and related parts and equipment. This interim longwall financing arrangement is up to the expected purchase price of $63.2 million and bears interest at the one-month LIBOR rate plus 3.95%. Upon the delivery of the longwall shields on or before April 1, 2014, this interim longwall financing arrangement is expected to be converted to a series of five-year leases that the Company anticipates will be accounted for as capital lease obligations. As of December 31, 2013, $31.6 million was outstanding under the interim longwall financing arrangement and the interest rate was 4.1%.

Maturity Table

The following summarizes the contractual maturities of long-term debt (excluding unamortized aggregate discounts of $8.5 million) and capital lease obligations as of December 31, 2013:

 

		Long-Term Debt				Capital Lease Obligations
		(In Thousands)
2014		$	57,634			$	12,400
2015			26,018				13,426
2016			26,018				11,893
2017			26,017				5,461
2018			285,017				—
Thereafter			1,063,807				—
		$	1,484,511			$	43,180

The above table represents defined contractual repayments and does not assume any early voluntary prepayment of principal or required prepayment pursuant to the excess cash flow provision or any other provisions of the Credit Agreement, which is subject to customary exceptions and thresholds.

The aggregate amount of minimum lease payments (which include principal and interest) for capital lease obligations is $47.4 million as of December 31, 2013. Minimum lease payments from 2014 through 2018 are as follows:

 

In Thousands		2014				2015				2016				2017				2018
Minimum lease payments		$	14,501			$	14,828			$	12,511			$	5,579			$	—

8. Sale-Leaseback Financing Arrangements

Macoupin Energy Sale-Leaseback Financing Arrangement

In January 2009, Macoupin entered into a sales agreement with WPP, LLC (“WPP”) and HOD (subsidiaries of NRP) to sell certain mineral reserves and rail facility assets (the “Macoupin Sales Arrangement”). Macoupin received $143.5 million in cash in exchange for certain mineral reserve and transportation assets. Simultaneous with the closing, Macoupin entered into a lease with WPP for mining of the mineral reserves (the “Mineral Reserves Lease”) and with HOD for the use of the rail loadout and rail loop (the “Macoupin Rail Loadout Lease” and the “Rail Loop Lease,” respectively). The Macoupin Mineral Reserves Lease is a 20-year noncancelable lease that contains renewal elections for six additional five-year terms. The Macoupin Rail Loadout Lease and

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

8. Sale-Leaseback Financing Arrangements (continued)

 

the Rail Loop Lease are 99-year noncancelable leases. Under the Macoupin Mineral Reserves Lease, Macoupin makes monthly payments equal to the greater of $5.40 per ton or 8.00% of the sales price, plus $0.60 per ton for each ton of coal sold from the leased mineral reserves, subject to a minimum royalty of $4.0 million per quarter through December 31, 2028. After the initial 20-year term, the annual minimum royalty is only $10,000 per year. The minimum royalty is recoupable on future tons mined. If during any quarter the tonnage royalty and tonnage fees paid under the Rail Loadout and Rail Loop Leases discussed below exceed $4 million, Macoupin may generally recoup any unrecouped quarterly payments made during the preceding 20 quarters on a first paid, first recouped basis. The Macoupin Rail Loadout Lease and Rail Loop Lease require an aggregate payment of $3.00 ($1.50 for the rail loop facility and $1.50 for the rail load-out facility) for each ton of coal loaded through the facility for the first 30 years, up to 3.4 million tons per year. After the initial 30-year term, Macoupin will only pay an annual rental payment of $20,000 per year for usage of the rail loadout and rail loop. The Macoupin Sales Arrangement, Mineral Reserves Lease, Macoupin Rail Loadout Lease and Rail Loop Lease are collectively accounted for as a financing arrangement (the “Macoupin Sale-Leaseback”) (see Note 2). This financing arrangement is recourse to Macoupin and not recourse to Foresight Energy or any of its other subsidiaries.

At December 31, 2013 and 2012, the amount outstanding under the Macoupin Sale-Leaseback was $143.5 million. The effective interest rate on the financing obligation was 14.2%, 14.2% and 14.1% for the years ended December 31, 2013, 2012 and 2011, respectively. Interest expense was $19.6 million, $20.6 million and $13.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. During the fourth quarter of 2011, changes to the Macoupin mine plan resulted in a reduction of the effective interest rate and therefore, interest expense of $10.7 million. The impact to interest expense from changes in the mine plan during 2012 and 2013 was immaterial.

Sugar Camp Energy Sale-Leaseback Financing Arrangement

In March 2012, Sugar Camp entered into a sales agreement with HOD for which it received a total of $50.0 million in cash in exchange for certain rail loadout assets (“Sugar Camp Sales Agreement”). Simultaneous with the closing, Sugar Camp entered into a lease transaction with HOD for the use of the rail loadout (the “Sugar Camp Rail Loadout Lease”). The Sugar Camp Rail Loadout Lease is a 20-year noncancelable lease that contains renewal elections for 16 additional five-year terms. Under the Sugar Camp Rail Loadout Lease, Sugar Camp will pay a monthly royalty of $1.10 per ton for every ton of coal mined from specified reserves and loaded through the rail loadout. The royalty is subject to adjustment based on the time it takes for Sugar Camp to complete each longwall move. The royalty payments are subject to a minimum payment amount of $1.3 million per quarter for the first twenty years the lease is in effect. After the initial 20-year term, Sugar Camp would only pay an annual rental payment of $10,000 per year. To the extent the minimum payment exceeds amounts owed based on actual coal loaded, the excess is recoupable within two years of payment.

The Sugar Camp Sales Agreement and Sugar Camp Rail Loadout Lease are collectively accounted for as a financing arrangement (the “Sugar Camp Sale-Leaseback) (See Note 2). This financing arrangement is recourse to Sugar Camp and Foresight Energy has a limited declining commercial guaranty which began at $15 million and decreases with each minimum payment made by Sugar Camp.At December 31, 2013 and 2012, the amount outstanding under the Sugar Camp Sale-Leaseback was $50.0 million. The effective interest rate on the financing, which is derived from the timing and tons of coal to be mined as set forth in the current mine plan and the related cash payments, was 14.3% and 13.8% at December 31, 2013 and 2012, respectively. Interest expense recorded on the Sugar Camp Sale-Leaseback was $7.2 million and $5.4 million for the years ended December 31, 2013 and 2012, respectively.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

8. Sale-Leaseback Financing Arrangements (continued)

 

An agreement was reached between the Company, Foresight Reserves and HOD which allows for the existing Sugar Camp Rail Loadout Lease to be amended in the future to include coal produced from the second longwall at Sugar Camp on what is expected to be materially consistent terms as the original agreement discussed. Pursuant to such an amendment occurring, the consideration paid by HOD for including coal produced by the second longwall at Sugar Camp will be paid directly to Foresight Reserves.

Maturity table

The following summarizes the maturities of principle payments, based on current mine plans, on the Company’s sale-leaseback financing arrangements, and accrued interest at December 31, 2013:

 

		Sale-Leaseback
		Financing				Accrued
		Arrangements				Interest
		(In Thousands)
2014		$	—			$	9,146
2015			—				—
2016			205				—
2017			1,062				—
2018			1,214				—
Thereafter			190,953				—
		$	193,434			$	9,146

The aggregate amounts of remaining minimum lease payments on the Company’s sale-leaseback financing arrangements are $331.3 million. Minimum payments from 2014 through 2018 are as follows:

 

In Thousands		2014				2015				2016				2017				2018
Minimum lease payments		$	21,000			$	21,000			$	21,000			$	21,000			$	21,000

9. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following:

 

		December 31, 2013				December 31, 2012
		(In Thousands)
Employee compensation, benefits and payroll taxes		$	17,137			$	5,078
Accrued taxes other than income			4,270				3,653
Royalties (non-affiliate)			2,999				1,228
Liquidated damages			7,448				5,863
Deferred revenue			—				3,907
Other			5,661				5,105
		$	37,515			$	24,834

Employee compensation, benefits and payroll taxes includes a $11.7 million liability recognized for a phantom equity award (the “Liability Award”) to an executive of the Company. This Liability Award fully vested in 2010 and was granted principally for services performed to develop the Company’s longwall mines. Prior to 2013, the Company had not recorded the liability (or corresponding mine development asset); however, the Company

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

9. Accrued Expenses and Other Current Liabilities (continued)

 

determined the amount was immaterial to its consolidated financial statements during all periods impacted. Approximately $2.5 million was recognized under this award as selling, general and administrative expenses for non-developmental activities performed by the executive during the vesting period and fair market value adjustments to the Liability Award in 2013. The remaining fair value of the Liability Award was recorded as a development asset. The Liability Award is adjusted to fair value each reporting period with the offset recorded to selling, general and administrative expenses.

10. Asset Retirement Obligations

Changes in the carrying amount of the Company’s asset retirement obligations were as follows:

 

		2013				2012				2011
		(In Thousands)
Balance, at January 1 (including current portion)		$	19,449			$	19,967			$	22,320
Accretion expense			1,527				1,552				1,705
Expenditures for reclamation activities			(376	)			(574	)			(753	)
Adjustments to the liability from changes in estimates			625				(1,496	)			(3,305	)
Balance, at December 31			21,225				19,449				19,967
Less: current portion of asset retirement obligations			(809	)			(99	)			(317	)
Noncurrent portion of asset retirement obligations		$	20,416			$	19,350			$	19,650

The credit-adjusted, risk-free interest rates used in determining the asset retirement obligations were 8.8%, 7.6% and 8.6% at December 31, 2013, 2012, and 2011, respectively.

11. Contractual Arrangements and Operating Leases

The Company leases certain surface rights, mineral reserves, mining, transportation and other equipment under various lease agreements with related entities under common ownership, NRP and its subsidiaries and other independent third parties in the normal course of business.

The mineral reserve leases can generally be renewed as long as the mineral reserves are being developed and mined until all economically recoverable reserves are depleted or until mining operations cease. The lease agreements typically require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price of the coal. Generally, the leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The minimum royalties are generally recoupable against production royalties over a contractually defined period of time (generally five to ten years). Some of these agreements also require overriding royalty and/or wheelage payments. Under the terms of certain mineral reserve leases, the Company is to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements and is responsible for the acquisition costs and the assets are to be titled to WPP. Transportation throughput agreements generally require a per ton fee amount for coal transported and contain certain escalation clauses and/or renegotiation clauses. For certain transportation assets, the Company is responsible for operations, repairs, and maintenance and for keeping transportation facilities in good working order. Surface rights, mining, and other equipment leases require monthly payments based upon the specified agreements. Certain of these leases provide options for the purchase of the property at various times during the life of the lease, generally at its then fair market value. The Company also leases certain office space, rail cars and equipment under leases with varying expiration dates.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

11. Contractual Arrangements and Operating Leases (continued)

 

The following presents future minimum payments, by year, required under contractual royalty and throughput arrangements with related entities and third parties as of December 31, 2013:

 

		Royalties –Third Party				Royalties –Related Party				Transportation Minimums – Third Party				Transportation Minimums – Related Party
		(In Thousands)
2014		$	2,004			$	55,667			$	27,775			$	40,480
2015			2,004				55,667				27,775				42,320
2016			2,004				55,667				27,775				44,160
2017			2,004				55,667				20,780				46,080
2018			2,004				55,667				20,780				48,160
Thereafter			13,193				368,668				65,060				157,760
Total		$	23,213			$	647,003			$	189,945			$	378,960

The following presents future lease minimum payments, by year, required under noncancelable operating leases with initial terms greater than one year as of December 31, 2013:

 

		Operating Leases – Third Party				Operating Leases – Related Party
		(In Thousands)
2014		$	4,631			$	105
2015			1,204				105
2016			1,141				105
2017			342				105
2018			—				105
Thereafter			—				300
Total minimum lease payments		$	7,318			$	825

Total rental expense from operating leases for the years ended December 31, 2013, 2012, and 2011 was approximately $17.0 million, $17.2 million, and $13.0 million, respectively. Included in rental expense is $9.9 million, $11.5 million, and $10.2 million for the years ended December 31, 2013, 2012 and 2011, respectively, of contingent rental payments to Williamson Transport, a subsidiary of NRP, for the rail load facility at Williamson Energy. The Company pays contingent rental fees, net of a fixed per ton amount for maintaining the facility, on each ton of coal passed through the rail load facility. The Company also paid an annual rental fee of $0.1 million to New River Royalty, LLC, a subsidiary of Foresight Reserves, in each of the prior three years under two land leases.

12. Related-Party Transactions

The controlling member of Foresight Reserves directly and indirectly beneficially owns an interest in the GP and LP interests of NRP. The Company routinely engages in transactions in the normal course of business with Foresight Reserves and its affiliates and NRP and its subsidiaries. These transactions include production royalties, transportation services, administrative and management service arrangements, coal material handling and storage services, supply agreements, service agreements, land leases and sale-leaseback financing arrangements (the sale-leaseback financing arrangements are discussed in Note 8 and are excluded from the tables below). From time to time, the Company also acquires certain mining equipment from Foresight Reserves and affiliated entities.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

12. Related-Party Transactions (continued)

 

As of December 31, 2013 and 2012, the Company had affiliate balances as follows:

 

Affiliated Company		Balance Sheet Location		December 31, 2013				December 31, 2012
				(In Thousands)
Foresight Reserves and affiliated entities		Due from affiliates		$	368			$	1,357
Foresight Reserves and affiliated entities		Due to affiliates		$	4,521			$	3,484
NRP and affiliated entities		Due to affiliates			5,051				8,267
				$	9,572			$	11,751
Foresight Reserves and affiliated entities		Prepaid royalties		$	37,644			$	22,575
NRP and affiliated entities		Prepaid royalties			39,801				34,390
				$	77,445			$	56,965

A summary of expenses incurred with affiliated entities is as follows:

 

		December 31, 2013				December 31, 2012				December 31, 2011
		(In Thousands)
Royalty expense – NRP		$	51,345			$	42,051			$	31,998
Royalty expense – Foresight Reserves			8,294				8,790				1,099
Loadout expense – NRP			10,000				11,608				10,279
Transportation services – Foresight Reserves and affiliated entities			30,217				26,275				3,325
Management and transportation usage fees – Foresight Reserves and affiliated entities			1,488				3,127				15,546

Royalty expenses are included in cost of coal sales (excluding depreciation, depletion and amortization). Fees for loadout services to NRP represent net loadout royalties and are also included in cost of coal sales (excluding depreciation, depletion and amortization). Fees for transportation services to Foresight Reserves and affiliated entities include throughput fees at the Convent Marine Terminal and Sitran terminal, which are included in transportation expense in the consolidated statements of operations. Management and transportation usage fees are included in selling, general and administrative expenses in the consolidated statements of operations.

During 2013, the Company purchased $9.0 million in mining supplies from an affiliated joint venture under a supply agreement entered into on May 1, 2013 (see Note 13).

The Company also paid an annual rental fee of $0.1 million to New River Royalty, LLC, a subsidiary of Foresight Reserves, in each of the prior three years under two land leases.

In connection with the 2013 Reorganization, each of the Company’s mines entered into a transloading and storage agreement with Sitran. These agreements will provide for the unloading of coal from railcars into stockpiles at Sitran and for the loading of coal from stockpiles into barges. Under these agreements each mine will pay Sitran $1.50 per ton of coal offloaded, stored or transloaded at Sitran. Each agreement has an initial term of three years and renews automatically for successive one-year periods until terminated by either party. The

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

12. Related-Party Transactions (continued)

 

transloading rate per ton escalates each year by 4%. The $1.50 per ton rate for transloading and storage at Sitran is materially consistent with the historical per ton costs incurred to operate the terminal prior to the 2013 Reorganization date.

On August 1, 2013, the Company entered into an equipment repair and rebuild agreement with an affiliate, Seneca Rebuild LLC (“Seneca Rebuild”). The agreement calls for Seneca Rebuild to be the primary provider of repair and rebuild services for mining machinery and equipment for the Company’s mines, subject to certain exceptions as set forth in the agreement. The initial term of the agreement is five years, ending in July 2018. The agreement requires Seneca Rebuild to provide a price quote for the performance of the work set forth in any repair or rebuild work order requested by one of the mines. The agreement permits the mines to obtain quotes from third parties for performance of the same work at any time before a written work order is executed with Seneca Rebuild and provides Seneca Rebuild an opportunity to match any lower quotes obtained by the mine. The Company’s mines did not utilize any Seneca Rebuild services during 2013.

13. Variable Interest Entities (VIEs)

The consolidated financial statements include VIEs for which Foresight Energy or a subsidiary is the primary beneficiary. Among those VIE that we consolidate are Mach Mining, LLC; M-Class Mining, LLC; Coal Field Construction Company LLC; MaRyan Mining LLC; Patton Mining LLC; Viking Mining LLC and LD Labor Company LLC (prior to the 2013 Reorganization date). Each of the VIEs holds a contract to provide one or more of the following services to a Foresight Energy subsidiary: contract mining, processing and loading services, or construction services. All of these entities were determined not to have sufficient equity at risk and are therefore VIEs. The Company was determined to be the primary beneficiary of each of these entities given it controls these entities under a contractual cost-plus arrangement.

On August 23, 2013, the Company effected the 2013 Reorganization pursuant to which certain transportation assets were distributed to its members. Among those assets distributed to its members was Adena Resources LLC (“Adena”), a subsidiary that provides water and other miscellaneous rights to the mines and Hillsboro’s coal loadout facility and the land on which the facility is situated (collectively, the “Loadout”).

Adena has various contractual water rights contracts with various state and local governments that are used to provide water to certain Foresight Energy mines. Concurrent with the distribution of Adena to its members, a water resources agreement was entered into between each of the Company’s mines and Adena providing for water resources to be available at each of the mines for use in mining operations. The agreements, which have an initial term of three years, will automatically renew for successive one-year periods unless either party opts out of the agreement. As compensation for furnishing water to the mines, the Company will pay Adena the actual cost incurred by Adena in furnishing water to the mine plus an annual administrative fee in the amount of $10,000. The Company is also responsible for reimbursing Adena for any future capital expenditures necessary to fulfill its obligations under the agreement. This entity was determined not to have sufficient equity at risk and is therefore a VIE. The Company was determined to be the primary beneficiary of Adena given the Company controls this entity under a contractual cost-plus arrangement.

Subsequent to the 2013 Reorganization date, Foresight Reserves placed the Loadout into a newly created subsidiary, Hillsboro Transport, LLC (“Hillsboro Transport”). Concurrent with the distribution, a throughput agreement was entered into between Hillsboro and Hillsboro Transport for Hillsboro Transport to operate the Loadout for Hillsboro. The agreement, which has an initial term of ten years, grants Hillsboro Transport the right to be the exclusive provider of clean coal handling services for Hillsboro. After the initial term of the throughput

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

13. Variable Interest Entities (VIEs) (continued)

 

agreement, the parties can agree to continue renewing the agreement in five-year increments (up to 16 times). At the expiration of each term, Hillsboro has an option to acquire the Loadout for its then fair value. As compensation for operating and maintaining the Loadout, Hillsboro Transport will receive $0.99/ton for every ton of coal loaded through the Loadout, subject to a minimum quarterly payment of $1.3 million beginning in 2014. Hillsboro Transport was determined not to have sufficient equity at risk as a result of the throughput agreement’s guaranteed minimum quarterly payments and is therefore a VIE. Hillsboro Energy was determined to be the primary beneficiary of this entity as it implicitly controls Hillsboro Transport given the related-party relationship between Hillsboro and Hillsboro Transport and the fact that the sole assets held by Hillsboro Transport are unique to Hillsboro’s operations.

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

 

		December 31, 2013				December 31, 2012
		(In Thousands)
Assets:
Current assets		$	4,386			$	3,472
Long-term assets			2,141				140
Total assets		$	6,527			$	3,612
Liabilities:
Current liabilities		$	5,310			$	5,017
Long-term liabilities			157				—
Total liabilities		$	5,467			$	5,017

On May 1, 2013, a related party through common majority ownership and an unrelated third-party supplier of mining equipment formed a joint venture whose purpose is the manufacture and sale of certain supplies primarily for use by the Company in the conduct of its mining operations. Upon the formation of the joint venture, the Company amended its existing supply agreement with this unaffiliated supplier to add the joint venture as a supplier party, extend the term of the supply agreement and update the pricing provisions of the supply agreement. The agreement, as amended, includes a requirement under which the Company’s coal mines are obligated to purchase at least 90% of their aggregate annual requirements for certain mining supplies from the supplier parties, subject to certain exceptions as set forth in the agreement. The initial term of the amended agreement is five years, ending in April 2018.

The supplies covered under this arrangement are sold pursuant to a price schedule incorporated into the agreement that is reviewed and, if necessary, adjusted every nine months during the term based on specified cost drivers for the supplies to result in an agreed-upon fixed profit percentage for the joint venture as set forth in the agreement.

This joint venture was determined to be a VIE given that the equity holders of the joint venture do not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the joint venture as

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

13. Variable Interest Entities (VIEs) (continued)

 

a result of the Company guaranteeing a fixed -profit percentage on the supplies it purchases from the joint venture. The Company is not the primary beneficiary of this joint venture and, therefore, does not consolidate the joint venture, given that the power over the joint venture is conveyed through the board of directors of the joint venture and no party controls the board of directors.

14. Derivative Contracts

The Company has commodity price risk as a result of changes in the market value of its coal. The Company attempts to minimize this risk by entering into long-term fixed price coal supply agreements and commodity hedge agreements.

As of December 31, 2013, the Company had outstanding coal purchase and sale commodity derivative contracts to fix the selling price on 2.0 million tons as economic hedges to certain future unpriced sales commitments through 2016. The Company accounts for these coal commodity contracts as freestanding derivatives and records any gains or losses resulting from adjusting these contracts to fair value in earnings.

In October 2012, the Company entered into coal purchase and sale commodity derivative contracts totaling 300,000 tons. The Company accounted for these coal commodity contracts as free-standing derivatives and recorded any gains or losses resulting from adjusting these contracts to fair value in earnings. These contracts were settled in January 2013. The $1.0 million in proceeds from the settlement of the commodity contracts was recorded as an investing activity in the consolidated statement of cash flows because the commodity contracts were settled prior to the underlying economic hedge.

During the years ended December 31, 2013, 2012 and 2011, $2.4 million, $0.5 million and $2.4, respectively, was recorded as a gain on commodity contracts in the consolidated statements of operations to adjust derivative contracts to fair market value. For classification purposes, the Company records the fair value of all the positions with a given counterparty on a gross basis in the consolidated balance sheets (see Note 17).

15. Contract Settlements

In April 2012, the Company entered into a settlement agreement with a customer related to a dispute over a coal supply agreement dating back to 2009. Under the terms of the settlement agreement, the Company received $10.0 million in cash proceeds, which was recorded in other operating income, net in the consolidated statement of operations during the year ended December 31, 2012, and as an operating activity in the consolidated statement of cash flows. The Company has no future performance obligations under the settlement agreement or the original coal supply agreement.

16. Commitments and Contingencies

The Company is subject to various market, operational, financial, regulatory and legislative risks. Numerous federal, state and local governmental permits and approvals are required for mining operations. Federal and state regulations require regular monitoring of mines and other facilities to document compliance. The Company believes it has obtained all permits currently required to conduct present mining operations. From time to time in the normal course of business, the Company may be required to prepare and present to federal, state, or local authorities data pertaining to the effect or impact that a proposed exploration for, or production of, coal may have on the environment.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

16. Commitments and Contingencies (continued)

 

These requirements could prove costly and time consuming and could delay commencing or continuing exploration, development or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the Company’s mining activities may be more closely regulated. Such legislation and regulations, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs and cause delays, interruptions, or a termination of operations, the extent of which cannot be predicted.

The Company endeavors to conduct its mining operations in compliance with all applicable federal, state, and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. To date, none of the violations or the monetary penalties assessed upon the Company have been material. Periodically, there are various claims and legal proceedings against the Company arising from the normal course of business. Although counsel is unable to predict with certainty the ultimate outcome, in the opinion of management, these claims are matters incidental to the normal business conducted by the Company.

In April 2013, the Illinois Environmental Protection Agency (“IEPA”) issued Sugar Camp two violation notices regarding exceedances in effluent discharge from the mine site and improper dilution of high chloride effluent. Sugar Camp believes that it is now in compliance with its permit and is in the process of working with the IEPA to implement a sustainable solution for the future disposal of water at the mine in compliance with its permits. Sugar Camp expects to enter into a compliance commitment agreement with the IEPA documenting its plan, which requires capital expenditures of approximately $15—$20 million, $7.5 million of which was expended in 2013. In late January 2014, the IEPA issued Sugar Camp a violation notice regarding construction of an underground injection well without issuance of an appropriate permit. Sugar Camp has ceased all drilling activities at the site and is working with the IEPA to finalize its permit application, which has been in process since May 2013.

In March 2009, the Sierra Club, two citizen groups and twelve individuals filed Requests for Administrative Review (“Hillsboro Requests”) of Hillsboro’s Deer Run Mine SMCRA Permit No. 399, the principal operating permit for the mine. The petitioners asked for reconsideration of issuance of the SMCRA permit on several grounds. In November 2013, the hearing officer dismissed all of the remaining Hillsboro Requests for petitioners’ failure to respond to outstanding discovery. The petitioners have filed an appeal of this dismissal order in an Illinois circuit court. While we believe the permit was properly issued and that we will prevail on the appeal, there can be no guarantee that the permit will not be vacated or substantially modified, which could result in production delays, additional costs or cessation of some or all operations at the mine.

In November 2012, six citizens filed requests for administrative review of Revision No. 1 to Permit No. 399 for the Hillsboro mine. Revision No. 1 allowed for conversion of the currently permitted coal refuse disposal facility from a non-impounding to an impounding structure. Shortly after the filing of Revision No. 1, one citizen withdrew his request. Following a hearing on both IDNR’s and Hillsboro’s motions to dismiss, the hearing officer dismissed the claims of two of the remaining five petitioners and also limited some of the issues remaining for administrative review. The legal proceeding is ongoing. To date, no deadlines or final hearing date has been set in this matter.

Foresight Energy purchased the Shay No. 1 Mine at Macoupin (“Shay Mine”) in 2009. Prior to the acquisition of the mine, in 2003, ExxonMobil Coal USA, Inc. (“Exxon”), the prior owner of the Shay Mine, enrolled the mine in the IEPA’s Site Remediation Program (“SRP”) to address some concerns regarding groundwater contamination from the refuse areas. Under the SRP, Exxon and Macoupin collected and quantified requested

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

16. Commitments and Contingencies (continued)

 

data. In the fall of 2011, Macoupin proposed, and IEPA accepted, a compliance commitment agreement (“CCA”) with remediation steps designed to respond to the groundwater contamination concerns. Further, in May 2013, Macoupin submitted a Corrective Action Plan (“CAP”) with Groundwater Modeling to the IEPA to address the long-term compliance and corrective measures planned for the clean-up of groundwater contamination issues. In June 2013, the IEPA referred the CCA to the Illinois Attorney General’s office for enforcement on the basis that the compliance period for the CCA extended for too long of a period for the IEPA to monitor. We believe that the CAP for the groundwater issues will be finalized and implemented through a consent decree with the Illinois Attorney General’s office at some point in the future. As of December 31, 2013, the Company has accrued $11.5 million for this matter as an asset retirement obligation, as it relates to ongoing mining operations at Macoupin. While there can be no assurance that the ultimate costs will not exceed this amount, the Company does not expect that to be the case.

Also at Macoupin, the IDNR issued a permit on July 27, 2012, along with revisions to two existing permits at Macoupin, to allow underground coal slurry disposal. In August 2012, a citizen and an environmental group filed Requests for Administrative Review of the permit. In January 2014, the hearing officer granted summary judgment in favor of Macoupin. Additionally, the IDNR renewed a permit for the refuse disposal area. An environmental group has submitted a Request for Administrative Review of this permit renewal and the legal proceeding is ongoing. While the Company believes the IDNR decisions on the issuance of the permit for slurry disposal and renewal for existing refuse disposal area was proper, there can be no guarantee that the permit and the revisions to permits will not be vacated or substantially modified, which could result in additional costs or cessation of some or all operations at the mine.

The Company is also party to various other litigation matters, in most cases involving ordinary and routine claims incidental to the Company’s business. The Company cannot reasonably estimate its ultimate legal and financial liability with respect to such pending litigation matters. However, the Company believes, based on its examination of such matters, that the ultimate liability will not have a material adverse effect on its financial position, results of operations or cash flows.

Performance Bonds

The Company has outstanding surety bonds with third parties of approximately $45.1 million as of December 31, 2013 to secure reclamation and other performance commitments. The Company is not required to post collateral for these bonds.

17. Fair Value of Financial Instruments

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

 

		Fair Value at December 31, 2013
		Total				Level 1				Level 2				Level 3
		(In Thousands)
Commodity contracts		$	2,020			$	—			$	2,020			$	—
Liability Award			(11,700	)			—				—				(11,700	)
Total		$	(9,680	)		$	—			$	2,020			$	(11,700	)

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

17. Fair Value of Financial Instruments (continued)

 

		Fair Value at December 31, 2012
		Total				Level 1				Level 2				Level 3
		(In Thousands)
Commodity contracts		$	534			$	—			$	534			$	—
Total		$	534			$	—			$	534			$	—

The Company’s commodity contracts are valued based on direct broker quotes and corroborated with API 2 market pricing data (see Note 14). The Liability Award represents a phantom equity award to an executive of the Company (see Note 9). The Liability Award’s value is determined based on the fair value, as defined in the agreement, of Foresight Reserves and is adjusted for distributions made to Foresight Reserves’ members. The Liability Award is Level 3 in the fair value hierarchy given Foresight Reserves is a private company; therefore, there is no liquid market to determine the fair value of Foresight Reserves’ equity. The fair value of the Liability Award was determined using a discounted cash flow model and corroborated with recent equity transactions at Foresight Reserves. During the years ended December 31, 2013 and 2012, the Company had no assets or liabilities that were transferred between Level 1 and Level 2.

The classification and amount of the Company’s financial instruments, which are presented on a gross basis in the consolidated balance sheets as of December 31, 2013 and 2012, are as follows:

 

		Fair Value at December 31, 2013
		Other Current Assets				Other Assets				Accrued Expenses				Other Long-Term Liabilities
		(In Thousands)
Commodity contracts		$	1,976			$	912			$	(531	)		$	(337	)
Liability Award			—				—				(11,700	)			—
Total		$	1,976			$	912			$	(12,231	)		$	(337	)
		Fair Value at December 31, 2012
		Other Current Assets				Other Assets				Accrued Expenses				Other Long-term Liabilities
		(In Thousands)
Commodity contracts		$	534			$	—			$	—			$	—
Total		$	534			$	—			$	—			$	—

The following is a reconciliation of the beginning and ending balances for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31, 2013:

 

		Liability Award
		(In Thousands)
Liability balance, January 1, 2013		$	—
Recorded fair value (gains) or losses:
Included in earnings			677
Capitalized into development costs			(217	)
Purchases, issuances and settlements			11,240
Liability balance, December 31, 2013		$	11,700

There were no Level 3 assets or liabilities measured at fair value on a recurring basis during the years ended December 31, 2012 and 2011.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

17. Fair Value of Financial Instruments (continued)

 

Long-Term Debt

The fair value of the Company’s long-term debt as of December 31, 2013 and 2012 was $ 1,509.2 million and $1,043.8 million, respectively. The fair value of long-term debt was determined based on the amount of future cash flows associated with each debt instrument discounted at the Company’s current estimated credit-adjusted borrowing rate for similar debt instruments with comparable terms. This is considered a Level 3 fair value measurement.

18. Member Units

On December 31, 2012, member units (representing less than 1% of the total outstanding member units) were provided to executive management of the Company (the “Units”) from the existing outstanding units of the Company held by Foresight Reserves. The granting of the Units by Foresight Reserves was discretionary and was not issued pursuant to a contractual incentive plan and the Units are not subject to vesting restrictions or forfeiture. The Units carry certain put rights under which Reserves could be required to buy back these units. The Company recorded $4.6 million expense for this equity-based compensation which is included in selling, general and administrative expense in our consolidated statement of operations as the Units were provided for services rendered to the Company. The recorded equity-based compensation represents the fair value of the Units based on the estimated fair value of the Company that was determined using a discounted cash flow valuation model (Level 3 in the fair value hierarchy) and corroborated using a market-based approach.

19. Employee Benefit Plans

The Company offers safe harbor 401(k) plans (the “Plans”) for all employees who are eligible to participate. Employees are immediately eligible to participate upon becoming a full-time employee with the Company. The Plans allow for the deferral of all or part of a participant’s compensation, as defined by the Plans, up to the current limits provided by the Internal Revenue Service. The safe harbor matching feature calls for the Company to contribute 100% of the first 3% of compensation a participant contributes, and 50% of the next 2% of compensation contributed by the participant. Company contributions under the Plans for the years ended December 31, 2013, 2012, and 2011 were $2.5 million, $2.4 million, and $1.6 million, respectively.

20. Risk Concentrations

Sales and Credit Risk

The Company determines creditworthiness and credit limits for trade customers based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established. Credit losses are provided for in the financial statements and historically have been minimal.

For the year ended December 31, 2013, no customers represented greater than 10% of the Company’s total coal sales. For the year ended December 31, 2012, the Company’s two largest customers represented approximately 14% and 10% of the Company’s total coal sales. For the year ended December 31, 2011, the Company’s two largest customers represented approximately 16% and 11% of the Company’s coal sales. The Company’s largest customers vary from year-to-year. These customer percentages are inclusive of nominal development tons sold during these periods (see Note 2). No other customers for the years ended December 31, 2012 or 2011 represented greater than 10% of coal sales.

 

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Foresight Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

20. Risk Concentrations—(Continued)

 

During the years ended December 31, 2013, 2012 and 2011, export tons represented 34%, 46% and 32% of tons sold, respectively. During the years ended December 31, 2013 and 2012, tons exported into Europe represented approximately 23% and 27%, respectively, of tons sold. No other international geographic regions exceeded 10% of tons sold during the years ended December 31, 2013 and 2012. During the year ended December 31, 2011, no geographic regions outside of the United States represented greater than 10% of tons sold.

Transportation

The Company depends on rail, barge, and export terminal systems to deliver coal to its customers. Disruption of these services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Company’s ability to supply coal to its customers, resulting in decreased shipments. As such, the Company has sought to diversify transportation options and has entered into long-term contracts with transportation providers to ensure transportation is available to transport its coal.

21. Summary Quarterly Financial Information (Unaudited)

A summary of the unaudited quarterly results for the years ended December 31, 2013 and 2012 is presented below:

 

		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter
		(In Thousands)
2013
Coal sales		$	232,593			$	215,930			$	240,868			$	268,021
Operating income			57,420				41,927				49,488				55,352
Net income (loss)			29,220				14,167				(57,833	)			24,963
2012
Coal sales		$	141,351			$	213,834			$	240,203			$	250,498
Operating income			40,778				70,124				68,768				28,581
Net income			25,168				51,245				47,756				1,502

In the third quarter of 2013, the Company recorded a loss of $77.8 million for the early debt extinguishment of debt in the consolidated statement of operations which includes $72.1 million in tender costs and fees to redeem the 2017 Senior Notes and the write-off of $5.7 million in unamortized deferred debt issuance costs and the net unamortized debt premium of the extinguished debt.

In the fourth quarter of 2013, the Company reversed $4.3 million in discretionary bonuses, which had been accrued ratably during the first three quarters of 2013.

In the first quarter of 2012, the Company entered into a settlement agreement with a customer related to a dispute over a coal supply agreement dating back to 2009. The Company received $10.0 million in cash proceeds, which was recorded in other operating income, net in the consolidated statement of operations.

During the fourth quarter of 2012, the Company recorded $6.5 million in depreciation, depletion and amortization in the consolidated statement of operations for amortization expense on subsidence rights for which the mineral rights that were benefited by the subsidence rights had been mined in prior years and in prior quarters of 2012. Of this amount, $3.3 million related to years prior to 2012 and $1.0 million, $1.2 million and $1.0

 

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Notes to Consolidated Financial Statements

21. Summary Quarterly Financial Information (Unaudited)—(Continued)

 

million related to the first, second and third quarters of 2012, respectively. Prior periods were not adjusted as such amounts were immaterial and thus the entire amortization expense was recorded in the fourth quarter of 2012.

Additionally, during the fourth quarter of 2012, the Company recorded $4.3 million to write-off previously capitalized deferred issuance costs related to an IPO pursuit and $11.5 million in incremental compensation expense related to annual discretionary bonuses awarded and paid to management in the fourth quarter, which were recorded to selling, general and administrative expenses. Also impacting comparability amongst the quarters was $5.9 million being recorded to transportation expense in the consolidated statement of operations during the fourth quarter of 2012 as a result of a change in estimate for not meeting contractual annual minimum volume commitments under certain transportation agreements with third parties.

 

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APPENDIX A: FORM OF PARTNERSHIP AGREEMENT

 

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APPENDIX B: CERTAIN DEFINED TERMS—BUSINESS

2010 Reorganization. The reorganization described under “Business—2010 Reorganization.”

2013 Refinancing. The refinancing described under “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Liquidity and Capital Resources.”

2013 Reorganization. The reorganization described under “Business—2013 Reorganization”

2017 Senior Notes. Foresight Energy LLC and Foresight Energy Finance Corporation’s $600 million 9.625% senior unsecured notes due 2017.

2021 Senior Notes. Foresight Energy LLC and Foresight Energy Finance Corporation’s $600 million 7.875% senior unsecured notes due 2021.

Adena Entities. Christopher Cline, Foresight Reserves, L.P., Adena Minerals LLC, and their respective affiliates.

Adena Resources. Adena Resources, LLC.

ARRA. American Recovery and Reinvestment Act.

Ash. Inorganic material consisting of iron, alumina, sodium and other incombustible matter that is contained in coal. The composition of the ash can affect the burning characteristics of coal.

Assigned reserves. Coal that has been committed to be mined at identified operating facilities and potential future operations

Bituminous coal. The most common type of coal that is between sub-bituminous and anthracite rank. Bituminous coals produced from the Central and Eastern United States coal fields typically have moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btus.

BNSF. Burlington Northern Santa Fe Railway Company.

British thermal unit or “Btu.” A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

CAIR. Clean Air Interstate Rule.

Central Appalachia. Coal producing area in eastern Kentucky, Virginia and southern West Virginia and northern Tennessee.

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act of 1980.

Clean Air Act Amendments of 1990 and the Clean Air Act. The Clean Air Act was originally passed in 1970 to address significant air pollution problems in our cities. The 1990 amendments broadened and strengthened the original law to address specific problems such as acid deposition, urban smog, hazardous air pollutants and stratospheric ozone depletion.

The Cline Group. The Cline Resource and Development Company its subsidiaries and affiliates.

CN. Canadian National Railway Company.

Coal seam. Coal deposits occur in layers typically separated by layers of rock. Each layer is called a “seam.” A seam can vary in thickness from inches to a hundred feet or more.

 

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Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel.

Colt. Colt LLC.

Continuous miner. A machine which constantly extracts coal while loading. This is to be distinguished from a conventional mining unit which must stop the extraction process in order for loading to commence.

Convent Marine Terminal. A terminal in Convent, Louisiana located at mile marker 161.5 on the Mississippi River, formerly known as IC RailMarine Terminal.

CSAPR. Cross-State Air Pollution Rule.

CCS. Carbon capture and storage.

CSX. CSX Corporation.

CWA. The Clean Water Act of 1972.

EIA. Energy Information Administration.

EPA. Environmental Protection Agency.

ExxonMobil. Exxon Mobil Coal USA, Inc.

FCS. Foresight Coal Sales LLC, a subsidiary of Foresight Energy LLC.

Flexible conveyor train or FCT. A continuous haulage system that eliminates the use of mobile coal haulage equipment such as shuttle cars or battery powered coal haulers. It helps eliminate any haulage related bottlenecks from typical underground continuous miner operations, allowing a continuous miner to operate at its maximum capacity. A flexible conveyor and traction system permits the FCT to be operated as one single unit, continuously conveying material along its length while simultaneously tramming to follow the continuous miner’s movement, all with only one operator.

Foresight Energy Services. Foresight Energy Services LLC.

Foresight Management. Foresight Management LLC.

Foresight Reserves. Foresight Reserves, L.P.

Fossil fuel. A hydrocarbon such as coal, petroleum or natural gas that may be used as a fuel.

GHG. Greenhouse gas(es).

GWs. Gigawatts.

IDNR. Illinois Department of Natural Resources.

IEPA. Illinois Environmental Protection Agency.

Illinois Basin. Coal producing area in Illinois, Indiana and western Kentucky.

 

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Independence . Independence Land Company, LLC.

Interior Region. Coal producing area consisting of the Illinois Basin, Arkansas, Kansas, Louisiana, Mississippi, Missouri, Oklahoma and Texas.

IPCB. Illinois Pollution Control Board.

IPO Reorganization. The reorganization described under “Prospectus Summary—IPO Reorganization.”

Lignite. The lowest rank of coal. It is brownish-black with a high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu.

Longwall mining. A productive underground mining method in the United States. A shearer with two rotating cutting drums trams across the longwall face, cutting the coal and transferring it to an armored chain conveyor. Hydraulic supports hold the roof as the longwall mining system advances through the coal.

Below is an illustrative diagram of the longwall mining process.

 

M-Class. M-Class Mining, LLC, an independent contract miner.

Mach. Mach Mining, LLC, an independent contract miner.

MaRyan. MaRyan Mining LLC, an independent contract miner.

MATS. Mercury and Air Toxics Standards.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal has a particularly high Btu, but low ash content.

Mineable coal. That portion of the coal reserve base which is commercially mineable and excludes all coal that will be left, such as in pillars, fenders or property barriers.

MSHA. Mine Safety and Health Administration.

 

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Mt. Millions of tons.

NAAQS. National Ambient Air Quality Standards.

Northern Appalachia. Coal producing area in western Maryland, eastern Ohio, southwestern Pennsylvania and northern West Virginia.

NOx. Nitrogen oxides. NOx represents both NO2 and NO3 which are gases formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to acid rain and is a precursor of ozone.

NPDES. The National Pollutant Discharge Elimination System.

NRP. Natural Resource Partners, L.P.

NS. Norfolk Southern Corporation.

NYSE. New York Stock Exchange.

OSM. The Office of Surface Mining Reclamation and Enforcement.

Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Patton Mining. Patton Mining LLC, an independent contract miner.

PRB. Powder River Basin. Coal producing area in northeastern Wyoming and southeastern Montana.

Preparation plant. A facility for crushing, sizing and washing coal to prepare it for use by customers. The washing process separates ash from the coal and may also remove some of the coal’s sulfur content. Usually located on a mine site, although one plant may serve several mines.

Prior Credit Facility. Foresight Energy LLC’s amended and restated senior secured credit facility dated as of December 15, 2011.

Probable reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Productive Capacity. Productive capacity is an estimate of the design and annual production capacity at each mine based on the number of potential longwall mining units and two continuous miner units supporting each longwall mining system at each of Williamson, Sugar Camp and Hillsboro, and three continuous miner units operating at Macoupin. Achievement of full productive capacity and the timing are subject to risks and uncertainties, including, among others, adverse geology, 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. See “Risk Factors” for a more detailed discussion of such risks and uncertainties.

Productivity . As used in this prospectus, refers to clean tons of coal produced per underground man hour worked, as published by the Mine Health and Safety Administration (MSHA).

Proven reserves. Reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

 

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RCRA. Resource Conservation and Recovery Act.

Reclamation. The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes reshaping the land to its approximate original contour, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations. Reclamation is closely regulated by both state and federal laws.

Reserve. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

RGGI. Regional Greenhouse Gas Initiative.

Riverstone. Riverstone Holdings LLC and certain of its affiliates.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

Roof supports. Longwall equipment, including chocks or shields equipped with hydraulic cylinders which are placed in a long line, side by side, to support the roof of the coalface.

Ruger. Ruger Coal Company, LLC.

Savatran. Savatran LLC, a subsidiary of Foresight Energy LLC.

Scrubber (flue gas desulfurization system). Any of several forms of chemical/physical devices which operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal. Although effective in substantially reducing sulfur from combustion gases, scrubbers require about 6% to 7% of a power plant’s electrical output and thousands of gallons of water to operate.

SEC. The Securities and Exchange Commission.

Securities Act. The Securities Act of 1933, as amended.

Senior Secured Credit Facilities. Foresight Energy LLC’s amended and restated senior secured credit facilities dated as of August 23, 2013.

Severance tax. A tax imposed on the removal of a natural resource, such as crude oil or coal.

Sitran. Sitran LLC.

Slope. Underground mine access shaft which travels downward towards the coal seam.

SMCRA. The Surface Mining Control and Reclamation Act of 1977, as amended.

Sub-bituminous coal. Black coal that ranks between lignite and bituminous coal. Sub-bituminous coal produced from the PRB has a moisture content between 20% to over 30% by weight, and its heat content ranges from 8,000 to 9,500 Btus of coal.

Subsidence. Lateral or vertical movement of surface land that occurs when the roof of an underground mine collapses. Longwall mining causes planned subsidence by the mining out of coal that supports the overlying strata.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide (SO2) is produced as a gaseous by-product of coal combustion.

 

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Sulfur dioxide emission allowance. A tradable authorization to emit sulfur dioxide. Under Title IV of the Clean Air Act, one allowance permits the emission of one ton of sulfur dioxide.

Thermal coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal. Also commonly referred to as “steam coal.”

TMDL. Total Maximum Daily Load.

Tons. The short ton is the unit of measure referred to in this prospectus, unless otherwise noted. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds. A “metric” tonne is approximately 2,205 pounds.

TVA. Tennessee Valley Authority.

Unassigned reserves. Coal at suspended locations and coal that has not been committed to be mined at existing operating facilities or potential future operations.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface and accessed by a slope, drift portal or shaft. Most underground mines are located east of the Mississippi River and underground mines account for about 40% of annual United States coal production.

UP. Union Pacific Railroad Corporation.

Wheelage. A fee payable to a property owner or lessor for the transit of coal, usually assessed on a per ton basis.

Williamson Royalty Ventures. Williamson Royalty Ventures LLC.

Wood Mackenzie. Wood Mackenzie Ltd.

WPP. WPP, LLC.

 

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APPENDIX C: CERTAIN DEFINED TERMS—OFFERING STRUCTURE

Adjusted operating surplus: For any period, operating surplus (excluding any amounts attributable to the items in the first bullet point under the definition of operating surplus) generated during that period is adjusted to:

 

•

decrease operating surplus by:

 

•

the amount of any net increase during that period in working capital borrowings; and

 

•

the amount of any net decrease during that period in cash reserves for operating expenditures not relating to an operating expenditure made during that period; and

 

•

the amount of any expenditures that are not operating expenditures solely because of the provision described in the last bullet point under the definition of operating expenditures; and

 

•

increase operating surplus by:

 

•

the amount of any net decrease during that period in working capital borrowings; and

 

•

the amount of 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; and

 

•

the amount of 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 in adjusted operating surplus in subsequent periods.

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.

Capital account: The capital account maintained for a partner under our partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in us held by a partner.

Capital surplus. All cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all cash distributed since the closing of the initial public offering equals the operating surplus from the closing of the initial public offering through the end of the quarter immediately preceding that distribution. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus.

Common units. The common units representing limited partner interests in Foresight Energy LP offered pursuant to this offering. See “Description of Common Units.”

General partner. Foresight Energy GP LLC, our general partner, which is owned by Foresight Reserves, L.P. and a member of management.

Interim capital transactions: means the following transactions:

 

•

borrowings (other than working capital borrowings);

 

•

sales of equity interests; and

 

•

sales or other dispositions of assets for cash, other than inventory, accounts receivables and other assets in the ordinary course of business, or as part of normal retirements or replacements of assets.

 

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Maintenance Capital Expenditures: Cash expenditures made to maintain our long-term operating capacity or net income (for instance, 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 our long-term operating capacity or net income).

Maintenance capital expenditures also includes 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 construction or developing a replacement asset and ending on the earlier of the date that any such replacement asset commences commercial service and the date that the asset is abandoned or disposed of.

Operating expenditures: All of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under interest rate hedge agreements or commodity hedge agreements (provided that (1) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (2) payments made in connection with the termination of any interest rate hedge contract or commodity 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 interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments 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 below when such repayment actually occurs;

 

•

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

 

•

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

 

•

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Operating surplus. Operating surplus consists of:

 

•

$         million; plus

 

•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, provided that cash receipts from the termination of any hedge contract prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such hedge contract; plus

 

•

cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of the construction, acquisition, improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period

 

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beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service and the date that it is abandoned or disposed of; less

 

•

cash distributions paid on equity issued by us (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; less

 

•

all of our operating expenditures (as defined above) 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.

The Partnership. “The Partnership,” “we” “us” and “our,” when used in a historical context, refer to Foresight Energy LLC and its subsidiaries. When used in the present tense or prospectively, those terms refer to Foresight Energy LP and its subsidiaries, giving effect to the IPO Reorganization.

Units. Refers to common units.

Working capital borrowings: Borrowings that our general partner intends for us to use for working capital purposes or to pay distributions to partners, made pursuant to a credit agreement or similar financing arrangement; provided, that, when such debt is incurred, it is the intent of the borrower to repay such borrowings within 12 months from sources other than additional working capital borrowings.

 

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FORESIGHT ENERGY LP

Common Units

Representing Limited Partner Interests

 

 

PRELIMINARY PROSPECTUS

                    , 2014

 

 

Barclays

Citigroup

Morgan Stanley

J.P. Morgan

Goldman, Sachs & Co.

Deutsche Bank Securities

Dealer Prospectus Delivery Obligation

Until                     , 2014 (25 days after the commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

 

 

 

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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Other expenses in connection with the issuance and distribution of the securities to be registered hereunder will be substantially as follows (all amounts are estimated except the Securities and Exchange Commission registration fee and the Financial Industry Regulatory Authority filing fee):

 

Item		Amount
Securities and Exchange Commission registration fee		$	34,380
FINRA filing fee		$	30,500
NYSE fee				*
Blue Sky filing fees and expenses				*
Accounting fees and expenses				*
Legal fees and expenses				*
Transfer agent fees and expenses				*
Printing and engraving expenses				*
Miscellaneous expenses				*
Total		$		*

 

*	To be provided by amendment.

The Registrant will bear all expenses shown above.

Item 14. Indemnification of Directors and Officers.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the underwriting agreement to be filed as an exhibit to this registration statement, which provides for the indemnification of Foresight Energy LP and our general partner, their officers and directors, and any person who controls Foresight Energy LP and our general partner, including indemnification for liabilities under the Securities Act. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever. As of the consummation of this offering, the general partner of the registrant will maintain directors and officers liability insurance for the benefit of its directors and officers.

Item 15. Recent Sales of Unregistered Securities.

On January 26, 2012, in connection with the formation of Foresight Energy LP, or the Partnership, the Partnership issued (i) to Foresight Energy GP LLC, its general partner, a non-economic general partner interest in the Partnership and (ii) to Foresight Reserves, LP the 100.0% limited partner interest in the Partnership for $1,000. The issuance was exempt from registration under Section 4(2) of the Securities Act of 1933. There have been no other sales of unregistered securities within the past three years.

Item 16. Exhibits and Financial Statement Schedules.

(a) Exhibits.

 

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INDEX TO EXHIBITS

 

Exhibit Number		Description of Documents
1.1*		Form of Underwriting Agreement
3.1**		Certificate of Limited Partnership of Foresight Energy LP
3.2*		Form of Partnership Agreement of Foresight Energy LP (included as Appendix A to the Prospectus)
4.1*		Form of Registration Rights Agreement
4.2**		Indenture, dated as of August 23, 2013, by and among Foresight Energy LLC, Foresight Energy Finance Corporation, the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee
5.1*		Opinion of Cahill Gordon & Reindel LLP as to the legality of the securities being registered
8.1*		Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*		Form of Contribution, Conveyance and Assumption Agreement
10.3*		Form of Long-Term Incentive Plan
10.4**		Amendment Agreement (including the Amended and Restated Credit Agreement), dated as of August 23, 2013 by and among Foresight Energy LLC, certain subsidiaries of Foresight Energy LLC, Citibank, N.A., as administrative agent, and the lenders party thereto
10.5**		Credit Agreement, dated as of January 5, 2010, by and among Sugar Camp Energy LLC, as the borrower, Foresight Energy LLC, as a guarantor, Crédit Agricole Corporate and Investment Bank, as Administrative Agent (formerly known as Calyon New York Branch) and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent (formerly known as CALYON Deutschland Niederlassung Einer Französischen Societé Anonyme) (the “Sugar Camp Credit Agreement”)
10.6**		First Amendment to the Sugar Camp Credit Agreement dated as of February 5, 2010, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.7**		Second Amendment to the Sugar Camp Credit Agreement and First Amendment to Foresight Guarantee, dated as of August 4, 2010, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.8**		Third Amendment to the Sugar Camp Credit Agreement, dated as of September 24, 2010, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent

 

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Exhibit Number		Description of Documents
10.9**		Fourth Amendment to the Sugar Camp Credit Agreement, dated as of May 27, 2011, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment   Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.10**		Fifth Amendment to the Sugar Camp Credit Agreement and First Amendment to Guaranty, dated as of March 8, 2012, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.11**		Sixth Amendment to the Sugar Camp Credit Agreement and Second Amendment to Guaranty, dated as of August 23, 2013, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.12**		Guaranty of the Sugar Camp Credit Agreement by Foresight Energy LLC, as guarantor, in favor of Crédit Agricole Corporate and Investment Bank, as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent dated May 27, 2011
10.13**		Credit Agreement, dated as of May 14, 2010, by and among Hillsboro Energy LLC, as the borrower, Foresight Energy LLC, as a guarantor, Credit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent (the “Hillsboro Credit Agreement”)
10.14**		First Amendment to the Hillsboro Credit Agreement, dated as of June 17, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.15**		Second Amendment to the Hillsboro Credit Agreement and First Amendment to Foresight Guaranty dated as of August 4, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.16**		Third Amendment to the Hillsboro Credit Agreement dated as of September 24, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.17**		Fourth Amendment to the Hillsboro Credit Agreement dated as of May 27, 2011, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent

 

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Exhibit Number		Description of Documents
10.18**		Fifth Amendment to the Hillsboro Credit Agreement and First Amendment to Guaranty dated as of March 8, 2012, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.19**		Sixth Amendment to the Hillsboro Credit Agreement and Second Amendment to Guaranty dated as of August 16, 2013, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.20**		Guaranty of the Hillsboro Credit Agreement by Foresight Energy LLC, as guarantor, in favor of Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent dated May 27, 2011
10.21**		Illinois Coal Lease dated July 1, 2002 from the United States of America, as Lessor acting through its legal agent, the Tennessee Valley Authority, (“TVA”), to Illinois Fuel Company, LLC, as Lessee (“Illinois Coal Lease”), which was assigned to Ruger Coal Company, LLC, with such assignment and transfer being consented to by TVA, by an Assignment and Assumption Agreement effective on August 4, 2009 (“Assignment and Assumption Agreement”) by and among TVA, Illinois Fuel Company, LLC and Ruger Coal Company, LLC wherein TVA consented to “the mining of the Lease reserves by Sugar Camp Energy, LLC, and with Ruger Coal Company, LLC agreeing that Sugar Camp Energy, LLC can mine the Illinois Coal Lease reserves and consenting to the mining of such reserves in a Consent dated effective on January 22, 2010 between Ruger Coal Company, LLC and Sugar Camp Energy, LLC (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.22**		Amendment One to Illinois Coal Lease dated April 10, 2012 between United States of America, as Lessor acting through its legal agent, the Tennessee Valley Authority (“TVA”), and Illinois Fuel Company LLC, Lessee (as assigned to Ruger Coal Company LLC under that Assignment and Assumption Agreement dated August 4, 2009 by and among TVA, Illinois Fuel Company, LLC, Assignor and Ruger Coal Company LLC, Assignee, and expressly granting Sugar Camp Energy, LLC the right to mine the reserves subject to the lease) (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.23**		Amendment Two to Illinois Coal Lease effective as of August 30, 2012 by and between United States of America, as Lessor acting through its legal agent, the Tennessee Valley Authority (“TVA”), and Illinois Fuel Company LLC, Lessee (as assigned to Ruger Coal Company LLC under that Assignment and Assumption Agreement dated August 4, 2009 by and among TVA, Illinois Fuel Company, LLC, Assignor and Ruger Coal Company LLC, Assignee, and expressly granting Sugar Camp Energy, LLC the right to mine the reserves subject to the lease) (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.24**		Master Lease Agreement between PNC Equipment Finance, LLC, as Lessor and Foresight Energy Services LLC, as Lessee dated October 31, 2013, that Master Lease Guaranty delivered by Foresight Energy LLC in favor of PNC Equipment Finance, LLC in connection with Master Lease Agreement, and that Real Property Waiver for the benefit of PNC Equipment Finance, LLC by Williamson Energy LLC, Sugar Camp Energy LLC and Hillsboro Energy LLC dated October 31, 2013

 

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Exhibit Number		Description of Documents
10.25**		Master Lease Agreement dated March 30, 2012, among BB&T Equipment Finance Corporation (“BB&T”), as Lessor, Hillsboro Energy LLC, Sugar Camp Energy, LLC and Williamson Energy, LLC, collectively as Lessee, and Foresight Energy LLC, as guarantor
10.26**		Coal Mining Lease between RGGS Land & Mineral LTD., L.P. and Sugar Camp Energy, LLC dated July 29, 2005 (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.27**		First Amendment to Coal Mining Lease between RGGS Land & Minerals, LTD., L.P. and Sugar Camp Energy LLC dated August 11, 2008
10.28**		Amendment dated December 21, 2010 to Coal Mining Lease between RGGS Land & Minerals, LTD., L.P. and Sugar Camp Energy, LLC
10.29**		Surface Sublease between Sugar Camp Energy, LLC and Hod, LLC dated March 6, 2012
10.30**		Lease Agreement dated March 6, 2012 between Hod, LLC and Sugar Camp Energy, LLC
10.31**		First Amendment to Lease Agreement dated August 23, 2013 between HOD, LLC and Sugar Camp Energy, LLC
10.32**		Materials Handling and Storage Agreement by and among Raven Energy LLC of Louisiana, Foresight Energy LLC and Savatran LLC dated January 1, 2012 (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.33**		Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated September 10, 2009
10.34**		Amendment No. 1 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated January 11, 2010
10.35**		Amendment No. 2 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated October 4, 2010
10.36**		Amendment No. 3 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated January 13, 2011
10.37**		Amendment No. 4 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated February 2, 2012
10.38**		Amendment No. 5 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated August 21, 2012.
10.39**		Coal Mining Lease Agreement (5000 Foot Extension) between Independence Land Company, LLC and Williamson Energy, LLC dated March 13, 2006
10.40**		Amended and Restated Coal Mining Lease Agreement between WPP LLC and Williamson Energy, LLC dated August 14, 2006
10.41**		First Amendment to the Amended and Restated Coal Mining Lease Agreement between WPP LLC and Williamson Energy, LLC dated May 19, 2008
10.42**		Amendment to the Amended and Restated Coal Mining Lease Agreement between WPP LLC and Williamson Energy LLC, dated December 18, 2009

 

II-5

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Exhibit Number		Description of Documents
10.44**		Third Amendment to Amended and Restated Coal Mining Lease Agreement dated August 12, 2010 between WPP LLC and Williamson Energy, LLC
10.45**		Fourth Amendment to Amended and Restated Coal Mining Lease Agreement dated June 30, 2011 but effective April 1, 2011 between WPP LLC and Williamson Energy, LLC
10.46		Partial Release of Leased Premises from Amended and Restated Coal Mining Lease Agreement dated June 30, 2011 between WPP LLC and Williamson Energy, LLC
10.47**		Fifth Amendment to Amended and Restated Coal Mining Lease Agreement dated March 20, 2013 but effective March 1, 2013 between WPP LLC and Williamson Energy, LLC
10.48**		Partial Release of Leased Premises from Amended and Restated Coal Mining Lease Agreement dated March 20, 2013 but effective March 1, 2013 between WPP LLC and Williamson Energy, LLC
10.49**		Corrective Partial Release of Leased Premises from Amended and Restated Coal Mining Lease Agreement dated April 5, 2013 but effective March 1, 2013 between WPP LLC and Williamson Energy, LLC
10.50**		Lease (Rail Load Out Lease) dated May 1, 2005 between Steelhead Development Company, LLC and Williamson Energy, LLC
10.51**		Coal Mining Lease dated August 12, 2010 between Ruger Coal Company, LLC and Sugar Camp Energy, LLC
10.52**		First Amendment to Coal Mining Lease between Ruger Coal Company, LLC and Sugar Camp Energy LLC dated November 4, 2011
10.53		Second Amendment to Coal Mining Lease between Ruger Coal Company, LLC and Sugar Camp Energy LLC dated July 24, 2012
10.54**		Coal Mining Lease and Sublease dated August 12, 2010 from Colt LLC to Williamson Energy, LLC
10.55**		First Amendment to Coal Mining Lease and Sublease Agreement between Colt, LLC and Williamson Energy, LLC dated June 30, 2011 but effective April 1, 2011
10.56**		Second Amendment to Coal Mining Lease and Sublease Agreement between Colt LLC and Williamson Energy LLC dated February 13, 2013 but effective December 31, 2012
10.57**		Third Amendment to Coal Mining Lease and Sublease Agreement between Colt, LLC and Williamson Energy, LLC dated March 20, 2013 but effective March 1, 2013
10.58**		Partial Release of Premises from Coal Mining Lease and Sublease between Colt, LLC and Williamson Energy, LLC, dated March 20, 2013 but effective March 1, 2013
10.59**		Overriding Royalty Agreement dated August 12, 2010 between Ruger Coal Company LLC and Sugar Camp Energy, LLC
10.61**		Coal Mining Lease (For “Reserve 1” and “Reserve 3”) dated August 12, 2010 between Colt LLC and Hillsboro Energy LLC
10.62**		First Amendment to Coal Mining Lease (For “Reserve 1” and “Reserve 3”) dated February 13, 2013 but effective December 31, 2013 between Colt LLC and Hillsboro Energy LLC
10.63**		Coal Mining Lease (For “Reserve 2”) dated August 12, 2010 between Colt LLC and Hillsboro Energy LLC

 

II-6

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Exhibit Number		Description of Documents
10.64**		First Amendment to Coal Mining Lease (For “Reserve 2”) dated August 21, 2012 between Colt LLC and Hillsboro Energy LLC
10.65		Second Amendment to Coal Mining Lease (For “Reserve 2”) dated February 13, 2013 between Colt LLC and Hillsboro Energy LLC
10.66**		Throughput Agreement dated August 23, 2013 between Hillsboro Energy LLC and Hillsboro Transport LLC
10.68		Master Fuel Purchase and Sales Agreement between Williamson Energy LLC and The Dayton Power and Light Company dated August 16, 2007 and that Transaction Confirmation ID No. 507002 having a Transaction Date of October 2, 2007, as amended by Amendment One dated August 26, 2010 and Amendment Two dated January 2, 2013 (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.69		Amendment and Restatement of the Short Phantom Equity Agreement dated December 21, 2012 among Foresight Energy Services LLC, Drexel Short, Foresight Management, LLC and Foresight Reserves, L.P.
21.1**		List of Subsidiaries of Foresight Energy LP
23.1		Consent of Independent Registered Public Accounting Firm for Foresight Energy LP
23.2		Consent of Independent Registered Public Accounting Firm for Foresight Energy LLC
23.3		Consent of Weir International, Inc.
23.4*		Consent of Cahill Gordon & Reindel LLP (included in Exhibit 5.1)
23.5*		Consent of Vinson & Elkins L.L.P. (included in Exhibit 8.1)
23.6**		Consent of Wood Mackenzie Limited
24.1**		Powers of Attorney
24.2**		Powers of Attorney
99.1**		Amendment No. 2 to the Registration Statement on Form S-1 of Foresight Energy LP f/k/a Foresight Energy Partners LP, previously submitted to the Securities and Exchange Commission via the confidential email system on August 3, 2012 (including all exhibits filed with such amendment)
99.2**		Amendment No. 3 to the Registration Statement on Form S-1 of Foresight Energy LP f/k/a Foresight Energy Partners LP, previously submitted to the Securities and Exchange Commission via the confidential email system on September 11, 2012 (including all exhibits filed with such amendment)

 

*	to be filed by amendment

**	previously filed

 

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Item 17. Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act, and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes:

(i) That for purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4), or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(ii) That for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with registrant or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to registrant or its subsidiaries for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

 

II-8

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, hereunto duly authorized, in the City of New York, State of New York, on April 24, 2014.

 

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities indicated, which are with the general partner of the registrant, on:

 

Name and Signatures		Title
/s/    Michael J. Beyer         Michael J. Beyer		Director and Chief Executive Officer and President (Principal Executive Officer)
* Oscar A. Martinez		Senior Vice President—Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
* Christopher Cline		Chairman of the Board of Directors
* John F. Dickinson		Director
* E. Bartow Jones		Director

 

*By:		/s/ Michael J. Beyer
		Michael J. Beyer, Attorney-in-fact

 

II-9

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INDEX TO EXHIBITS

 

Exhibit Number		Description of Documents
1.1*		Form of Underwriting Agreement
3.1**		Certificate of Limited Partnership of Foresight Energy LP (f/k/a Foresight Energy Partners LP)
3.2*		Form of Partnership Agreement of Foresight Energy LP (included as Appendix A to the Prospectus)
4.1*		Form of Registration Rights Agreement
4.2**		Indenture, dated as of August 23, 2013, by and among Foresight Energy LLC, Foresight Energy Finance Corporation, the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee
5.1*		Opinion of Cahill Gordon & Reindel LLP as to the legality of the securities being registered
8.1*		Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*		Form of Contribution, Conveyance and Assumption Agreement
10.3*		Form of Long-Term Incentive Plan
10.4**		Amendment Agreement (including the Amended and Restated Credit Agreement), dated as of August 23, 2013 by and among Foresight Energy LLC, certain subsidiaries of Foresight Energy LLC, Citibank, N.A., as administrative agent, and the lenders party thereto
10.5**		Credit Agreement, dated as of January 5, 2010, by and among Sugar Camp Energy LLC, as the borrower, Foresight Energy LLC, as a guarantor, Crédit Agricole Corporate and Investment Bank, as Administrative Agent (formerly known as Calyon New York Branch) and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent (formerly known as CALYON Deutschland Niederlassung Einer Französischen Societé Anonyme) (the “Sugar Camp Credit Agreement”)
10.6**		First Amendment to the Sugar Camp Credit Agreement dated as of February 5, 2010, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.7**		Second Amendment to the Sugar Camp Credit Agreement and First Amendment to Foresight Guarantee, dated as of August 4, 2010, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.8**		Third Amendment to the Sugar Camp Credit Agreement, dated as of September 24, 2010, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.9**		Fourth Amendment to the Sugar Camp Credit Agreement, dated as of May 27, 2011, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment
		Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent

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Exhibit Number		Description of Documents
10.10**		Fifth Amendment to the Sugar Camp Credit Agreement and First Amendment to Guaranty, dated as of March 8, 2012, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.11**		Sixth Amendment to the Sugar Camp Credit Agreement and Second Amendment to Guaranty, dated as of August 23, 2013, by and among Sugar Camp Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (formerly known as Calyon Deutschland Niederlassung Einer Französischen Societé Anonyme), as Hermes Agent
10.12**		Guaranty of the Sugar Camp Credit Agreement by Foresight Energy LLC, as guarantor, in favor of Crédit Agricole Corporate and Investment Bank, as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent dated May 27, 2011
10.13**		Credit Agreement, dated as of May 14, 2010, by and among Hillsboro Energy LLC, as the borrower, Foresight Energy LLC, as a guarantor, Credit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent (the “Hillsboro Credit Agreement”)
10.14**		First Amendment to the Hillsboro Credit Agreement, dated as of June 17, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.15**		Second Amendment to the Hillsboro Credit Agreement and First Amendment to Foresight Guaranty dated as of August 4, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.16**		Third Amendment to the Hillsboro Credit Agreement dated as of September 24, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.17**		Fourth Amendment to the Hillsboro Credit Agreement dated as of May 27, 2011, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.18**		Fifth Amendment to the Hillsboro Credit Agreement and First Amendment to Guaranty dated as of March 8, 2012, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent

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Exhibit Number		Description of Documents
10.19**		Sixth Amendment to the Hillsboro Credit Agreement and Second Amendment to Guaranty dated as of August 16, 2013, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly known as Calyon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent
10.20**		Guaranty of the Hillsboro Credit Agreement by Foresight Energy LLC, as guarantor, in favor of Crédit Agricole Corporate and Investment Bank (formerly known as Caylon New York Branch), as Administrative Agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent dated May 27, 2011
10.21**		Illinois Coal Lease dated July 1, 2002 from the United States of America, as Lessor acting through its legal agent, the Tennessee Valley Authority, (“TVA”), to Illinois Fuel Company, LLC, as Lessee (“Illinois Coal Lease”), which was assigned to Ruger Coal Company, LLC, with such assignment and transfer being consented to by TVA, by an Assignment and Assumption Agreement effective on August 4, 2009 (“Assignment and Assumption Agreement”) by and among TVA, Illinois Fuel Company, LLC and Ruger Coal Company, LLC wherein TVA consented to “the mining of the Lease reserves by Sugar Camp Energy, LLC, and with Ruger Coal Company, LLC agreeing that Sugar Camp Energy, LLC can mine the Illinois Coal Lease reserves and consenting to the mining of such reserves in a Consent dated effective on January 22, 2010 between Ruger Coal Company, LLC and Sugar Camp Energy, LLC (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.22**		Amendment One to Illinois Coal Lease dated April 10, 2012 between United States of America, as Lessor acting through its legal agent, the Tennessee Valley Authority (“TVA”), and Illinois Fuel Company LLC, Lessee (as assigned to Ruger Coal Company LLC under that Assignment and Assumption Agreement dated August 4, 2009 by and among TVA, Illinois Fuel Company, LLC, Assignor and Ruger Coal Company LLC, Assignee, and expressly granting Sugar Camp Energy, LLC the right to mine the reserves subject to the lease) (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.23**		Amendment Two to Illinois Coal Lease effective as of August 30, 2012 by and between United States of America, as Lessor acting through its legal agent, the Tennessee Valley Authority (“TVA”), and Illinois Fuel Company LLC, Lessee (as assigned to Ruger Coal Company LLC under that Assignment and Assumption Agreement dated August 4, 2009 by and among TVA, Illinois Fuel Company, LLC, Assignor and Ruger Coal Company LLC, Assignee, and expressly granting Sugar Camp Energy, LLC the right to mine the reserves subject to the lease) (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.24**		Master Lease Agreement between PNC Equipment Finance, LLC, as Lessor and Foresight Energy Services LLC, as Lessee dated October 31, 2013, that Master Lease Guaranty delivered by Foresight Energy LLC in favor of PNC Equipment Finance, LLC in connection with Master Lease Agreement, and that Real Property Waiver for the benefit of PNC Equipment Finance, LLC by Williamson Energy LLC, Sugar Camp Energy LLC and Hillsboro Energy LLC dated October 31, 2013
10.25**		Master Lease Agreement dated March 30, 2012, among BB&T Equipment Finance Corporation (“BB&T”), as Lessor, Hillsboro Energy LLC, Sugar Camp Energy, LLC and Williamson Energy, LLC, collectively as Lessee, and Foresight Energy LLC, as guarantor
10.26**		Coal Mining Lease between RGGS Land & Mineral LTD., L.P. and Sugar Camp Energy, LLC dated July 29, 2005 (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)

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Exhibit Number		Description of Documents
10.27**		First Amendment to Coal Mining Lease between RGGS Land & Minerals, LTD., L.P. and Sugar Camp Energy LLC dated August 11, 2008
10.28**		Amendment dated December 21, 2010 to Coal Mining Lease between RGGS Land & Minerals, LTD., L.P. and Sugar Camp Energy, LLC
10.29**		Surface Sublease between Sugar Camp Energy, LLC and Hod, LLC dated March 6, 2012
10.30**		Lease Agreement dated March 6, 2012 between Hod, LLC and Sugar Camp Energy, LLC
10.31**		First Amendment to Lease Agreement dated August 23, 2013 between HOD, LLC and Sugar Camp Energy, LLC
10.32**		Materials Handling and Storage Agreement by and among Raven Energy LLC of Louisiana, Foresight Energy LLC and Savatran LLC dated January 1, 2012 (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.33**		Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated September 10, 2009
10.34**		Amendment No. 1 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated January 11, 2010
10.35**		Amendment No. 2 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated October 4, 2010
10.36**		Amendment No. 3 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated January 13, 2011
10.37**		Amendment No. 4 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated February 2, 2012
10.38**		Amendment No. 5 to the Coal Mining Lease and Sublease Agreement between WPP LLC and Hillsboro Energy LLC dated August 21, 2012.
10.39**		Coal Mining Lease Agreement (5000 Foot Extension) between Independence Land Company, LLC and Williamson Energy, LLC dated March 13, 2006
10.40**		Amended and Restated Coal Mining Lease Agreement between WPP LLC and Williamson Energy, LLC dated August 14, 2006
10.41**		First Amendment to the Amended and Restated Coal Mining Lease Agreement between WPP LLC and Williamson Energy, LLC dated May 19, 2008
10.42**		Amendment to the Amended and Restated Coal Mining Lease Agreement between WPP LLC and Williamson Energy LLC, dated December 18, 2009
10.44**		Third Amendment to Amended and Restated Coal Mining Lease Agreement dated August 12, 2010 between WPP LLC and Williamson Energy, LLC
10.45**		Fourth Amendment to Amended and Restated Coal Mining Lease Agreement dated June 30, 2011 but effective April 1, 2011 between WPP LLC and Williamson Energy, LLC
10.46		Partial Release of Leased Premises from Amended and Restated Coal Mining Lease Agreement dated June 30, 2011 between WPP LLC and Williamson Energy, LLC
10.47**		Fifth Amendment to Amended and Restated Coal Mining Lease Agreement dated March 20, 2013 but effective March 1, 2013 between WPP LLC and Williamson Energy, LLC
10.48**		Partial Release of Leased Premises from Amended and Restated Coal Mining Lease Agreement dated March 20, 2013 but effective March 1, 2013 between WPP LLC and Williamson Energy, LLC

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Exhibit Number		Description of Documents
10.49**		Corrective Partial Release of Leased Premises from Amended and Restated Coal Mining Lease Agreement dated April 5, 2013 but effective March 1, 2013 between WPP LLC and Williamson Energy, LLC
10.50**		Lease (Rail Load Out Lease) dated May 1, 2005 between Steelhead Development Company, LLC and Williamson Energy, LLC
10.51**		Coal Mining Lease dated August 12, 2010 between Ruger Coal Company, LLC and Sugar Camp Energy, LLC
10.52**		First Amendment to Coal Mining Lease between Ruger Coal Company, LLC and Sugar Camp Energy LLC dated November 4, 2011
10.53		Second Amendment to Coal Mining Lease between Ruger Coal Company, LLC and Sugar Camp Energy LLC dated July 24, 2012
10.54**		Coal Mining Lease and Sublease dated August 12, 2010 from Colt LLC to Williamson Energy, LLC
10.55**		First Amendment to Coal Mining Lease and Sublease Agreement between Colt, LLC and Williamson Energy, LLC dated June 30, 2011 but effective April 1, 2011
10.56**		Second Amendment to Coal Mining Lease and Sublease Agreement between Colt LLC and Williamson Energy LLC dated February 13, 2013 but effective December 31, 2012
10.57**		Third Amendment to Coal Mining Lease and Sublease Agreement between Colt, LLC and Williamson Energy, LLC dated March 20, 2013 but effective March 1, 2013
10.58**		Partial Release of Premises from Coal Mining Lease and Sublease between Colt, LLC and Williamson Energy, LLC, dated March 20, 2013 but effective March 1, 2013
10.59**		Overriding Royalty Agreement dated August 12, 2010 between Ruger Coal Company LLC and Sugar Camp Energy, LLC
10.61**		Coal Mining Lease (For “Reserve 1” and “Reserve 3”) dated August 12, 2010 between Colt LLC and Hillsboro Energy LLC
10.62**		First Amendment to Coal Mining Lease (For “Reserve 1” and “Reserve 3”) dated February 13, 2013 but effective December 31, 2013 between Colt LLC and Hillsboro Energy LLC
10.63**		Coal Mining Lease (For “Reserve 2”) dated August 12, 2010 between Colt LLC and Hillsboro Energy LLC
10.64**		First Amendment to Coal Mining Lease (For “Reserve 2”) dated August 21, 2012 between Colt LLC and Hillsboro Energy LLC
10.65		Second Amendment to Coal Mining Lease (For “Reserve 2”) dated February 13, 2013 between Colt LLC and Hillsboro Energy LLC
10.66**		Throughput Agreement dated August 23, 2013 between Hillsboro Energy LLC and Hillsboro Transport LLC
10.68		Master Fuel Purchase and Sales Agreement between Williamson Energy LLC and The Dayton Power and Light Company dated August 16, 2007 and that Transaction Confirmation ID No. 507002 having a Transaction Date of October 2, 2007, as amended by Amendment One dated August 26, 2010 and Amendment Two dated January 2, 2013 (with certain confidential information omitted, which omitted information is the subject of a confidential treatment request and has been filed separately with the Securities and Exchange Commission)
10.69		Amendment and Restatement of the Short Phantom Equity Agreement dated December 21, 2012 among Foresight Energy Services LLC, Drexel Short, Foresight Management, LLC and Foresight Reserves, L.P.
21.1**		List of Subsidiaries of Foresight Energy LP
23.1		Consent of Independent Registered Public Accounting Firm for Foresight Energy Partners LP

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Exhibit Number		Description of Documents
23.2		Consent of Independent Registered Public Accounting Firm for Foresight Energy LLC
23.3		Consent of Weir International, Inc.
23.4*		Consent of Cahill Gordon & Reindel LLP (included in Exhibit 5.1)
23.5*		Consent of Vinson & Elkins L.L.P. (included in Exhibit 8.1)
23.6**		Consent of Wood Mackenzie Limited
24.1**		Powers of Attorney
24.2**		Powers of Attorney
99.1**		Amendment No. 2 to the Registration Statement on Form S-1 of Foresight Energy LP f/k/a Foresight Energy Partners LP, previously submitted to the Securities and Exchange Commission via the confidential email system on August 3, 2012 (including all exhibits filed with such amendment)
99.2**		Amendment No. 3 to the Registration Statement on Form S-1 of Foresight Energy LP f/k/a Foresight Energy Partners LP, previously submitted to the Securities and Exchange Commission via the confidential email system on September 11, 2012 (including all exhibits filed with such amendment)

 

*	to be filed by amendment

**	previously filed