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As filed with the Securities and Exchange Commission on February 2, 2012

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

FORESIGHT ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		1220
(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. 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		Joshua Davidson, Esq. Douglass M. Rayburn, Esq. Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 Telephone: (713) 229-1234 Fax: (713) 229-2727		Jason R. Lehner, Esq. Shearman & Sterling LLP 599 Lexington Avenue New York, New York 10022 Telephone: (212) 848-4000 Fax: (646) 848-7974

 

 

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
Common units representing limited partner interests		$100,000,000		$11,460

(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.

 

 

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 FEBRUARY 2, 2012

PRELIMINARY PROSPECTUS

 

Common Units

Representing Limited Partner Interests

FORESIGHT ENERGY PARTNERS LP

 

 

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 will apply 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.

 

 

Investing in our common units involves risks. See “Risk Factors” beginning on page 17.

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.

 

•

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

 

•

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

 

•

We could be negatively impacted by the competitiveness of the global markets in which we compete and declines in the market demand for coal.

 

•

Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations 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 fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

 

•

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

 

•

Unitholders will experience immediate and substantial dilution of $         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 Partners LP (before expenses)		$				$

 

(1)

Excludes a structuring fee of     % of the gross proceeds of this offering payable to                         . Please see “Underwriting.”

The underwriters expect to deliver the common units to purchasers on or about                 , 2012.

 

 

                    , 2012

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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			17
USE OF PROCEEDS			50
DILUTION			51
CAPITALIZATION			52
DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			53
HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS			65
SELECTED HISTORICAL FINANCIAL INFORMATION			78
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			81
BUSINESS			97
THE COAL INDUSTRY			114
ENVIRONMENTAL AND OTHER REGULATORY MATTERS			130
MANAGEMENT			136
COMPENSATION DISCUSSION AND ANALYSIS			139
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			144
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			151
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			156
DESCRIPTION OF INDEBTEDNESS			157
DESCRIPTION OF COMMON UNITS			162
THE PARTNERSHIP AGREEMENT			164
UNITS ELIGIBLE FOR FUTURE SALE			178
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			180
INVESTMENT IN FORESIGHT ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS			198
UNDERWRITING			199
LEGAL MATTERS			205
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM			206
EXPERTS—COAL RESERVES			207
WHERE YOU CAN FIND ADDITIONAL INFORMATION			208
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. 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, 2010, all of our proven and probable coal reserves were assigned reserves, which are coal reserves that have been designated for mining by a specific operation.

The information appearing in this prospectus concerning estimates of our proven and probable coal reserves was prepared by Weir International, Inc. as of January 1, 2010. 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.

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, Hanou Energy Consulting, Ventyx and Bloomberg L.P., none of whom are affiliated with us. Wood Mackenzie has consented to being named in this prospectus. While we believe that these sources of information are reliable, neither we nor the underwriters have independently verified such information, and neither we nor the underwriters make any representation as to the accuracy or completeness of such information.

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.

 

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While we believe our third party sources are reliable, we have not independently verified market and industry data provided by third parties. Accordingly, we cannot assure you that any of these assumptions are accurate or that our assumptions correctly reflect our position in our industry.

While we are not aware of any misstatements regarding any industry data presented in this prospectus, 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, or 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;

 

•

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;

 

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•

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;

 

•

Weather conditions or catastrophic weather-related damage;

 

•

Earthquakes and other natural disasters;

 

•

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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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. Additional risks and uncertainties not presently known to us, or that we currently deem immaterial, may also impair our business operations. We cannot assure you that any of the events discussed in this prospectus will not occur. If they do, our business, financial condition, results of operation and cash available for distribution could be materially and adversely affected. 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 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. For the twelve months ended December 31, 2011, our aggregate distributions would have been $         per unit, significantly less than the $         per unit that we project that we will be able to pay for each of the six months ending December 31, 2012 and the twelve months ending December 31, 2013.

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 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. For the year ended December 31, 2011, on a pro forma basis, our annual distribution would have been $         per unit, significantly less than the $         per unit distribution we project that we will to be able to pay for the six months ending December 31, 2012 and the twelve months ending December 31, 2013. Our expected aggregate annual distribution amount for each of the forecast periods is based on the price assumptions set forth in “Distribution Policy and Restrictions on Distributions — Significant Forecast Assumptions.” If our price assumptions prove to be inaccurate, our actual distribution for the six months ending December 31, 2012 and the twelve months ending December 31, 2013 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all during those periods.

In addition, while the subordinated units (and any PIK common units) will not receive cash distributions during the PIK period, the distribution of additional subordinated units (or PIK common units, if applicable) may substantially increase the number of units that will be outstanding after the PIK period and, after the PIK period, the amount of cash required on a quarterly and annual basis to pay the full minimum quarterly distribution on all units. 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 price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

 

•

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

 

•

the price and availability of alternative fuels;

 

•

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

 

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•

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

 

•

prevailing economic and market conditions;

 

•

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

 

•

the effects of new or expanded health and safety regulations;

 

•

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;

 

•

changes in tax laws; and

 

•

force majeure.

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

 

•

the level of capital expenditures we make;

 

•

the cost of acquisitions;

 

•

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; and

 

•

the amount of cash reserves established by our general partner.

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

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

The indenture governing our Senior Notes and our Senior Secured Credit Facility prohibit us from making distributions to unitholders if any default or event of default (as defined in the each agreement) exists. In addition, both the agreements contain covenants limiting our ability to pay distributions to unitholders to amounts that we refer to as each agreement’s “restricted payment basket.” The restricted payment basket of the Senior Secured Credit Facility consists of, in pertinent part, aggregate net proceeds of capital contributions and certain other investment returns plus 50% of consolidated net income (or, less 50% of consolidated net loss) accrued on a cumulative basis. The restricted payment basket of the indenture consists of, in pertinent part, aggregate net proceeds of capital contributions and certain other investment returns plus 50% of consolidated net income (or, less 100% of consolidated net loss) accrued on a cumulative basis. Accordingly, non-cash losses, such as an impairment of the value of our properties, will reduce the respective restricted payment basket. As of December 31, 2011, our restricted payments basket under the Senior Secured Credit Facility and indenture were equal to approximately $                 million and $                 million, respectively. The aggregate minimum quarterly distribution on our common units will be $                 million. Our Senior Notes mature in August 2017 and our Senior Secured Credit Facility matures in August 2014. If the amount in each restricted payment basket in respect of any quarter is materially reduced or does not increase at a sufficient rate to cover our distribution rate, we may be restricted in paying all or part of the minimum quarterly distribution to our unitholders. See “Description of Indebtedness.”

 

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The assumptions underlying our forecast of cash available for distribution included in “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 record 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 record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.

We are dependent on our Williamson complex and suspension of production at that complex may materially adversely affect our business.

We are in the process of developing one longwall system at each of Sugar Camp and Hillsboro. Until these longwalls are operational, we are dependent upon the continuous operation of Williamson for substantially all of our revenues. If Williamson were to cease production for any reason, it would have a material adverse effect on our results of operations, business and financial position, as well as our ability to pay distributions to our unitholders.

The Sugar Camp and Hillsboro longwall systems are still under development, may not achieve anticipated productive capacity, may experience unanticipated costs or may be delayed or not completed at all.

The Sugar Camp and Hillsboro longwall systems are still under development. The development of a longwall system is a complex and challenging process that may take longer and cost more than estimated, or not be completed at all. In addition, anticipated productive capacity may not be achieved. We may encounter additional 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. Once production begins, if any of our longwalls were to cease production for any reason, it would have a material adverse effect on our results of operations, business and financial position, as well as our ability to pay distributions to our unitholders.

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

 

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the governmental permits that we need to continue developing our proven and probable coal reserves. The inability to conduct mining operations 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.

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

Our business is capital intensive due to construction of new mines and infrastructure and maintenance of existing operations. 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 new mines has been spent, we must continue to invest capital to maintain or to increase our production. As of September 30, 2011, we expect the longwalls currently in development at each of Sugar Camp and Hillsboro will require approximately an additional $94.4 million to achieve anticipated productive capacity, and an additional $17.7 million will be required to complete our transportation projects. 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.

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 depend upon many factors, including:

 

•

The market price for coal;

 

•

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

 

•

Competition from other coal suppliers;

 

•

Advances in power technologies;

 

•

The worldwide demand for electricity;

 

•

The impact of worldwide energy conservation measures;

 

•

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

 

•

The cost of using, and the availability of, alternative 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;

 

•

Weather conditions;

 

•

The efficiency of our mines;

 

•

The pricing terms contained in our long-term contracts;

 

•

Cancellation or renegotiation of contracts;

 

•

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

 

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•

Transportation costs;

 

•

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

 

•

The cost and availability of our contract miners;

 

•

The availability of skilled employees; and

 

•

Work stoppages or other labor difficulties.

Substantial or extended declines in the price that we receive for our coal or increases in the costs of mining or transporting our coal could have a material adverse effect on our operating results and our ability to generate the cash flows we require to invest in our operations, satisfy our obligations and pay distributions to unitholders.

We face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

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 incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

 

•

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

 

•

Future coal prices, operating costs and capital expenditures;

 

•

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

 

•

Future mining technology improvements;

 

•

The effects of regulation by governmental agencies;

 

•

Ability to obtain, maintain and renew all required permits;

 

•

Employee health and safety; and

 

•

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

As a result, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our 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 ability to pay distributions to our unitholders.

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

We use equipment in our coal mining and transportation operations such as continuous miners, conveyors, shuttle cars, roof bolters, shearers, shield trains and trucks. 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

 

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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 and petroleum-based fuels in the mining process. If the prices of steel, petroleum products or other materials continue to increase 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 will increase, which could materially and adversely impact our profitability.

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

We are or may be 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.”

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, the 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 inflation or deflation, and changes in the laws regulating the timing, production, sale or use of coal. Moreover, a limited number of these agreements permit the customer to terminate the contract if transportation costs, which are typically borne by the customer, increase substantially or, in the event of changes in regulations affecting the coal industry, that increase the price of coal beyond specified amounts.

 

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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. We occasionally enter into hedge or other arrangements to offset the cost variability underlying these forward sales contracts. 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.

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

We derived approximately 64% and 47% of our total coal revenues from our five largest customers for the year ended December 31, 2010 and the first three quarters of 2011, respectively. Negotiations to extend existing agreements or enter into long-term agreements with those and other customers may not be successful, and those 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.

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

In an economic downturn, certain customers have sought and others may seek to delay shipments or request deferrals under existing agreements. For example, we are currently engaged in a lawsuit with the Tennessee Valley Authority relating to their failure to accept and pay for coal pursuant to a contract with us entered into in September 2008. See “Business—Legal Proceedings and Liabilities.” 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.

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

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

 

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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.

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, is not 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 a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.

At December 31, 2011, our total indebtedness was approximately $897.4 million, including our Senior Notes, Senior Secured Credit Facility and longwall financings. We had unused capacity of $76.0 million under our Senior Secured Credit Facility and $6.8 million under our longwall financings. 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.

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

 

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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 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. At September 30, 2011, we recorded total asset retirement obligations of approximately $23.0 million. Our estimates for this future liability are subject to change based on new or amendments to existing applicable laws and regulation, the nature of ongoing operations and technological innovations. Although we accrue for future costs, 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. 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 in the United States and our obligations under coal leases in the United States. 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. 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 and/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

 

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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. Also, in any such case, the investigation and resolution of title issues would divert management’s time from our business and our results of operations could be adversely affected. Additionally, if we lose any leasehold interests relating to any of our preparation plants, we may need to find an alternative location to process our coal and load it for delivery to customers, which could result in significant unanticipated costs.

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. Failure to meet those requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself. 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 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 from third parties. Each of those leases requires that minimum royalties be paid regardless of production levels from the leased reserves. See “Business—Coal Reserves.” 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 attendant 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 or change in the Illinois state severance tax or any county tax could disproportionately impact us relative to our competitors that are more geographically diverse.

We operate our mines with a limited work force. Our ability to operate our mines efficiently and profitably could be impaired if we lose key personnel or fail to continue to attract qualified contractors.

We manage our business with a number of key personnel at each location, including key contractors. In addition, 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 personnel and contractors. We cannot be certain that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel and contractors in the future. Failure to retain or attract key personnel 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.

 

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We operate our mines with a work force that is contracted through our operators. While none of our contractors’ employees are members of unions, our work force may not remain non-union in the future.

None of our contractors’ employees are represented under collective bargaining agreements. However, all of our work force may not remain non-union in the future, and proposed legislation such as the Employee Free Choice Act, 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 operations.

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, preferably with at least one year of experience, and proficiency in multiple mining tasks, including mining equipment maintenance. Any shortage of skilled mining labor reduces the productivity of our 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 miners for all of our coal production and transportation companies to deliver our coal. If any of the contract mining or transportation companies with whom we contract went 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 adversely affected. Our contract miners and contract transportation 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 third-party; the price and financial viability of the third-party; our willingness to reimburse temporary cost increases experienced by the third-party; our ability to pass on 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.

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

Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of our executive officers and other key employees. The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a replacement. A limited number of persons exist with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled personnel with coal industry experience. Competition for these persons in the coal industry is intense and we may not be able to successfully recruit, train or retain qualified managerial personnel. As a public company, our future success also will depend on our ability to hire and retain management with public company experience. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

 

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

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

 

•

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

 

•

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

 

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

 

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Industrial accidents;

 

•

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

 

•

Environmental hazards;

 

•

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

 

•

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

 

•

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

 

•

Accidental or unexpected mine water inflows;

 

•

Delays in moving our longwall equipment;

 

•

Railroad derailments;

 

•

River flooding;

 

•

Interruption or loss of power, fuel, or parts;

 

•

Increased or unexpected reclamation costs;

 

•

Equipment availability, replacement or repair costs; and

 

•

Mining and processing equipment failures and unexpected maintenance problems;

These risks, conditions and events could result in damage to, or destruction of value of, our coal properties, our coal production or transportation facilities, personal injury or death, environmental damage to our properties or the properties of others, delays or prohibitions on mining our coal or in the transportation of coal, monetary losses and potential legal liability, and 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 obligations. In particular, underground mining and related processing activities present inherent risks of injury to persons and damage to equipment. Our insurance policies only provide limited coverage for some of these risks and will not fully cover these risks. Significant mine accidents could occur, potentially resulting in a mine shutdown, and could have a substantial 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 impact on our business and operating results.

 

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Any change in consumption patterns by generators away from the use of coal could affect our ability to sell the coal we produce.

Coal powers 42% of the world’s electricity needs and the domestic electricity generation industry accounts for approximately 90% of domestic 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, and 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. For example, the relatively recent low price of natural gas 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 in generating a certain percentage of 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.

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 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 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.

Coal producers depend upon rail, barge, truck, overland conveyor, ocean-going vessels and port facilities to deliver coal to customers. Disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays, lack of rail or port capacity or other events could temporarily impair our ability to supply coal to customers and thus could adversely affect our results of operations, cash flows and financial condition.

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

 

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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.

Significant increases in transportation costs could make our coal less competitive when compared to alternative 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 alternative fuels such as natural gas, or could make our coal production 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 is 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. For example, in the second quarter of 2011 heavy rain reduced the ability of the railroads and barges our customers used to transport coal from our mines. 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, our business could be materially and adversely affected.

As our existing coal supply agreements expire, our revenues and operating profits could be negatively impacted if we are unable to extend existing agreements or enter into new agreements due to competition, changing coal purchasing patterns or other variables.

As our coal supply agreements expire, we will compete with other coal suppliers to renew these agreements or to obtain new sales. To the extent our other mines in operation do not have contracts for coal or if we cannot renew these coal supply agreements with our customers 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. The global recession experienced in 2008 and 2009 resulted in decreased

 

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demand worldwide for electricity. Any decrease in demand may cause our customers to delay negotiations for new contracts and/or request lower pricing terms. 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 these changes prohibit utilities from burning the contracted coal. To the degree that we operate outside of long-term contracts, our revenues are subject to pricing in the spot market that can be significantly more volatile than the pricing structure negotiated through a long-term coal supply agreement. 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 if spot market pricing for coal is unfavorable.

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 near 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 and Europe could reduce our revenues and thus adversely affect our results of operations. The recent financial and sovereign debt crises in North America and Europe have led to a global economic slowdown, with the economies of those regions showing significant signs of weakness resulting in greater volatility in the United States economy and in the global capital and credit markets. These markets have been experiencing disruption, 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 and high unemployment rates. Instability in consumer confidence and increased unemployment have increased concerns of prolonged economic weakness. Furthermore, these developments may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. We are unable to predict the duration and severity of the current crisis or determine the specific impact of the current economic conditions on our business at this time, but 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.

Risks Related to Environmental, Health, Safety and Other Regulation

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:

 

•

Surface subsidence from underground mining;

 

•

Employee health and safety;

 

•

Permits and other licensing requirements;

 

•

Remediation of contaminated soil, surface water and groundwater;

 

•

Air emissions;

 

•

Water quality standards;

 

•

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

 

•

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

 

•

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

 

•

Reclamation and restoration of mining properties after mining is completed;

 

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•

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 and intend to do so at 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, can substantially increase the cost of coal mining or have a material adverse effect on our results of operations, cash flows and financial condition.

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. For example, the principal operating permit for Hillsboro, issued in 2009 under SMCRA by the IDNR, is currently being challenged by an environmental organization and several individuals which, if successful, could result in delay, modification or cessation of activities at the mine site, any of which could materially and adversely affect our production, cash flow and profitability. See “Business—Legal Proceedings and Liabilities.”

New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would

 

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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. See “Environmental and Other Regulatory Matters.”

Extensive governmental regulation pertaining to employee 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 segment of 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 and/or regulations and orders may be adopted that may materially and adversely affect our mining operations. For example, in response to underground mine accidents 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.

There is also a possibility that new federal legislation pending in Congress known as the Supplemental Mine Improvement and New Emergency Response Act, or S-MINER Act, could be enacted. 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, it could harm our future operating results. 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, not to exceed 4.4% of the gross sales price. For the nine month period ended September 30, 2011, we recognized $5.2 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 harmed. 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 materially and adversely affect our operating results.

 

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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 as pursuant to permitting authority to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend our obligations to deliver coal under these 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 it is available, to fulfill these obligations, incur capital expenditures to re-open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or terminate customers’ contracts. Any of these actions could have a material adverse effect on our business and results of operations.

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, many of the locations that we own or operate were used for coal mining and/or involved hazardous materials either before or after we were involved with these locations. We may be subject to claims under federal and state statutes and/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 own or operate currently, 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 at Macoupin 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 adversely affect us.

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-fueled power plants produce carbon dioxide and other GHG as a by-product of their operations. GHG emissions have received increasing scrutiny from local, state, federal and international government bodies. Future regulation of GHG could occur pursuant to future United States treaty obligations or statutory or regulatory change. In addition, the EPA and other regulators are using existing laws, including the federal Clean Air Act, to seek to limit emissions of carbon dioxide and other GHG emissions, from major sources, including coal-fueled power plants. 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

 

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effect or may take effect before federal action. 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. 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 United States Supreme Court recently determined that such claims cannot be pursued under Federal law, plaintiffs may seek to proceed under state common law. 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.

Current and future international, federal, state, regional or local laws, regulations or court orders regulating GHG emissions and/or coal ash could require additional controls on coal-fueled power plants and industrial boilers and may cause some users of coal to close existing facilities, reduce construction of new facilities or switch from coal to alternative fuels. These ongoing and future developments may have a material adverse impact on the global supply and demand for coal, and as a result could materially adversely affect our results of operations, cash flows and financial condition. Even in the absence of future developments, increased awareness of, and any adverse publicity regarding, GHG emissions and coal ash use, storage or disposal could adversely affect our customers’ reputation and reduce demand for coal.

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

Following the offering, Foresight Reserves will own and control our general partner and will appoint all of the directors of our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, 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. Therefore, conflicts of interest may arise between Foresight Reserves and its affiliates, including our general partner, on the one hand, and 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, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

 

•

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

 

•

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

 

•

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 capital expenditure and whether a capital expenditure is classified as a maintenance and replacement capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Our partnership agreement does not set a limit on the amount of maintenance and replacement capital expenditures that our general partner may estimate. Please read “How We Make Distributions To Our Partners—Capital Expenditures” for a discussion on when a capital expenditure constitutes a maintenance and replacement capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash 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—Partnership Interests—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 subordinated units or the incentive distribution rights;

 

•

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

 

•

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

 

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•

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 currently holds substantial interests in other companies in the energy and natural resource sectors. We may compete directly with entities in which Foresight Reserves has 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.”

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 fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

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

Pursuant to our cash distribution policy, we expect that, following the PIK period, we will distribute a significant portion of our available cash to our partners 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.”

 

 

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We may issue additional units without unitholder approval, and expect to issue additional subordinated units, which will dilute existing unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interest that rank senior to the common units, that we may issue at any time without the approval of our unitholders. We expect to issue additional subordinated units to the holders of the subordinated units during the PIK period. In addition, if the subordinated units convert prior to the end of the PIK period, they will convert into PIK common units, which will be entitled to receive additional PIK common units in lieu of cash distributions. The issuance of additional common units or other equity interests of equal or senior rank 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, or, with respect to the subordinated units and any PIK common units, reinvestment of the cash we retain by paying distributions in kind, such issuances will be dilutive to the existing unitholders.

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

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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.”

 

 

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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 required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

•

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interest of our partnership;

 

•

provides that our general partner and its officers and directors will not be liable for monetary damages 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 our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

•

provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary 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, 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.”

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. The parent and 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, certain affiliates of our general partner, including The Cline Group and Riverstone, currently hold substantial interests in other companies in the coal mining business. For example, The Cline Group makes investments and purchases entities that acquire, own and operate coal mining businesses. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, affiliates of our general partner may compete with us for investment opportunities, and our affiliates of our general partner may own an interest in entities that compete with us.

 

 

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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.”

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

Our general partner has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal 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 which would have entitled the holder to an aggregate quarterly cash distribution in the prior quarter equal to the distributions to our general partner on the incentive distribution rights in the prior quarter. It is possible that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Please read “How We Make Distributions To Our Partners—Adjusted Operating Surplus—General Partner’s 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.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business 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 its members and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

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

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 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). Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

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 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 in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members 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.

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, but not the obligation, which it may assign to any of its affiliates or to us, 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 issuing additional common units and exercising its

 

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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 will own an aggregate of     % of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the PIK common and subordinated units), Foresight Reserves will own     % of our common units. For additional information about the limited call right, please read “The Partnership Agreement—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, unless conversion occurs prior to the end of the PIK period, in which case they would convert into PIK common units. All of the units that are issued to Foresight Reserves will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by Foresight Reserves or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to Foresight Reserves. 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, subject to certain limitations. 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.

Prior to making any distribution on the common units, 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. Our partnership agreement does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay distributions to our unitholders. Please read “Distribution Policy and Restrictions on Distributions” and “Certain Relationships and Related Party Transactions.”

 

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At any time after August 15, 2014, our general partner may amend certain agreements governing our indebtedness in a manner that terminates the PIK period.

At any time after August 15, 2014, our general partner may, in its sole discretion, redeem, retire, repurchase, or otherwise refinance the Senior Notes or otherwise amend the indenture or the Senior Secured Credit Facility, in each case in a manner that terminates our PIK period. Following the termination of the PIK period, distributions in respect of any outstanding subordinated units will be paid in cash (and any PIK common units will convert into an equal number of common units). Under our partnership agreement, such a decision will explicitly be deemed not to be a violation of the fiduciary duties that might otherwise be owed by our general partner to our unitholders.

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 representing an aggregate     % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

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

 

•

our quarterly distributions;

 

•

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

 

•

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

 

•

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

 

•

general economic conditions;

 

•

volatility in the capital and credit markets;

 

•

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

 

•

future sales of our common units; and

 

•

the other factors described in these “Risk Factors.”

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

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

 

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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.

It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner, (ii) approve some amendments to our partnership agreement or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may 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. Please read “The Partnership Agreement—Limited Liability.”

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                         . Section 404 will require that we evaluate our internal control over financial reporting to enable management to report on, and our independent registered public accounting firm to audit, 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 U.S. 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. 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. We will also be required to obtain an audit report from our independent registered public accounting firm regarding the effectiveness of our internal controls over financial reporting. If we fail to implement the requirements of Section 404 in a timely manner, if we or our independent registered public accounting firm 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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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 will 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 Partners LP.”

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

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our members, we must first pay or reserve cash for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available for distribution to our members 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 our board 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 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 IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you 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 U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or the IRS, on this or any other tax matter affecting us.

 

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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 U.S. 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 (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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

The present U.S. 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, members of Congress have recently considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the U.S. 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 U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals will be reintroduced or 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 any 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 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

 

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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 would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depletion and depreciation 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, and non-U.S. persons will be required to file U.S. federal 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 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. 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

 

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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 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 allocate certain deductions for depletion and depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. 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.

A unitholder whose common units are loaned 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 is no tax concept of loaning a partnership interest, a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned units. In that case, he may no longer be treated for 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 to the short seller, 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. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should 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 2012 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) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal royalties, and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. 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.

 

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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 U.S. 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. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. 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 make a distribution to Foresight Reserves 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. If the underwriters do not exercise their option, we will issue              common units to Foresight Reserves 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, 2011, 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, 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(1)(2)(3)					%			$					%
Purchasers in the offering					%			$					%
Total					100.0%			$					100.00%

 

(1)	The units acquired by our general partner and its affiliates, including Foresight Reserves, consist of         common units and          subordinated units.

(2)

The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of December 31, 2011, equals parent net investment, which was $         million and is not affected by this offering.

(3)	Assumes the underwriters’ option to purchase additional common units is not exercised.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of September 30, 2011:

 

•

On an actual basis; and

 

•

On an as adjusted basis, after giving effect to this offering, 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 September 30, 2011
		Actual				As   Adjusted
		($ in thousands)
Cash		$	22,434			$
Debt(1):
Revolving credit agreement due 2014(2)		$	246,000			$
9.625% Senior Notes due 2017(2)			397,795
5.780% Long-wall financing agreement(2)			87,000
5.555% Long-wall financing agreement(2)			76,110
Total debt		$	806,905			$
Partners’ capital:
Limited partners:
Common unitholders—public
Common unitholders—Foresight Reserves
Subordinated unitholders—Foresight Reserves
General partner
Total Foresight Energy Partners LP partners’ capital
Members Equity:
Controlling interest		$	363,631			$
Non-controlling interest			(942	)
Total members’ equity			362,689
Total Capitalization		$	1,192,028			$

 

(1)

Total debt does not include $143.7 million of certain lease transactions (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, or any related accrued interest on such 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 these facilities.

 

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DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with “—Significant Forecast Assumptions” below, which includes the factors and assumptions upon which we base our cash distribution policy. 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 combined financial statements as of December 31, 2009 and 2010 and for the years ended December 31, 2008, 2009 and 2010, the unaudited historical condensed combined financial statements as of September 30, 2011 and for the nine months ended September 30, 2010 and 2011.

General

Our Cash Distribution Policy

It is our intent 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 from our operations after the establishment of cash reserves and payment of our expenses. Furthermore, 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. In addition, we expect to adopt a distribution coverage policy in which we may reserve a higher percentage of our operating surplus in respect of quarters where we believe commodity prices are high, and reserve a lower percentage of operating surplus in times of low commodity prices. We believe this policy will support steady and sustainably growing distributions. In addition, we may 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 determine the amount of our quarterly distributions and may change our distribution policy at any time.

Notwithstanding our cash distribution policy, certain provisions of the indenture governing the Senior Notes and our Senior Secured Credit Facility will restrict the ability of our operating subsidiaries to distribute cash to us. Our equity capital structure is designed to support the payment of cash distributions in an amount equal to at least the minimum quarterly distribution to our common unitholders during the period in which we expect the provisions of the indenture and credit facility will restrict our ability to pay cash distributions to all unitholders in accordance with our distribution policy. See “How We Make Distributions to Our Partners—Partnership Interests—Common Units,” “—Subordinated Units,” “—Adjusted Operating Surplus—PIK Common Units” and “—General—Payment-In-Kind Distributions” for a further description of the features of our equity capital structure.

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

There is no guarantee that we will make quarterly cash distributions to our unitholders. We do not have a legal obligation to pay quarterly distributions 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 Senior Secured Credit Facility and the indenture governing the Senior Notes contain financial tests and covenants that we must satisfy. Importantly, the restricted payment basket of the Senior Secured Credit Facility consists of, in pertinent part, aggregate net proceeds of capital contributions and certain other investment returns plus 50% of consolidated net income (or, less 50% of consolidated net loss) accrued on a cumulative basis. The restricted payment basket of the indenture consists of, in pertinent part, aggregate net proceeds of capital contributions and certain other investment returns plus 50% of consolidated net income (or, less 100% of consolidated net loss) accrued on a cumulative basis.

 

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•

Accordingly, non-cash losses, such as an impairment of the value of our properties, will reduce the restricted payment baskets. As of December 31, 2011, our restricted payments baskets under the credit facility and indenture were equal to approximately $                 million and $                 million, respectively. The aggregate minimum quarterly distribution on our common units will be $                 million. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing Arrangements” and “Description of Indebtedness.” Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit facility or the indenture, we will be prohibited from making cash distributions to you notwithstanding our cash distribution policy.

 

•

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, and 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. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

 

•

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash 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 board.

 

•

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, following the PIK period, we will rely upon external financing sources in large part, 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

Pursuant to our distribution policy, we intend upon completion of this offering to declare a minimum quarterly distribution of $         per unit for each complete 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.” Quarterly distributions, if any, will be made within 60 days after the end of each quarter.

The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering, and the cash 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)	As described in more detail in “How We Make Distributions to Our Partners,” we will pay distributions in kind with respect to our subordinated units until the end of the PIK period.

We will 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. We will adjust the quarterly distribution for the period from the closing of this offering through                     , 2012 based on the actual length of the period.

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 six months ending December 31, 2012, and the year ending December 31, 2013. 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 each of the four quarters ended December 31, 2011 based on our unaudited pro forma financial statements that are included in this prospectus.

 

•

“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 six months ending December 31, 2012 and fiscal year ending December 31, 2013.

Unaudited Pro Forma Cash Available for Distribution

The following table illustrates, on a pro forma basis for the fiscal year ended December 31, 2011, 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, 2011.

If we had completed the transactions contemplated in this prospectus on January 1, 2011 our unaudited pro forma cash available for distribution for the fiscal year ended December 31, 2011 would have been $         million. This amount would have enabled us to make an annualized distribution of 100% of the minimum quarterly distribution on our common units, but only approximately         % of the minimum quarterly distribution on the subordinated units.

 

 

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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 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. We estimate that these incremental general and administrative expenses initially will be approximately $             million per year.

Cash available for distribution is a cash accounting concept, while our unaudited pro forma 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 Partners LP

Unaudited Pro Forma Cash Available for Distribution

 

		Pro Forma
		Three Months Ended
		March 31, 2011		June 30, 2011		September 30, 2011		December 31, 2011		Year Ended December 31, 2011
		($ in thousands, except average coal price)
Operating Data:
Coal produced in tons
(Increase) decrease to coal inventory in tons
Coal purchased in tons
Coal sales in tons
Coal sales in tons—committed
Wgt. avg. coal sales price per ton—committed
Coal sales in tons—uncommitted
Wgt. avg. coal sales price per ton—uncommitted
Financial Data:
Coal revenue—committed
Coal revenue—uncommitted
Other coal revenue
Other revenues
Total revenues
Costs and expenses:
Cost of coal sales
Transportation expense
Depreciation, depletion and amortization
Accretion
Selling, general and administrative
Other operating (income) expense, net
Loss on commodity contracts
Gain on coal sale contract termination
Total costs and expenses
Income from operations
Interest and other income (expense):
Interest expense
Interest income
Net income

 

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		Pro Forma
		Three Months Ended
		March 31, 2011		June 30, 2011		September 30, 2011		December 31, 2011		Year Ended December 31, 2011
		($ in thousands, except distributions per unit)
Net income
Plus:
Interest expense
Interest and securities income
Depreciation, depletion and amortization
Accretion
Adjusted EBITDA(1)
Less:
Cash interest expense
Equity in net income of unconsolidated affiliate
Maintenance capital expenditures
Expansion capital expenditures
Plus:
Borrowings or cash on hand for expansion capital expenditures
Cash available for distribution and expansion capital reinvestment
Implied cash distributions based on the minimum quarterly distribution per unit:
Aggregate minimum quarterly distribution per unit
Cash distributions to common unitholders
Cash retained for expansion capital reinvestment(2)
Total distributions
Excess (shortfall)
Interest Coverage Ratio(3)
Minimum Interest Coverage Ratio
Net Leverage Ratio(3)
Maximum Net Leverage Ratio
Cash distributions
Restricted Payment Basket(4)

 

(1)	Please read Note 3 to “Selected Historical Financial Information.”

(2)

Cash retained for expansion capital reinvestment represents the amount of cash that would have been distributed to holders of subordinated units if such units were entitled to participate in cash distributions during the period presented. We expect that the cash we retain will be used for expansion capital projects during the PIK period that provide a rate of return at least as great as the yield of our common units during that time.

(3)

Our Senior Secured 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 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 quarters ended March 31, 2011 and June 20, 2011; 2.25 to 1.00 for the quarter ended September 30, 2011; and 2.50 to 1.00 for quarters ending thereafter.

 

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Our Senior Secured Credit Facility also requires us to maintain, as of the last day of any fiscal quarter, a consolidated net leverage ratio (the ratio of consolidated funded indebtedness less the sum of all unrestricted cash, cash equivalents and short term marketable debt securities that in the aggregate exceed $20.0 million) to consolidated EBITDA for the preceding four quarters. Each of these terms has a specific meaning set forth in the Senior Secured Credit Facility. The maximum consolidated net leverage ratio allowed under the Senior Secured Credit Facility is as follows:

 

Fiscal Quarter Ending		Maximum Consolidated Net Leverage Ratio
March 31, 2011		5.50 to 1.00
June 30, 2011		5.25 to 1.00
September 30, 2011		5.00 to 1.00
December 31, 2011		5.00 to 1.00
March 31, 2012		5.50 to 1.00
June 30, 2012		4.75 to 1.00
September 30, 2012		4.50 to 1.00
December 31, 2012		3.50 to 1.00
March 31, 2013 and thereafter		3.00 to 1.00 (or 3.50 to 1.00 beginning in any fiscal quarter in which the longwalls at Sugar Camp and Hillsboro have completed their first pass)

(4)

Each of our Senior Secured Credit Facility and the indenture governing the Senior Notes restricts our ability to make cash distributions to our unitholders. If no event of default exists under either the facility or the indenture, each document allows us to make distributions of a certain amount, which we refer to as each agreement’s “restricted payment basket.” The restricted payment basket under each of the credit facility and the indenture consists of, in pertinent part, aggregate net proceeds of capital contributions and certain other investment returns plus 50% of consolidated net income (or, less (i) 100% of consolidated net loss with respect to the indenture and (ii) 50% of consolidated net loss with respect to the Senior Secured Credit Facility) accrued on a cumulative basis. The amount set forth above is the restricted payment basket calculated under our credit facility. The restricted payment basket under our indenture is approximately $         higher because the calculation of consolidated net income under the indenture began at an earlier date.

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 six months ending December 31, 2012 and for the year ending December 31, 2013 on a quarterly basis. We forecast that our cash available for distribution generated during the six months ending December 31, 2012 and during the year ending December 31, 2013 will be approximately $         million and $         million, respectively. These amounts would be sufficient to pay the minimum quarterly distribution of $         per unit on all of our common and subordinated units for each quarter during such periods. 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 pro forma and 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 six months ending December 31, 2012 and the year ending December 31, 2013 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” for information as to the accounting policies we have followed for the financial forecast.

 

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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 six months ending December 31, 2012 and the year ending December 31, 2013. 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 Partners LP

Forecasted Cash Available for Distribution

 

Three Months Ending

Six Months Ending December 31, 2012

Three Months Ending

Year Ending December 31, 2013

September 30, 2012

December 31, 2012

March 31, 2013

June 30, 2013

September 30, 2013

December 31, 2013

($ in thousands, except average coal price)

Operating Data:

Coal produced in tons

(Increase) decrease to coal inventory in tons

Coal purchased in tons

Coal sales in tons

Coal sales in tons—committed

Wgt. avg. coal sales price per ton—committed

Coal sales in tons—uncommitted

Wgt. avg. coal sales price per ton—uncommitted

Financial Data:

Coal revenue—committed

Coal revenue— uncommitted

Other coal revenue

Other revenues

Total revenues

Costs and expenses:

Cost of coal sales

Transportation expense

Depreciation, depletion and amortization

Accretion

Selling, general and administrative

Other operating (income) expense, net

Loss on commodity contracts

Gain on coal sale contract termination

Total costs and expenses

Income from operations

 

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Three Months Ending

Six Months Ending December 31, 2012

Three Months Ending

Year Ending December 31, 2013

September 30, 2012

December 31, 2012

March 31, 2013

June 30, 2013

September 30, 2013

December 31, 2013

($ in thousands, except ratios and distributions per unit)

Interest and other income (expense):

Interest expense

Interest income

Net income

Net income

Plus:

Depreciation, depletion and amortization

Interest expense

Adjusted EBITDA(1)

Less:

Cash interest expense

Maintenance and replacement capital expenditures

Expansion capital expenditures

Plus:

Borrowings or cash on hand for expansion capital expenditures

Cash available for distribution and expansion capital reinvestment

Implied cash distributions based on the minimum quarterly distribution per unit:

Aggregate minimum quarterly distribution per unit

Cash distributions to common unitholders

Cash retained for expansion capital reinvestment(2)

Total distributions

 

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Three Months Ending

Six Months Ending December 31, 2012

Three Months Ending

Year Ending December 31, 2013

September 30, 2012

December 31, 2012

March 31, 2013

June 30, 2013

September 30, 2013

December 31, 2013

($ in thousands, except ratios and distributions per unit)

Excess (shortfall)

Interest Coverage Ratio(3)

Minimum Interest Coverage Ratio

Net Leverage Ratio(3)

Maximum Net Leverage Ratio

Cash available for distribution and expansion capital reinvestment

Restricted Payment Basket(4)

 

(1)	Please read Note 3 to “Selected Historical Financial Information.”

(2)

Cash retained for expansion capital reinvestment represents the amount of cash that would have been distributed to holders of subordinated units if such units were entitled to participate in cash distributions during the forecast periods. We expect that the cash we retain will be used for expansion capital projects during the PIK period that provide a rate of return at least as great as the yield of our common units during that time.

Unlike payment-in-kind distributions, the hypothetical cash distributions presented above do not compound over such periods. The table below illustrates the compounding effects of payment-in-kind distributions in respect of two full quarters offering and assumes (i) that we distribute the minimum quarterly distribution of $         per common unit each quarter and (ii) a constant price per common unit of $         (10% lower than the midpoint of the range), $         (the mid-point of the range set forth on the cover page of this prospectus), and $         (10% higher than the mid-point of the range).

 

		Price Per Common Unit
		$             10% lower		$             Midpoint		$             10% higher
Subordinated units outstanding immediately following this offering
Distribution-in-kind for the quarter ending September 30, 2012
Total outstanding subordinated units after first distribution
Distribution-in-kind for the quarter ending December 31, 2012
Total outstanding subordinated units after second distribution

 

(3)

Our senior secured 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 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 quarters ended March 31, 2011 and June 20, 2011; 2.25 to 1.00 for the quarter ended September 30, 2011; and 2.50 to 1.00 for quarters ending thereafter.

Our Senior Secured Credit Facility also requires us to maintain, as of the last day of any fiscal quarter, a net leverage ratio (the ratio of consolidated funded indebtedness less the sum of all unrestricted cash, cash equivalents and short term marketable debt securities that in the aggregate exceed $20.0 million to consolidated EBITDA for the preceding four quarters). Each of these terms has a specific meaning set forth in the Senior Secured Credit Facility. The maximum consolidated net leverage ratio allowed under the Senior Secured Credit Facility is as follows:

 

Fiscal Quarter Ending		Maximum Consolidated Net Leverage Ratio
March 31, 2011		5.50 to 1.00
June 30, 2011		5.25 to 1.00
September 30, 2011		5.00 to 1.00
December 31, 2011		5.00 to 1.00
March 31, 2012		5.50 to 1.00
June 30, 2012		4.75 to 1.00
September 30, 2012		4.50 to 1.00
December 31, 2012		3.50 to 1.00
March 31, 2013 and thereafter		3.00 to 1.00 (or 3.50 to 1.00 beginning in any fiscal quarter in which the longwalls at Sugar Camp and Hillsboro have completed their first pass)

 

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(4)

Each of our Senior Secured Credit Facility and the indenture the Senior Notes restricts our ability to make cash distributions to our unitholders. If no event of default exists under either the facility or the indenture, each document allows us to make distributions of an amount, which we refer to as each agreement’s “restricted payment basket.” The restricted payment basket under each of the credit facility and the indenture consists of, in pertinent part, aggregate net proceeds of capital contributions and certain other investment returns plus 50% of consolidated net income (or, less (i) 100% of consolidated net loss with respect to the indenture and (ii) 50% of consolidated net loss with respect to the Senior Secured Credit Facility) accrued on a cumulative basis. The amount set forth above is the restricted payment basket available under our credit facility. The restricted payment basket of the indenture is approximately $             higher because the calculation of consolidated net income under the indenture began at an earlier date.

Significant Forecast Assumptions

 

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

General

Intent to Distribute the Minimum Quarterly Distribution

Within 60 days after the end of each quarter, beginning with the quarter ending                     , 2012, we intend to make distributions to unitholders of record on the applicable record date. We intend to distribute to our unitholders on a quarterly basis an amount of cash or equity, as applicable, equal to at least the minimum quarterly distribution of $             per unit, or $             per unit per year, to the extent we have sufficient cash available for distribution. We will adjust the minimum quarterly distribution for the period from the closing of the offering through                     , 2012.

Our partnership agreement does not contain a requirement for us to pay distributions, whether in the form of cash or equity, to our unitholders. However, it does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time. See “Distribution Policy and Restrictions on Distributions—General—Our Cash Distribution Policy.”

Payment-In-Kind Distributions

From the date of the closing of this offering until the date that is the earlier of (i) August 15, 2017 and (ii) the date by which we (a) redeem, repurchase, defease or retire the Senior Notes, or otherwise amend the indenture governing the Senior Notes and (b) amend or terminate our Senior Secured Credit Facility, in each case, in a manner that permits us to distribute cash to all unitholders, we will pay distributions in respect of our subordinated units in the form of additional subordinated units. We refer to this period as the “PIK period.” The purpose of this feature is to support the payment of cash distributions in an amount equal to at least the minimum quarterly distribution to our common unitholders during the period in which we expect the provisions of the indenture and credit facility will restrict our ability to pay cash distributions to all unitholders in accordance with our distribution policy. The distribution in kind feature is intended to approximate a scenario in which we distribute cash to the holders of our subordinated units and then they reinvest those cash distributions for additional subordinated units. At the end of the PIK period, future distributions with respect to any outstanding subordinated units will be paid in cash.

Operating Surplus and Capital Surplus

General

Distributions, whether made in cash or in kind, will be made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than we would distribute cash 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, 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 holder of the incentive distribution rights would generally not participate in any capital surplus distributions with respect to those rights. For purposes of determining whether a distribution is made from operating surplus, all distributions paid in-kind will be treated as having been made in cash.

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); plus

 

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•

working capital borrowings made after the end of a period but on or before the date of determination of operating surplus for the period; plus

 

•

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 from such financing until the earlier to occur of the date the capital asset is placed in 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 loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to 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 deemed repaid 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 deemed repayment.

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 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 and replacement 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;

 

•

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;

 

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•

expansion capital expenditures;

 

•

actual maintenance and replacement capital expenditures;

 

•

investment capital expenditures;

 

•

payment of transaction expenses relating to interim capital transactions;

 

•

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

 

•

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

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of cash 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 and debt securities; 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 requires that we treat distributions, whether in cash or in equity, as coming from operating surplus until the sum of all distributions since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus includes up to $             million, which does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Estimated maintenance and replacement capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance and replacement capital expenditures and investment capital expenditures do not. Maintenance and replacement capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Examples of maintenance and replacement 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 our long-term operating capacity. Maintenance and replacement 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. Capital expenditures made solely for investment purposes will not be considered maintenance and replacement capital expenditures.

Because our maintenance and replacement capital expenditures can be irregular, the amount of our actual maintenance and replacement 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 and replacement capital expenditures from operating surplus.

 

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Our partnership agreement will require that an estimate of the average quarterly maintenance and replacement 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 and replacement 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 and replacement capital expenditures, such as 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 and replacement capital expenditures, please read “Distribution Policy and Restrictions on Distributions.”

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

 

•

it will reduce the risk that maintenance and replacement capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution in respect of all units for the quarter and subsequent quarters;

 

•

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 capital expenditures that we expect will increase our operating capacity for the long term. Examples of expansion capital expenditures include the acquisition of reserves, equipment or a new mine or the expansion of an existing mine, to the extent such capital expenditures are expected to expand our long-term operating capacity. 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 the construction of such capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital improvement commences commercial service and the date that it is disposed of or abandoned. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance and replacement 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 a capital asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or revenues, but which are not expected to expand, for more than the short term, our operating capacity or revenues.

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 the construction or improvement of a capital asset in respect of a period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset 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.

 

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

Partnership Interests

Common Units

At the closing of this offering, our common units and incentive distribution rights will be the only partnership interests entitled to cash. Please see “Description of Common Units.”

Subordinated Units

Foresight Reserves will initially own all of our subordinated units. The subordinated units will generally share pro rata with our common units with respect to the payment of distributions except that, for each quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordinated units will only be entitled to receive distributions in kind to the extent the distributions, if made in cash, could have been made from operating surplus. The subordinated units will not accrue arrearages.

During the PIK period, any distributions paid with respect to a subordinated unit will be in the form of additional subordinated units, the number of which will be calculated in the manner set forth below in “—Calculation of Payment-In-Kind Distributions.” When the subordination period ends, all of the subordinated units will convert into an equal number of common units, unless conversion occurs prior to the end of the PIK period, in which case they will convert into PIK common units. Please read “—Subordination Period.”

 

Calculation of Payment-In-Kind Distributions

The fractional number of subordinated units we distribute in kind with respect to each subordinated unit will be determined by dividing the distribution paid on a common unit in respect of the same quarter by the volume weighted average price of our common units for the 10 trading days immediately preceding the date on which the common units begin trading ex-dividend. We will calculate the number of PIK common units that we distribute in kind with respect to each existing PIK common unit in the same manner.

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 prior quarters, before any distributions from operating surplus may be made on the subordinated units, respectively. The practical effect of the subordination period is to increase the likelihood that during such periods there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Except as described below, the subordination period will begin on the closing date of this offering and will expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending June 30, 2015, if each of the following has occurred:

 

•

distributions (in cash or in equity) on each of the outstanding units equaled or exceeded the minimum quarterly distribution of $         per unit for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; and

 

 

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•

the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distribution on all of the units during those periods on a fully diluted weighted average basis.

Early Termination of Subordination Period. Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending June 30, 2014, if each of the following has occurred:

 

•

distributions (in cash or in equity) on each of the outstanding units equaled or exceeded $         (150.0% of the annualized minimum quarterly distribution) for each quarter in the four-quarter period immediately preceding that date without a material deviation from our distribution coverage policy; and

 

•

the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of $         (150.0% of the annualized minimum quarterly distribution) on all of the outstanding units on a fully diluted weighted average basis and the related distribution on the incentive distribution rights.

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 cash distributions.

Adjusted Operating Surplus

Adjusted operating surplus is intended to 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. Adjusted operating surplus 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 in working capital borrowings with respect to that period; less

 

•

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

 

•

any net decrease in working capital borrowings with respect to that period; plus

 

•

any net increase in cash reserves for operating expenditures with respect to that period 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 with respect to 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.

Conversion of Outstanding Subordinated and PIK Common Units Upon Removal of the General Partner

If the unitholders remove our general partner other than for cause:

 

•

the subordinated units and any PIK common 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; and

 

•

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

 

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Distributions From Operating Surplus During Subordination Period

Our partnership agreement requires that we make distributions from operating surplus for any quarter during the subordination period in the following manner:

 

•

first, 100.0% 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 for prior quarters;

 

•

second, 100.0% to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

•

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

Distributions of Cash From Operating Surplus After The Subordination Period

Our partnership agreement requires that we make distributions of cash from operating surplus for any quarter after the subordination period in the following manner:

 

•

first, 100.0% 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.

PIK Common Units

If the subordination period ends during the PIK period, the subordinated units will convert into PIK common units. Our partnership agreement provides that the PIK common units will participate pro rata with the common units with respect to the payment of distributions. However, we will pay distributions on PIK common units by issuing additional PIK common units in an amount calculated in the manner described above in “—Partnership Interests—Calculation of Payment-In-Kind Distributions.” At the end of the PIK period, the PIK common units will convert into common units.

General Partner Interest

Our general partner owns a non-economic general partner interest in us and thus will not be entitled to distributions that we make prior to our liquidation in respect of such interest.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (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. For purposes of calculating the amount of incentive distributions to be made to the holders of incentive distribution rights, all distributions in kind will be treated as if they were paid in cash. Upon the closing of this offering, our general partner will hold all of our incentive distribution rights, but may transfer these rights separately from its non-economic general partner interest.

If for any quarter:

 

•

We have distributed cash from operating surplus or, with respect to the subordinated units, the equity equivalent thereof, to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

•

We have distributed cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

 

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then, our partnership agreement requires that any incremental distributions from operating surplus for that quarter will be made among the unitholders and the general partner in the following manner:

 

•

first, 100.0% 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 unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

 

•

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

 

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Distributions From Operating Surplus

The following table illustrates the percentage allocations of cash, or, with respect to the subordinated units during the PIK period, the equity equivalent thereof, from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner 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 our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

 

		Total Quarterly Distribution Per Common and Subordinated Unit(1)		Marginal Percentage Interest in Distribution
				Unitholders				General Partner
Minimum Quarterly Distribution		$			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	%

 

(1)	The amounts in this column include the value of the additional units that will be paid in kind to the holders of the subordinated units each quarter until the end of the PIK period.

General Partner’s 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 to our general partner 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 after the PIK period when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for the prior four consecutive fiscal quarters. The reset and target distribution levels will be 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 this event increase as described below. We anticipate that our general partner would exercise this reset right in

 

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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 to our general partner.

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 a predetermined formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights received by our general partner for the quarter prior to the reset event as compared to the average cash distributions per common unit during this period.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the amount of cash distributions received by our general partner in respect of its incentive distribution rights for the most recent quarterly distribution by (y) the amount of cash distributed per common unit for such quarter.

Following a reset election, a baseline 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, 100.0% to all common unitholders, pro rata, until each unitholder receives an amount per unit equal to 115.0% of the reset minimum quarterly distribution for that quarter;

 

•

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

 

•

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

 

•

thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to our general partner.

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 our general partner 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 prior fiscal quarter immediately preceding the reset election was $        .

 

		Quarterly Distribution Per Unit Prior to Reset		Unitholders				General Partner				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.

 

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The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and our general partner in respect of its incentive distribution rights, based on the amount distributed per quarter 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 $         per quarter for the quarter prior to the reset.

 

Quarterly Distributions Per Unit Prior to Reset

Distributions to Common Unitholders Prior to Reset

Cash Distributions to General Partner Prior to Reset

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 $

—

$

—

$

$

$

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and our general partner in respect of its 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 to our general partner upon the reset was calculated by dividing (1) the amount received by our general partner in respect of its incentive distribution rights for the quarter prior to the reset as shown in the table above, or $         million, by (2) the amount distributed on each common unit for the quarter prior to the reset as shown in the table above, or $         .

 

Quarterly Distributions Per Unit After Reset

Distributions to Common Unitholders After Reset

Cash Distributions to General Partner After Reset

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 $

—

—

—

—

—

$

—

$

$

Our general partner will be entitled to cause the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

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, 100.0% to all common and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

 

•

second, 100.0% to the common unitholders, pro rata, until we distribute for each common unit an amount of cash 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.

 

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Effect of a Distribution From Capital Surplus

Our partnership agreement treats a distribution of cash from 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 cash from capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in relation 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.

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

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 unrecovered initial unit price;

 

•

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 unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would convert into two subordinated units. Our partnership agreement provides that we do 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 manager’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

 

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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 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 unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

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, 100.0% to the common unitholders, until the capital account for each common unit is equal to the sum of: (1) the unrecovered 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, 100.0% to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

•

fourth, 100.0% to all unitholders, pro rata, until we allocate under this paragraph 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 of cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 100.0% to the unitholders, pro rata, for each quarter of our existence;

 

•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph 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 of cash 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 our general partner for each quarter of our existence;

 

•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph 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 of cash 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 our general partner for each quarter of our existence; and

 

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The percentage interests set forth above for our general partner assume our general partner has not transferred the incentive distribution rights.

 

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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.

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, 100.0% 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, 100.0% 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, 100.0% 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 general partner 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 our general partner 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. In the event 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: (i) audited financial statements for the years ended December 31, 2010, 2009 and 2008; (ii) unaudited financial statements for the years ended December 31, 2007 and 2006; and (iii) unaudited condensed financial statements for the nine months ended September 30, 2011 and 2010. The unaudited consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of our management, include all adjustments, consisting of only normal and recurring adjustments, necessary for a fair presentation of the information set forth herein. Operating results for the nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011 or for any future period. This data should be read in conjunction with consolidated financial statements and related notes included elsewhere in this prospectus.

The following information is only a summary and should be read in conjunction with the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the related notes included elsewhere in this prospectus.

 

		For the Years Ended December 31,																				For the Nine Months Ended September 30,
		2010				2009				2008				2007				2006				2011				2010
		($ in thousands, except averages)
Statement of Operations Data
Revenues
Coal sales revenue		$	362,592			$	271,249			$	238,842			$	—			$	—			$	358,931			$	246,087
Costs and Expenses
Cost of coal sales			130,610				101,528				109,421				—				—				119,762				88,272
Transportation expense			58,482				48,933				46,942				—				—				72,615				32,489
Depreciation, depletion and amortization			55,590				38,937				27,886				226				143				52,451				39,778
Accretion			2,068				1,735				203				—				—				1,279				1,477
Selling, general, and administrative			28,367				22,610				11,913				13,581				11,836				26,083				17,386
Other operating (income) expense, net(1)			(2,611	)			(3,208	)			334				(80	)			(960	)			52				(964	)
Loss on commodity contracts			—				—				—				—				—				847				—
Gain on coal sale contract termination			—				—				(44,019	)			—				—				—				—
Operating income (loss)			90,086				60,714				86,162				(13,727	)			(11,019	)			85,842				67,649
Other income and expense:
Interest and securities income			67				427				1,360				359				270				4				52
Interest expense			(40,498	)			(46,466	)			(43,625	)			(21,618	)			(8,179	)			(35,196	)			(32,615	)
Loss on interest rate swaps			—				(586	)			—				—				—				—				(550	)
Net income from continuing operations			49,655				14,089				43,897				(34,986	)			(18,928	)			50,650				34,536
Net loss from discontinued operations			(40,893	)			(50,545	)			(41,249	)			(51,059	)			(12,364	)			—				(40,893	)
Net income (loss)			8,762				(36,456	)			2,648				(86,045	)			(31,292	)			50,650				(6,357	)
Less: Net income attributable to non-controlling interests			909				246				56				(650	)			7				50				867
Net income (loss) attributable to controlling interests		$	7,853			$	(36,702	)		$	2,592			$	(85,395	)		$	(31,299	)		$	50,600			$	(7,224	)

 

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		For the Years Ended December 31,																				For the Nine Months Ended September 30,
		2010				2009				2008				2007				2006				2011				2010
		($ in thousands, except averages)
Statement of Cash Flows
Net cash from operating activities		$	32,044			$	107,400			$	75,624			$	(80,861	)		$	(5,340	)		$	45,403			$	(62,793	)
Net cash from investing activities		$	(250,168	)		$	(408,714	)		$	(198,138	)		$	137,930	)		$	(247,881	)		$	(242,490	)		$	(171,664	)
Net cash from financing activities		$	203,486			$	329,604			$	135,397			$	206,429			$	270,867			$	186,070			$	200,343
Investment in mining rights, equipment and development		$	(255,460	)		$	(348,445	)		$	(182,627	)		$	(143,737	)		$	(236,898	)		$	(242,490	)		$	(176,958	)
Balance Sheet Data (at period end)
Cash and investments in available-for-sale securities		$	33,451			$	57,031			$	28,585			$	2,240			$	4,633			$	22,434			$	13,975
Property, plant, equipment, and mine development, net		$	995,425			$	634,250			$	365,663			$	278,745			$	198,810			$	1,233,767			$	841,497
Total assets		$	1,131,880			$	1,036,160			$	697,394			$	509,119			$	345,753			$	1,421,744			$	993,902
Total long-term debt (2)		$	605,390			$	345,753			$	353,956			$	691,162			$	540,736			$	806,905			$	536,107
Total equity		$	282,066			$	133,103			$	86,702			$	(470,003	)		$	(369,388	)		$	362,689			$	242,995
Other Data
Adjusted EBITDA (3)		$	147,744			$	101,386			$	70,232			$	(13,501	)		$	(10,876	)		$	139,572			$	108,354
Capital expenditures		$	(255,460	)		$	(348,445	)		$	(182,627	)		$	(143,737	)		$	(236,898	)		$	(242,490	)		$	(176,958	)
Tons produced (4)			6,813				5,921				5,411				—				—				6,982				5,297
Tons sold (4)			6,730				5,635				5,484				—				—				6,410				4,550
Average realized price per ton sold (5)		$	53.88			$	48.14			$	43.55			$	—			$	—			$	56.00			$	54.09
Average cost of sales per ton sold (6)		$	19.41			$	18.02			$	19.95			$	—			$	—			$	18.68			$	19.40

 

(1)	For the period ended December 31, 2009, this relates primarily to a one-time sale of equipment at Macoupin.

(2)

Total long-term debt does not include $143.5 million of certain lease transactions (including coal and surface leases) that are characterized as financing arrangements due to the 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.” It also includes, among other items, other liabilities of discontinued operations.

(3)

Adjusted EBITDA is defined as earnings before interest, taxes, depreciation, depletion, amortization, accretion, and excluding the items or expenses as set forth below. Adjusted EBITDA is not a measure of performance defined in accordance with 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 GAAP results and the reconciliation to GAAP results, provides a more complete understanding of our results of operations and the factors and trends affecting our business. Adjusted EBITDA should not be considered as an alternative to net income (loss) as an indicator of our performance or as an alternative to net cash provided by operating activities as a measure of liquidity. The primary material limitations associated with the use of Adjusted EBITDA as compared to GAAP results are (i) it may not be comparable to similarly titled measures used by other companies in our industry, and (ii) it excludes financial information that some may consider important in evaluating our performance. We compensate for these limitations by providing disclosure of the differences between Adjusted EBITDA and GAAP results, including providing a reconciliation of Adjusted EBITDA to GAAP results, to enable investors to perform their own analysis of our operating results.

 

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The following table reconciles Adjusted EBITDA to the most directly comparable GAAP measure, net income (loss) from continuing operations:

 

		For the Years Ended December 31,																				For the Nine Months Ended September 30,
		2010				2009				2008				2007				2006				2011				2010
		($ in thousands)
Adjusted EBITDA:
Net income (loss) from continuing operations		$	49,655			$	14,089			$	43,897			$	(34,986	)		$	(18,928	)		$	50,650			$	34,536
Interest expense			40,498				46,466				43,625				21,618				8,179				35,196				32,615
Interest and securities income			(67	)			(427	)			(1,360	)			(359	)			(270	)			(4	)			(52	)
Depreciation, depletion and amortization			55,590				38,937				27,886				226				143				52,451				39,778
Accretion			2,068				1,735				203				—				—				1,279				1,477
Loss on interest rate swaps			—				586				—				—				—				—				—
Gain on coal sale contract termination			—				—				(44,019	)			—				—				—				—
Adjusted EBITDA		$	147,744			$	101,386			$	70,232			$	(13,501	)		$	(10,876	)		$	139,572			$	108,354

 

(4)

Only includes tons produced and tons sold from our Williamson mine prior to January 1, 2010, as our Macoupin mine was in development prior to this period. Only includes tons produced and tons sold from our Williamson and Macoupin mines for the year ended December 31, 2010 and the nine months ended September 30, 2011 and 2010, as our Sugar Camp and Hillsboro mines are in development. Macoupin produced and sold 0.2 million tons in the year ended December 31, 2009, for which revenues and costs associated with this production and coal sales were capitalized as mine development. Sugar Camp produced and sold 0.6 and 0.1 million tons for the nine months ended September 30, 2011 and 2010, respectively, and 0.3 million tons for the year ended December 31, 2010, for which revenues and costs associated with this production and coal sales were capitalized as mine development.

(5)	Calculated as coal sales revenue divided by tons sold.

(6)	Calculated as cost of coal sales divided by tons sold.

 

 

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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 cost per ton 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, a longwall mine in southern Illinois, currently producing coal with one longwall and two continuous miner units, with a productive capacity of 7 million tons;

 

•

Sugar Camp, a longwall mine in southern Illinois, currently producing coal with three continuous miner units, with a productive capacity of 28 million tons when all four of its longwalls are operational, the first of which is expected to begin in the first quarter of 2012;

 

•

Hillsboro, a longwall mine in central Illinois, currently producing coal with two continuous miner units, with a productive capacity of 27 million tons when all three of its longwalls are operational, the first of which is expected to begin in the third quarter of 2012; and

 

•

Macoupin, a continuous miner operation in central Illinois with a productive capacity of 3 million tons.

With approximately 3 billion tons of assigned proven and probable coal reserves, we believe that our coal reserves are sufficient to support over 45 years of production at our full expected productive capacity of up to 65 million tons per year. All of our reserves are favorably located with transportation access to market via truck, rail and barge. We have direct and indirect access to all five Class I railroads and control a seaborne export terminal in Louisiana and a barge-loading river terminal on the Ohio River. We have numerous contractual arrangements with railroads and river terminals giving us long-term access with price certainty.

Since our inception, we have invested over $1.5 billion in capital expenditures to develop what we believe are industry leading, geologically similar, low cost and highly productive mines and related infrastructure. In 2010, we produced 7.2 million tons of coal and through September 30, 2011 we produced 7.9 million tons of coal. At full runrate, each of our first longwalls at Sugar Camp and Hillsboro is expected to have a productive capacity of at least 7 million tons of coal per year.

Factors That Affect Our Results

Coal Prices. We attempt to mitigate price fluctuations by executing long-term contracts when we feel the market is favorable and by opportunistically selling coal into the spot market. We were able to sell a significant portion of our existing production at favorable prices under long-term contracts during the historically high priced period in 2008. Since then, coal prices weakened due to the economic downturn, reduced electrical generation from coal-fired plants and high inventory levels. Over the recent past, coal prices have begun to firm as a result of improved economic conditions, increased electrical generation and a draw-down of utility inventories.

 

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International Coal Demand. During the past three fiscal years, we have exported approximately 33% of our coal to Europe, South America, Africa and Asia. We believe that international market demand for thermal coal will increase due primarily to strong demand from China and India and other Asian countries. As a result of growing international demand, coal prices for seaborne thermal coal have, from time to time, yielded higher margins to us than domestic prices and, based on forward price curves, are expected to continue to do so. Given our low cost of production, transportation logistics and the high Btu content of our coal, we believe we will be able to cost competitively continue to sell our coal into the seaborne market.

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 panels that limit moves to only once per year. Williamson has successfully moved its longwall three times. Production interruption associated with initiating production at a new panel has ranged from two days to seven weeks.

Contract Position. We have sold a significant portion of our coal under long-term agreements with terms that range from twelve months to nine years. As of September 30, 2011, approximately 78% of our expected coal production in 2012 was sold or committed under contracts. We have sold coal to over 45 domestic power plants, industrial users and international customers. In 2010, we sold approximately 77% of our coal to power plants in the United States and 23% was delivered to international customers. Our sales strategy is to enter into up to ten year contracts for the majority of our additional production, with the first two to three years at fixed prices, and the final years subject to resets at a negotiated price or the prevailing market price. We believe that our low cost structure positions us to successfully reprice our coal at a profitable margin in any price environment in which our competitors can operate.

Cost of Coal Sales. Our costs of coal sales include mining costs, labor, supplies and repairs, power, rental and leases expense, reclamation cost, inventory charges and sales-related costs, which are composed of royalties, wheelage and other costs including preparation expense, belting, loading, depreciation and amortization, and mine administration expenses. Each of these cost components has its own drivers, which can include the cost and availability of labor, changes in health care and insurance regulation, the cost of consumable items or inputs in our supplies, changes in regulation of our industry, and/or our staffing levels. In particular, our royalties depend directly upon the price at which we sell our coal subject to a minimum floor level.

Transportation Expense and Development. We sell a majority of our coal to customers at delivery points other than our mines including 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 contracts 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. We record the full cost of any transportation between our mines and the point of sale as revenue.

We continue to develop our transportation infrastructure. In 2011, we completed the rail spur at the Hillsboro complex, finished development of our state of the art dock facility located on the Ohio River and gained control of a seaborne export terminal in Louisiana. These developments, in conjunction with our existing transportation infrastructure, will allow us to continue to cost effectively deliver coal to coal-fired utilities in nearly every domestic market in the United States and the export markets, including Europe, South America, Africa, and Asia.

Foresight Supply Company. In January 2011, we established a new entity, Foresight Supply Company, which serves as the central supply entity for all of our Illinois coal mining operations. By consolidating our coal supply functions, we anticipate gaining efficiencies and reducing costs through a more centralized procurement, stocking, and delivery process.

 

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Selling, General and Administrative. Selling, general and administrative consists primarily of sales commissions, severance taxes, sales related expenses, corporate overhead and black lung taxes. In the ordinary course of business, we sometimes enter into contracts with third party sales representatives and pay them agreed upon sales commissions. Additionally, through December 31, 2011 we were managed by Foresight Management, a company owned by Foresight Reserves and reimbursed Foresight Reserves for direct and indirect management costs and labor incurred by them on our behalf.

Seasonality. Demand for coal can increase due to unusually hot or cold weather as power 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.

Critical Accounting Policies

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 GAAP. GAAP require 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.

Development Stage Operations. Certain of our operations are considered to be in the development stage. While in the development stage, any coal sales made by these companies are recorded as a reduction of mine development costs capitalized on our balance sheet. Certain expenses incurred by these companies while in the development stage are also capitalized on our balance sheet. In accordance with GAAP, the production phase is not deemed to commence with removal of soluble mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to the ore body. As of September 30, 2011, our Hillsboro and Sugar Camp operations remain in the development stage, and are expected to remain so until the time the longwall mining commences at each operation. Our Macoupin operation was in the development stage from January 22, 2009, the date on which we acquired this property, until December 31, 2009. Our Williamson operations are in the production phase. Once our mines are in the production phase, the results of their operations are accounted for on our income statement.

Revenue Recognition. Coal sales revenue includes sales to customers of coal produced at our operations and sale of coal purchased from third parties. We recognize coal sales at the time legal title and risk of loss pass to our customers, which is generally when the coal is delivered to an agreed-upon destination. Quality adjustments are recorded as necessary based on contract specifications and are netted against coal mining revenue. Fees related to the handling and transportation of coal inventory during the production process are included in coal inventory in the consolidated balance sheets.

Variable Interest Entities. We employ contractors to provide labor for our mines, coal processing facilities and dock in Indiana. In accordance with GAAP, our consolidated financial statements include certain other entities considered variable interest entities for which we are the primary beneficiary. These entities own no equipment, real property or other intangible assets and each holds a contract to provide contract labor services solely to Foresight Energy LLC subsidiaries. We encourage you to read the notes to our historical audited consolidated financial statements found elsewhere in this prospectus for more information about these entities.

Sale-Leaseback Financing Arrangement. In the first quarter of 2009, Macoupin sold certain of its coal reserves to WPP, a subsidiary of 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. As Macoupin has continued involvement in the assets sold, the transaction is treated as a financing arrangement. As of September 30, 2011 and December 31, 2010, we carried an outstanding balance

 

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related to this transaction of $143.5 million on our balance sheet, and for the nine months ended September 30, 2011 and for the year ended December 31, 2010, we reported an associated interest expense of $18.8 million and $23.4 million, respectively, on our income statement.

Use of Estimates. Preparing financial statements in conformity with 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.

Asset Retirement Obligations and Reclamation. Our ARO liabilities primarily 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 for both underground mines and surface facilities 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 spending 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. We record an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. 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 on the straight-line method over its expected life. 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.

New Accounting Pronouncements

None.

 

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Results of Operations

The table below displays our consolidated results of operations:

 

		For the Years Ended December 31,												For the Nine Months Ended September 30,
		2010				2009				2008				2011				2010
Revenues			($ in thousands)
Coal sales revenue		$	362,592			$	271,249			$	238,842			$	358,931			$	246,087
Costs and Expenses
Cost of coal sales			130,610				101,528				109,421				119,762				88,272
Transportation expense			58,482				48,933				46,942				72,615				32,489
Depreciation, depletion and amortization			55,590				38,937				27,886				52,451				39,778
Accretion			2,068				1,735				203				1,279				1,477
Selling, general, and administrative			28,367				22,610				11,913				26,083				17,386
Other operating ( income) expense, net			(2,611	)			(3,208	)			334				52				(964	)
Loss on commodity contracts			—				—				—				847				—
Gain on coal sale contract termination			—				—				(44,019	)			—				—
Operating income			90,086				60,714				86,162				85,842				67,649
Other income and expense:
Interest and securities income			67				427				1,360				4				52
Interest expense			(40,498	)			(46,466	)			(43,625	)			(35,196	)			(32,615	)
Loss on interest rate swaps			—				(586	)			—				—				(550	)
Net Income from continuing operations			49,655				14,089				43,897				50,650				34,536
Net loss from discontinued operations			(40,893	)			(50,545	)			(41,249	)			—				(40,893	)
Net income (loss)			8,762				(36,456	)			2,648				50,650				(6,357	)
Less: Net income attributable to non-controlling interests			909				246				56				50				867
Net income (loss) attributable to controlling interests		$	7,853			$	(36,702	)		$	2,592			$	50,600			$	(7,224	)

Comparison of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2010

Coal Sales Revenue. Total coal sales revenue for the nine months ended September 30, 2011, was $358.9 million, an increase of $112.8 million, or 46%, compared to total coal sales revenue of $246.1 million for the nine months ended September 30, 2010. The increase is due to a 41% increase in sales volume and 4% increase in average realization per ton. Average realization, defined as the average price sold per ton, was $56.00 per ton in the nine months ended September 30, 2011, an increase of $1.91 per ton, or 4%, compared to average realization in the nine months ended September 30, 2010, of $54.09 per ton. This increase was primarily due to an increase in international sales. We sold 6.4 million tons of coal in the nine month period ended September 30, 2011, compared to 4.6 million tons of coal in the same period in 2010. The increased sales volumes were attributable to increases in production at both Williamson and Macoupin and increased market penetration by Macoupin. Coal production increased to 7.9 million tons for the nine month period ended September 30, 2011, compared to 5.4 million tons for the same period in 2010. This increase was attributable to increased production from Macoupin resulting from the addition of a second continuous miner unit and increased production from Williamson due to a reduction of six weeks of idle time associated with the move of its longwall.

 

 

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		For the Nine Months Ended September 30, (tons in millions)
		2011				2010
Production(1)			7.9				5.4
Tons sold			6.4				4.6
Average realization ($/ton)		$	56.00			$	54.09

 

(1)

As reported by MSHA

Cost of Coal Sales. Cost of coal sales for the nine months ended September 30, 2011 was $119.8 million, an increase of $31.5 million, or 36%, from our cost of coal sales of $88.3 million during the nine months ended September 30, 2010. This increase was primarily a result of increased sales volumes. Our average cost per ton sold in the nine months ended September 30, 2011 was $18.68, a decrease of $0.72, or 4%, from our average cost per ton of $19.40 in the nine months ended September 30, 2010. The decrease was primarily attributable to the increased tons sold from Macoupin in 2011 compared to the first nine months of 2010 and the lower overall costs of this operation.

 

		For the Nine  Months Ended September 30,
		2011				2010
Cost of coal sales (in millions)		$	119.8			$	88.3
Tons sold (in millions)			6.4				4.6
Average cost of coal sales per ton sold ($/ton)		$	18.68			$	19.40

Transportation Expense. Our costs of transportation in the nine months ended September 30, 2011 were $72.6 million, an increase of $40.1 million or 123%, compared to our transportation expense of $32.5 million in the nine months ended September 30, 2010. This increase in transportation expense relates primarily to the increased sales volume in 2011 compared to 2010, and increased international sales.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses for the nine months ended September 30, 2011 were $52.5 million, an increase of $12.7 million, or 32%, over our depreciation, depletion and amortization expenses of $39.8 million for the nine months ended September 30, 2010. This increase was a result of additional amortization of development costs related to increased production at our mining operations and additional expense related to property, plant, equipment, and mine development at both Williamson and Macoupin. In addition, there were increases in depreciation for Hillsboro due to their continued growth and expansion.

Selling, General, and Administrative Expenses. Our selling, general, and administrative expenses for the nine months ended September 30, 2011 were $26.1 million, an increase of $8.7 million, or 50%, compared to our selling, general, and administrative expenses of $17.4 million for the nine months ended September 30, 2010. The increase was attributed to the continued growth and expansion of Foresight Energy LLC.

Interest Expense. Our interest expense in the nine months ended September 30, 2011 was $35.2 million, an increase of $2.6 million, or 8%, over our interest expense of $32.6 million for the nine months ended September 30, 2010. The increase in interest expense was due to an increase in the amount of amortized debt issuance costs and overall increase in borrowings required to further develop Hillsboro and Sugar Camp. This increase was offset by a decline in the average interest rate on our borrowings primarily due to repayment of the Williamson Royalty Ventures note in 2010 and additional capitalized interest at Hillsboro and Sugar Camp related to mine development.

Change in Fair Value in Commodity Contracts. We recorded an unrealized change in fair value in commodity contracts during the nine months ended September 30, 2011 of approximately $0.8 million. We entered into the coal commodity contracts during the nine months ended September 30, 2011 and there were no similar contracts in 2010.

 

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Net Income from Continuing Operations. We realized net income from continuing operations of $50.7 million in the nine months ended September 30, 2011, a $15.6 million increase from our net income from continuing operations in the same period in 2010 of $34.5 million due to the factors stated above.

Comparison of Twelve Months Ended December 31, 2010 to Twelve Months Ended December 31, 2009

Coal Sales Revenues. Total mining revenues for the year ended December 31, 2010, increased by $91.3 million, or 34%, to $362.6 million from $271.2 million for the year ended December 31, 2009. This was due to an increase in average realization and an increase in the amount of coal sold during the 2010 year. Average realization was $53.88 per ton in the year ended December 31, 2010, an increase of $5.74 per ton, or 15%, over our average realization for the year ended December 31, 2009, which was $48.14. The improvement was due to the expiration of some low priced contracts at the end of 2009 and shipments on new contracts in 2010 with higher average realization. We sold 6.7 million tons of coal in the year ended December 31, 2010, compared to sales of 5.6 million tons for the year ended December 31, 2009. The increased sales volumes were due primarily to sales from our acquired Macoupin operations which moved out of the development stage at the beginning of 2010. We produced 6.8 million tons of coal in the year ended December 31, 2010, or 0.9 million tons more than the 5.9 million tons we produced during the year ended December 31, 2009, due to the commencement of production at the acquired Macoupin operation in 2010. The 2009 period did not benefit from any production from Macoupin.

 

		For the Year Ended December 31, (tons in millions)
		2010				2009
Production(1)			6.8				5.9
Tons sold (sales)			6.7				5.6
Average realization ($/ton)		$	53.88			$	48.14

 

(1)

As reported by MSHA.

Cost of Coal Sales. Our cost of coal sales for the year ended December 31, 2010, was $130.6 million, an increase of $29.1 million, or 29% from our cost of sales of $104.1 million, during the year ended December 31, 2009, primarily as a result of increased sales volumes. Our average cost per ton sold for the year ended December 31, 2010 was $19.41, an increase of $1.39, or 8%, over our average cost per ton of $18.02 for the year ended December 31, 2009. The increase was primarily attributable to increases in our royalty expense as a result of increased revenue / sales prices, supplies and repairs, and specific subsidence projects which were completed during the third and fourth quarters at the Williamson mining operations.

 

		For the Year Ended Ended December 31,
		2010				2009
Cost of coal sales (in millions)		$	130.6			$	101.5
Tons sold (in millions)			6.7				5.6
Average cost of coal sales per ton sold ($/ton)		$	19.41			$	18.02

Transportation Expense. Our costs of transportation for the year ended December 31, 2010, were $58.5 million, an increase of $9.6 million or 20%, over our transportation expense of $48.9 million for the year ended December 31, 2009. This increase in transportation expense relates primarily to the increased tonnage sold in 2010 over 2009.

Depreciation and Amortization. Our depreciation and amortization expenses for the year ended December 31, 2010, were $55.6 million, an increase of $16.7 million, or 43%, over our depreciation and amortization expenses of $38.9 million for the year ended December 31, 2009. The higher expense in the year

 

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ended December 31, 2010, was principally due to the acquisition of Macoupin in 2009 and the recording depreciation expense in the 2010 period as production began. Macoupin had no depreciation expense in the comparable 2009 period as it was in development.

Selling, General and Administrative. Our selling, general and administrative expenses for the year ended December 31, 2010, were $28.4 million, an increase of $5.8 million, or 25%, over our selling, general and administrative expenses of $22.6 million for the year ended December 31, 2009. The higher expense in the year ended December 31, 2010, was due to higher administrative costs associated with managing additional mining operations compared to the year ended December 31, 2009. Specifically, the Company had additional costs related to the development and growth of the Hillsboro, Sugar Camp, and Macoupin mining operations.

Interest Expense. Our interest expense in the year ended December 31, 2010, was $40.5 million, a decrease of $6.0 million, or 13%, compared to our interest expense of $46.5 million for the year ended December 31, 2009. The decrease in interest expense was due to a decline in the average interest rate on our borrowings primarily due to the repayment of the Williamson Royalty Ventures note and additional capitalized interest on our Hillsboro and Sugar Camp mine development projects.

Net Income from Continuing Operations. We realized net income from continuing operations of $49.7 million in the year ended December 31, 2010, a $35.6 million increase from our net income from continuing operations of $14.1 million for the year ended December 31, 2009 due to the factors stated above.

Comparison of Twelve Months Ended December 31, 2009 to Twelve Months Ended December 31, 2008

Coal Sales Revenues. Coal sales revenue for the year ended December 31, 2009, increased by $32.4 million, or 14%, to $271.2 million from $238.8 million for the year ended December 31, 2008, primarily due to increased average realized prices and increased tonnages sold from our Williamson operation. Our average realized price was $48.14 per ton in 2009, an increase of $4.58 per ton, or 11%, over our average realized price from coal sales in 2008, which was $43.55. These favorable contract prices are a result of contracts that we secured in 2008 and 2009 for 2009. We sold 5.6 million tons in 2009, an increase of 0.1 million tons, or 2%, over the 5.5 million tons we sold from the Williamson operation in 2008. The increase in tonnage was due to a full year of longwall mining in 2009 versus a partial year of longwall mining in 2008. Our longwall at Williamson commenced operation in March 2008. Our other mining operations were in the development stage during 2008 and 2009 and recorded no revenues.

Cost of Coal Sales. Our cost of coal sales for the year ended December 31, 2009, were $101.5 million, a decrease of $7.9 million, or 7%, from our 2008 cost of sales of $109.4 million. The reduction in our cost was due to operational efficiencies we experienced at Williamson from greater production. Higher production results in lower cost per ton because significant costs of production are fixed at a large coal mine like Williamson. Our average cost per ton sold in 2009 decreased by $1.94, or 10% to $18.02, from our average cost per ton sold of $19.95 in 2008. The reduction in unit cost experienced was driven by the full year of longwall production and operational efficiencies we achieved in 2009 relative to 2008. Our other mining operations were in the development stage during 2008 and 2009 and recorded no operating costs.

 

		For the Twelve Months Ended December 31,
		2009				2008
Cost of coal sales (in millions)		$	101.5			$	109.4
Tons sold (in millions)			5.6				5.5
Average cost of sales per ton sold (in millions)		$	18.02			$	19.95

Transportation Expense. Our costs of transportation expense in 2009 were $48.9 million, an increase of $2.0 million, or 4%, over our 2008 transportation expense of $46.9 million. This increase in transportation expense relates primarily to a change in the mix of sales to our customers and changes in required transportation to get our coal to the point of sale.

 

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Depreciation and Amortization. Our depreciation and amortization expenses for the year ended December 31, 2009, were $38.9 million, an increase of $11.1 million, or 40%, over our depreciation and amortization expenses for the year ended December 31, 2008 of $27.9 million. The higher expense in 2009 was principally due to the increase in capital expenditures we made across all our mines in 2009 and change in the classification of the Macoupin mining complex into the production phase.

Selling, General and Administrative. Our selling, general and administrative expense for the year ended December 31, 2009 was $22.6 million, an increase of $10.7 million, or 90%, over our selling, general and administrative expense for the year ended December 31, 2008 of $11.9 million. The higher expense in 2009 was principally due to the higher administrative cost of managing additional mining projects as we commenced construction of our Hillsboro and Sugar Camp mines and transaction costs relating to our acquisition of the Macoupin mine in 2009.

Gain On Coal Sale Contract Termination. In 2008, we experienced a one-time gain of $44.0 million relating to the negotiated early termination of a coal sales contract by one of our customers. We did not have any customers terminate any contracts with us in 2009 that resulted in similar payments to us.

Interest Expense. Our interest expense in 2009 was $46.5 million, an increase of $2.9 million, or 7%, over our 2008 interest expense of $43.6 million. The increase in interest expense was largely due to the interest component of the sale-leaseback financing arrangement at Macoupin which occurred in January 2009. This transaction resulted in an additional non-cash interest expense of $8.9 million in 2009 and lease minimums reclassified as interest of $10.3 million. There were no comparable expenses in 2008. We encourage you to read the footnotes to our consolidated financial statements to learn more about this transaction. Additional increases in interest expense in 2009 relative to 2008 resulted directly from our increased borrowings.

Income Taxes. In 2009, we distributed $47.6 million to the owners of Foresight Reserves as reimbursement for tax liabilities generated by the sale of coal reserves acquired in 2009 as a part of our Macoupin acquisition. We encourage you to read the footnotes of our financial statements to learn more about this transaction. We made no tax distributions to the owners of Foresight Reserves in 2008. This tax distribution in 2009 was recorded as a distribution on our statement of members’ equity and was not on our income statement.

Other Income (Expense). We had other income in 2009 of $3.2 million, a $3.5 million increase over other expenses of $0.3 million we incurred in 2008. The additional income we received in 2009 related to the salvage and gain on the subsequent sale of underground mining equipment that we recovered during our rehabilitation of the Macoupin mine efforts in 2009.

Net Income or Loss From Continuing Operations. We reported net income from continuing operations of $14.1 million in 2009, a $29.9 million reduction in net income from continuing operations in 2008 of $43.9 million, due to the factors stated above.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and service our debt. Historically, our primary sources of liquidity have been committed capital contributions from Foresight Reserves, borrowings under committed financing arrangements, and cash flow from operations

Following completion of this offering, we expect our sources of liquidity to include cash generated by our operations, borrowings under our credit agreement and issuances of equity and debt securities. Furthermore, following the completion of this offering, we will make a minimum quarterly distribution of $             per

 

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common unit per quarter, which equates to $             million per quarter, or $             million per year, based on the number of common units to be outstanding immediately after completion of this offering, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses. Please read “Distribution Policy and Restrictions on Distributions.”

Cash Flows

Net cash provided by operating activities was $45.4 million for the nine months ended September 30, 2011, compared to net cash used of $62.8 million in the same period of 2010. The increase in cash provided by operations was due to increases in our net income from the factors identified above. Net cash used in investing activities was $242.5 million for the nine months ended September 30, 2011, compared to $171.7 million in the same period of 2010. The increase in cash used reflected more capital expenditures in 2011 to bring Hillsboro and Sugar Camp closer to production.

Net cash provided by financing activities was $186.1 million for the nine months ended September 30, 2011, compared to $200.3 million in the same period of 2010. The decrease was due to reduced member contributions and the net of proceeds and repayments of note and equipment loans.

As of September 30, 2011, we had cash of $22.4 million and $37.0 million available capacity on our Senior Secured Credit Facility, compared to cash of $14.0 million and $211.5 million available capacity on our Senior Secured Credit Facility as September 30, 2010.

Net cash provided by operating activities was $32.0 million for the twelve months ended December 31, 2010, compared to net cash provided of $107.4 million in the same period of 2009. The decrease in cash provided by operations was a result of the discontinued operations of the company. Net cash used in investing activities was $250.0 million for the twelve months ended December 31, 2010, compared to $408.7 million in the same period of 2009. The decrease in cash used reflected fewer capital expenditures and purchases of available for sale securities in 2009.

Net cash provided by financing activities was $203.5 million for the twelve months ended December 31, 2010, compared to $329.6 million in the same period of 2009. The decrease in cash from financing activities was primarily due to the repayment of notes and equipment loans with proceeds from our debt offering in 2010 and proceeds from the sale-leaseback financing transaction in 2009.

As of December 31, 2010, we had cash of $33.5 million and $189.0 million in available capacity under our Senior Secured Credit Facility, compared to cash of $33.5 million and $29.9 million in available capacity under on our credit facilities as of December 31, 2009.

Net cash provided by operating activities was $107.4 million for the twelve months ended December 31, 2009, compared to net cash provided of $75.6 million in the same period of 2008. The increase in cash provided by operations was primarily due to a positive change in working capital. Net cash used in investing activities was $408.7 million for the twelve months ended December 31, 2009, compared to $198.1 million in the same period of 2008. The increase in cash used reflected a net increase in capital expenditures and a net increase in purchases of available for sale securities.

Net cash provided by financing activities was $329.6 million for the twelve months ended December 31, 2009, compared to $135.4 million in the same period of 2008. The increase was mainly due to cash received in a sale-leaseback financing transaction at our Macoupin mine compared to the twelve months ended December 31, 2008.

As of December 31, 2009, we had cash of $14.8 million and $29.9 million available capacity on our credit facilities, compared to cash of $3.6 million as of December 31, 2008.

 

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Capital Expenditures

We continue to make significant capital expenditures at Sugar Camp and Hillsboro and in our transportation infrastructure as we complete the development of those projects. We anticipate funding these capital expenditures through our existing credit facilities, from current operations’ cash flow and existing member contributions. The following is a summary of our estimated remaining construction capital expenditures for these projects in the next twelve months:

 

		Budgeted Construction Capital to be Spent As of September 30, 2011
		($ in millions)
Sugar Camp Energy		$	38.1
Hillsboro Energy			56.3
Transportation			17.7
Total		$	112.1

Financing Arrangements

Senior Secured Credit Facility

On December 15, 2011, we amended and restated our four-year revolving credit agreement providing for up to $400.0 million of borrowings with various financial institutions. Borrowings under the credit facility will bear interest at floating rates based on a Eurodollar rate or a bank base rate, at our election, plus applicable margins that are determined by reference to a pricing matrix based on our debt to EBITDA ratios as defined in the agreement. The revolving credit agreement expires on August 12, 2014. At September 30, 2011, $246.0 million had been drawn and $2.0 million reserved for letters of credit leaving additional available borrowing capacity of $37.0 million.

Sugar Camp Longwall Financing Arrangement

On January 5, 2010, we entered into a credit agreement with various financial institutions which provides financing for a longwall mining system and related parts and accessories of up to $83.4 million toward the $98.1 million estimated cost of the longwall mining system. The financing is secured by the assets purchased with the proceeds of this credit agreement. In addition, the financing agreement provides for financing of 100% of the loan fees estimated at $4.9 million and for financing 100% of $9.4 million of eligible interest on the loan during the construction of the longwall mining system. The loan provides a total commitment of approximately $97.8 million. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semi-annually beginning September 30, 2010 unless considered as eligible interest as noted above. Principal repayments are due semi-annually at the first semi-annual date occurring after the commercial operation date (estimated to be December 31, 2011). Principal is to be repaid in equal semi-annual payments over eight years starting on the first semi-annual date. At September 30, 2011, $87.0 million had been drawn.

Hillsboro Longwall Financing Arrangement

On May 14, 2010, we entered into a credit agreement with various financial institutions which provides financing for a longwall mining system and related parts and accessories of up to $77.3 million toward the $91.0 million estimated cost of the longwall mining system. The financing is secured by the assets purchased with the proceeds of this credit agreement. In addition, the financing agreement provides for financing of 100% of the loan fees estimated at $4.5 million and for financing 100% of $7.5 million of eligible interest on the loan during the construction of the longwall mining system. The loan provides a total commitment of approximately $89.3 million. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semi-annually beginning January 2011, unless considered as eligible interest as noted above. Principal repayments are due semi-annually

 

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at the first semi-annual date occurring after the commercial operation date. Principal is to be repaid in equal semi-annual payments over eight years starting on the first semi-annual date. At September 30, 2011, $76.1 million had been drawn.

Senior Notes

On August 12, 2010, we completed a $400.0 million senior unsecured notes offering. The financing agreement calls for interest payments at 9.625% to be made semi-annually each February 15 and August 15 beginning on February 15, 2011, with the entire principal balance due on August 15, 2017. Proceeds from the financing transaction were used to pay off a large portion of Foresight Energy LLC’s then existing indebtedness.

Sale-Leaseback Financing Arrangement

As of September 30, 2011, we carried an outstanding balance of $143.5 million relating to the sale-leaseback financing of certain coal reserves at Macoupin. The proceeds of this transaction were used to fund our capital needs at Macoupin.

Loan Covenants

The guaranty agreements between us and the lender under each of the Sugar Camp Longwall Financing Arrangement and Hillsboro Longwall Financing Arrangement contain certain financial covenants that require, among other things, maintenance of minimum amounts and compliance with debt service coverage and leverage ratios. We met the required financial covenants on September 30, 2011 and we believe we are currently in compliance. In addition, our other financing arrangements include customary covenants with which we believe we are in compliance.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications and financial instruments with off-balance sheet risk, such as performance or surety bonds and bank letters of credit. Liabilities related to these arrangements are not reflected in our Consolidated Balance Sheets. However, the underlying obligations that they secure, such as self-insured workers compensation liabilities, royalty obligations, and asset retirement obligations are reflected in our Consolidated Balance Sheets where appropriate.

As of September 30, 2011, Foresight Reserves held outstanding surety bonds for the benefit of Foresight Energy LLC and its subsidiaries with a total face amount of $37.4 million, consisting of $10.3 million for Williamson, $10.8 million for Hillsboro, $7.9 million for Sugar Camp, $8.3 million for Macoupin, and $0.2 million for Savatran. In addition, we had $2.0 million of letters of credit in place for credit support on a coal sales transaction.

 

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Contractual Obligations

The following is a summary of our significant future contractual obligations by year as of September 30, 2011:

 

		Total				Less than 1 year				1-3 years				4-5 years				More than 5 years
Principal repayments on long-term debt(1)		$	809,811			$	10,194			$	307,167			$	440,778			$	50,972
Interest related to long-term debt(1)			277,066				47,677				137,744				86,233				5,412
Operating lease obligations			14,023				3,292				10,731				—				—
Coal and surface leases and overriding royalties(2)			1,026,253				68,667				215,001				143,334				599,251
Construction capital expenditure obligations(3)			62				62				—				—				—
Total		$	2,126,515			$	129,892			$	670,643			$	670,345			$	655,635

 

(1)	Excludes payments on the sale-leaseback financing arrangements, but includes Sugar Camp and Hillsboro longwall financing arrangements, our Senior Secured Credit Facility and our 9.625% senior unsecured notes due 2017.

(2)	See description of agreements under “—Coal and Surface Leases and Overriding Royalties” below. Includes payments due on the sale-leaseback financing arrangement.

(3)	We have contractual obligations to make $62.2 million of construction capital expenditures and expect, but are not contractually obligated, to make $49.9 million of capital expenditures, at Sugar Camp, Hillsboro and Macoupin, and to complete our logistics projects.

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.

Williamson

Williamson 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 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 has the option to buy the Savatran rail spur for its fair value as determined by an independent appraiser.

Williamson has a coal mining lease agreement with Independence, owned by NRP, a related party. 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 is required to pay Independence the greater of 9.0% of the gross selling price or $2.85 per ton for the coal mined from the leased premises. In addition to the tonnage royalty, Williamson is required to pay a quarterly minimum royalty of $416,750 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 with limitations as outlined in the lease. 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 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

 

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mined from certain mineral reserves identified in the agreement that Williamson 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 has coal mining lease agreements with WPP, an affiliate of NRP, a related party. 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 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 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 with limitations as outlined in the lease. 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.

As part of the 2010 Reorganization, Williamson leased 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 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 on future tons mined with limitations as outlined in the agreement, is as follows:

 

For calendar year 2011		$	500,000
For calendar year 2012		$	500,000
For calendar year 2013 and thereafter		$	2,000,000

Hillsboro

Hillsboro entered into a coal mining lease agreement on September 10, 2009, with WPP. Hillsboro 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 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 paid a minimum royalty of $3,100,000 on April 20, 2010, covering the period of January 1, 2010 through March 31, 2010. Thereafter, for the remaining three calendar quarters in 2010 and the four calendar quarters of 2011, the quarterly minimum royalty will be $3,100,000 due and payable in July, October, January, and March for the prior quarter’s production. Thereafter, beginning with the quarterly minimum royalty due April 20, 2012, the quarterly minimum royalty is $7,500,000 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 with limitations as outlined in the lease.

As part of the 2010 Reorganization, Hillsboro leased coal reserves from Colt, LLC, 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 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 on future tons mined with limitations as outlined in each lease, is as follows:

 

For calendar year 2011		$	600,000
For calendar year 2012		$	1,000,000
For calendar year 2013 and thereafter		$	4,000,000

 

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Macoupin

In January 2009, NRP acquired additional coal reserves and infrastructure assets related to our Macoupin mine for $143.7 million. Simultaneous with the closing, Macoupin 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 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 is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order.

As part of the 2010 Reorganization, Macoupin leased coal reserves from Colt, LLC, 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 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 on future tons mined with limitations as outlined in each lease, is as follows:

 

For calendar year 2011		$	500,000
For calendar year 2012		$	500,000
For calendar year 2013 and thereafter		$	2,000,000

Sugar Camp

In 2005, Sugar Camp entered into a mineral lease with RGGS Land & Mineral 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 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 $4.008 million in 2010 and 2011 then reduces to $2.004 million for the remainder of the primary term.

As part of the 2010 Reorganization, Sugar Camp leased 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 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.

As part of the 2010 Reorganization, Sugar Camp entered into two overriding royalty agreements with Ruger pursuant to which Sugar Camp is given the right to mine certain reserves controlled by Ruger as lessee. Pursuant to these overriding royalty agreements, the total royalty that Sugar Camp will be required to pay for each ton of coal mined is equal to the difference between (i) the actual production royalty paid by Sugar Camp to the lessor of the reserves under the leases assumed by Sugar Camp from Ruger and (ii) the amount which is equal to 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 on future tons mined with limitations as outlined in each lease, is as follows:

 

For calendar year 2011		$	150,000
For calendar year 2012		$	250,000
For calendar year 2013 and thereafter		$	1,000,000

 

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Transportation Infrastructure

As part of the 2010 Reorganization, Foresight Reserves contributed Savatran (which also owns the Williamson Track rail spur) and Sitran to Foresight Energy LLC. In exchange, Foresight Energy LLC caused each of Williamson, Sugar Camp, Hillsboro and Macoupin to enter into Surface Lease and Transportation Agreements with Savatran and Sitran. Those agreements are described in “Business—Transportation.” Foresight Energy LLC further caused each of Savatran and Sitran to pay over all sums collected prior to the 2010 Reorganization under the Surface Lease and Transportation Agreements to Foresight Reserves.

Other Leases

We lease office space under various leases with monthly payments that expire during January of 2013 and January of 2017. We also lease railcars from various companies that require monthly payments. These leases expire at different times from July 30, 2012 through December 31, 2014, and are customarily removed and/or replaced.

Quantitative and Qualitative Disclosure 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 are commodity price risk and interest rate risks.

Commodity Price Risk

We have commodity price risk as a result of changes in the market value of our coal. We try to manage that risk by entering into fixed priced coal supply agreements and various commodity hedge agreements. As of September 30, 2011, approximately 78% of our expected coal production in 2012 was sold or committed under contracts. We have two coal purchase and sale commodity contracts.

Interest Rate Risk

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At September 30, 2011, of our $806.9 million principal amount of debt outstanding, $246.0 million of outstanding borrowings have interest rates that fluctuate based on changes in the market rates. A one percentage point increase in the interest rates related to those borrowings would result in an annualized increase in interest expense of $2.5 million.

Credit Risk

We have credit risk associated with our customers/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. Credit losses are provided for in the financial statements and have historically been minimal.

 

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BUSINESS

We are a low cost producer of high quality thermal coal with expertise in operating and developing highly productive underground mines in the Illinois Basin. We have invested over $1.5 billion in four mining complexes with long reserve lives which we believe will provide us with significant sustainable free cash flow. We have significant near-term and long-term growth opportunities through our approximately 3 billion tons of coal reserves. We believe our first operation, Williamson, was the most productive underground coal mine in the United States for the fourth quarter of 2011 on a clean tons produced per man hour basis. Our leading productivity translates into low costs, and we believe we are the lowest cost underground coal producer in the United States at $19.41 per ton in 2010. We have developed infrastructure to provide each mining complex with multiple transportation options, providing widespread cost competitive access to both domestic and international markets. We believe we are among the largest United States exporters of thermal coal, and in recent years, we have exported approximately 33% of our coal to Europe, South America, Africa and Asia.

Our four mining complexes (Williamson, Sugar Camp, Hillsboro and Macoupin) are designed to support up to 8 longwall mining systems, giving them a combined productive capacity of up to 65 million tons of high Btu coal per year. We currently operate one longwall system at Williamson and plan to commence one longwall system at each of Sugar Camp and Hillsboro in the first nine months of 2012, having already invested most of the expansion capital necessary to develop these mines. Longwall mining is a highly-automated, underground mining technique that enables high volume, low cost operations. Our approximately 3 billion tons of reserves consist of three large contiguous blocks of coal, each benefiting from thick seams and roof and floor geology favorable for longwall mining. The geology, mine plan, equipment and infrastructure at each of Sugar Camp and Hillsboro are relatively similar to Williamson and we anticipate similar productivity at these complexes.

We sell a significant portion of our coal under long-term 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, as well as the seaborne thermal coal market. For 2012, 2013 and 2014, we have secured coal sales commitments for approximately 12.8 million tons, 14.0 million tons and 11.7 million tons, respectively, of which all in 2012, approximately 9.2 million tons in 2013 and approximately 5.3 million tons in 2014 are priced. The following table describes our contracted position for 2012, 2013 and 2014 as of January 31, 2012:

 

		2012								2013								2014
		Tons				Price				Tons				Price				Tons				Price
Committed and priced			12.8			$	58.13				9.2			$	61.08				5.3			$	69.18
Committed and unpriced			0								4.8								6.4

We have developed infrastructure that provides each of our mining complexes with multiple transportation outlets and have direct and indirect access to all five Class I railroads giving us unique access to multiple domestic and seaborne markets. We control a seaborne export terminal in Louisiana and a barge-loading river terminal on the Ohio River. We have numerous contractual arrangements with railroads and river terminals giving us long-term access with price certainty. This logistical advantage gives us the flexibility to direct shipments to the markets that offer the price necessary to achieve the highest margin for our coal.

 

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Since our inception, we have invested over $1.5 billion in our four mining complexes and related transportation infrastructure. This significant initial investment included infrastructure and design that we believe will enable us to maintain productivity levels from the initial development over a sustained period of time and allow expansion of production more quickly and more cost effectively than greenfield mine developments. We plan to take advantage of this initial development strategy and additional longwall mining systems in the upcoming years to grow our production. The table below outlines our mining complexes:

 

		Williamson				Sugar Camp				Hillsboro				Macoupin				Total
Mine Type			Longwall				Longwall				Longwall				Continuous Miner
Number of Potential Longwalls(1)			1				4				3				—				8
Short tons in millions:
Coal Reserves(2)			396				1,328				879				360				2,964
2010 Production(2)			5.8				0.3				0.02				1.0				7.2
First Nine Months of 2011 Production(3)			5.6				0.6				0.3				1.4				7.9
Long-term Potential Productive Capacity(4)			7				28				27				3				65

 

(1)	Represents total number of longwall mining systems that could be deployed, including the one currently in operation at Williamson. We plan to have one longwall mining system in operation at each of Williamson, Sugar Camp and Hillsboro in the first nine months of 2012.

(2)	See “Coal Reserve Information” for more information.

(3)	For the nine months ended September 30, 2011, as reported by MSHA.

(4)

Annual productive capacity is an estimate of the design 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 two 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.

In 2010, we produced 7.2 million tons of coal, and during the first nine months of 2011, we produced 7.9 million tons of coal. For the twelve months ended September 30, 2011, we produced 9.6 million tons of coal and generated revenues of $475.4 million and Adjusted EBITDA of $178.9 million. For the year ended December 31, 2010 and the nine months ended September 30, 2011 we generated $7.9 million and $50.6 million of net income, respectively. See note 3 of “Prospectus Summary—Summary Historical Consolidated Financial and Other Information” for a reconciliation of net income to Adjusted EBITDA.

Our Strategy

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

Maintaining industry-leading cost structure and high productivity. 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 significantly increase when Sugar Camp and Hillsboro commence longwall operations during the first nine months of 2012. Nearly all the expansion capital has been spent at each project and both are producing and selling development coal. We have a visible pipeline of additional growth projects beyond these two longwalls to further develop our vast reserve base.

 

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Securing a stable revenue base. We intend to expand our portfolio of long-term coal supply agreements to increase the stability of our operating cash flows and mitigate the effects of coal price volatility.

Maintain and enhance our transportation and logistics network. We will continue to develop assets and infrastructure to ensure that we have low cost transportation options to reach existing and new customers and markets for our coal and thereby maximize the margin of our coal sales.

Maintaining a diverse and high-quality customer base. We have sold coal or are currently selling coal to 46 different customers and end users in 16 states and 12 countries around the world.

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 selections and operating processes. We will continue to work with equipment manufacturers to make mining equipment and the 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.

Our Strengths

Industry-leading productivity driving low costs and attractive margins. Our leading productivity derives from a combination of attractive geology, innovative mine design, a highly motivated and skilled workforce, automated longwall mining systems and significant investment in infrastructure. We believe Williamson was the most productive underground coal mine in the United States for the fourth quarter of 2011 on a clean tons produced per man hour basis. This high productivity results in low operating costs. During the first nine months of 2011, our consolidated cash costs of production were $18.68 per ton, which we believe makes us the lowest cost underground producer in the United States. Our low costs drive margins that are among the highest in the U.S. coal industry, and in the first nine months of 2011, we generated $25.98 cash margin per ton. Our high productivity and low costs position us to outperform our competitors and generate positive cash flow in all coal market conditions. Given our favorable cost position, we believe our coal will remain competitive and retain its position as base load fuel for our customers.

Significant near-term production growth enabled by over $1.5 billion of capital already invested. We plan to commence new longwall mining operations at each of Sugar Camp and Hillsboro in the first nine months of 2012, which we expect will significantly increase our coal production. At each of these two complexes, we are currently producing coal from continuous miners, and the underground and surface facilities are already largely constructed. At full run rate, each of these longwalls has a targeted productive capacity of at least 7 million tons per year. Sugar Camp and Hillsboro are designed to provide us with organic growth opportunities for subsequent years by adding additional longwall mining systems to the same complexes. Because we have already made the significant investment in large scale surface and underground infrastructure, our growth from these complexes will have shorter lead time and lower costs than greenfield development, which will enable us to generate incremental cash flows.

Portfolio of sales contracts at attractive prices 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. For 2012, 2013 and 2014, we have secured coal sales commitments for approximately 12.8 million tons, 14.0 million tons and 11.7 million tons, respectively, of which all in 2012, approximately 9.2 million tons in 2013 and approximately 5.3 million tons in 2014 are priced.

Broad domestic and export market access through a variety of transportation options allows us to maximize margins. We complement our low cost mining operations with competitive low cost transportation options to the domestic and international markets. Our mines are attractively positioned in close proximity to railroads and rivers and we have developed transportation optionality for each of our mining complexes. We have direct and indirect access to all five Class I rail lines. We also control a seaborne export terminal in Louisiana

 

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and a barge-loading river terminal on the Ohio River. We have long-term contractual access to two additional barge-loading river terminals on the Ohio and Mississippi Rivers. In order to protect access to these transportation options, we have entered into agreements with terms up to 10 years. Across all transportation options, we currently have 7 million tons of seaborne coal throughput capacity per year, and plan to increase capacity to 10 million tons of seaborne coal throughput per year in the near-term and 18 million tons of seaborne coal throughput per year in the long-term without investing significant additional capital. This broad market access enables us to maximize prices and margins realized for our coal sales.

Large, contiguous, high quality reserve base supports long mine lives and efficient, economic production expansion. We control approximately 3.0 billion tons of coal reserves, which we believe ranks us 5th among public companies in the United States and 10th among public companies globally. Almost all of our reserves are found 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 and enables us to utilize the same infrastructure to support future growth. This reduces the need to continually spend development capital for greenfield infrastructure, such as slopes, shafts and basic surface facilities, in order to maintain and grow production levels.

Best-in-class management capabilities. Our chairman 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 efficient mine design and planning, increasing productivity, reducing costs, building infrastructure, implementing our marketing strategy and safe mining operations. In addition to their operating strengths, our senior executives have experience in identifying, acquiring, financing and integrating relevant businesses that will enhance the value of our assets.

Coal Market Overview

Coal remains an in-demand, cost-competitive energy source relative to alternative fossil fuels and other alternative energy sources. Growth in domestic electricity demand continues to drive demand for thermal coal. According to the EIA, total United States electricity consumption is expected to grow by 13.0% from 2010 to 2025. Coal will continue to remain a critical component of power generation, with coal-powered electricity expected to grow by 11% during this period. Coal, particularly coal produced in the Illinois Basin, has historically been a low-cost source of energy relative to its substitutes because of the high prices for alternative fossil fuels. Coal also has a lower all-in cost relative to other alternative energy sources, such as nuclear, hydroelectric, wind and solar power.

Demand for Illinois Basin coal is growing in the U.S. Many domestic utilities have installed or are planning to install scrubbers, which is expanding the market for high sulfur coal from the Illinois Basin and the Northern Appalachian region. According to Wood Mackenzie estimates, 198 GWs, or 63% of total capacity, of electric generating units in the United States was scrubbed in 2011. Wood Mackenzie expects scrubbed capacity to increase to 268 GWs, or 100% of total capacity, by 2025. In addition, Wood Mackenzie forecasts domestic Illinois Basin demand increasing by over 75 million tons within the next 15 years, with much of the demand deriving from the southeastern and midwest regions. Shortages and decreases in supply in the eastern United States continue to affect pricing in the entire United States market.

Expected long-term increases in international demand and the United States export market. We believe that the Pacific Basin demand for global seaborne thermal coal will increase in the near-term and create a shortfall in the Atlantic Basin supply, as quantities of thermal coal from traditional European and South African suppliers shift to Asia over the decade. This will create growing export opportunities for United States and South American producers to export to coal-fired plants in Europe.

 

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

Operational History

Our operations and adjacent reserves are located in the Illinois Basin in southern and central Illinois. We control approximately 3 billion tons of proven and probable coal reserves with a heat content range of 10,700 to 11,980 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.

Williamson, Sugar Camp and Hillsboro use longwall mining systems. 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.

 

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The table below summarizes our operations, mining methods, transportation, reserves and productive capacity.

 

Complex		Location(1)				Mining Methods(2)				Transportation Access(3)		Proven and Probable Reserves				Productive Capacity(4)				Production
																				Year Ended December 31, 2010				Nine Months Ended September 30, 2011
												(tons in millions)
Williamson			SILB				LW, CM			Rail (CN), Barge (OHR, MSR), Truck			396				7				5.8				5.6
Sugar Camp			SILB				LW, CM			Rail (CN, NS, CSX, BNSF), Barge (OHR, MSR), Truck			1,328				28				0.3				0.6
Hillsboro			CILB				LW, CM			Rail (UP, NS), Barge (OHR, MSR), Truck			879				27				0.02				0.3
Macoupin			CILB				CM			Rail (UP, NS), Barge (OHR, MSR), Truck			360				3				1.0				1.4
Total													2,964				65				7.2				7.9

 

(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)

Annual productive capacity is an estimate of the design 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 two 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.

Williamson Mining Complex

Our Williamson mining complex 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, 2010, Williamson’s assigned reserve base contains approximately 396 million tons of clean recoverable proven and probable coal with an average heat content of 11,832 Btus per pound. Permitting for Williamson began in March 2004 and construction began in July 2005 following receipt of the permit. 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 March 2008. Williamson was designed for an annual productive capacity of approximately 7 million tons.

Williamson operates in the Herrin No. 6 Seam, using two continuous miner units to develop the mains and gate roads for its longwall panels which we believe are among the longest and widest in the industry. 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 22,000 feet and have seam height of approximately 6 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

 

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domestic thermal market or to New Orleans to serve the international market. Williamson maintains throughput agreements at several barge and vessel loading facilities on the Ohio and Mississippi Rivers and in New Orleans.

Williamson 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, 2011, Mach employed 167 workers at our Williamson mine complex, 125 of which worked underground. Mach maintains a bonus program for its employees to promote safety and productivity.

We believe Williamson was the most productive underground coal mine in the United States in the fourth quarter of 2011 on a clean tons produced per man hour basis.

Williamson leases some of its coal reserves from a subsidiary of NRP as a result of transactions in 2005 and 2006, where we sold these reserves to NRP’s subsidiary and leased them back. Proceeds from this transaction were used to capitalize the mine during construction. 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

Our Sugar Camp mining complex is wholly-owned by our subsidiary Sugar Camp Energy, LLC. As of January 1, 2010, its assigned reserve base contains approximately 1,328 million tons of clean recoverable proven and probable coal with an average heat content of 11,722 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. Development of the gate roads for the first longwall panel is progressing and the longwall is expected to begin production in the first quarter of 2012. The first longwall panels mined are planned to be 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 6 feet.

Sugar Camp operates in the same Herrin No. 6 Seam, and uses a similar mine design and most of the same equipment as Williamson. We therefore expect that each longwall at Sugar Camp will achieve the same high volume of production and productivity as the Williamson longwall. Certain of Sugar Camp’s infrastructure including its bottom development, slope belt, material handling system and rail loadout were designed to support multiple longwalls. This will enable Sugar Camp to expand its production through the installation of additional longwall mining units at incremental costs compared to a greenfield mine. Sugar Camp is expected to have an annual productive capacity of approximately 12 to 14 million tons when its first two longwall mining systems begin operations.

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

Sugar Camp 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, 2011, M-Class employed 169 workers at our Sugar Camp mining complex, 150 of which worked underground. M-Class maintains a bonus program for its employees to promote safety and productivity.

Sugar Camp leases its reserves from RGGS Land and Mineral, LTD, LP, Ruger and TVA.

 

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Hillsboro Mining Complex

Our Hillsboro mining complex is wholly-owned by our subsidiary Hillsboro Energy LLC. As of January 1, 2010, its assigned reserve base contains approximately 879 million tons of clean recoverable proven and probable coal with an average heat content of 10,961 Btus per pound.

Permitting began in July 2006, and construction began in May 2009. Hillsboro’s slope reached the coal seam at a depth of approximately 450 feet in October 2010. Gate road development for the first longwall panels to be mined has begun and longwall production is expected to commence during the third quarter of 2012. The first longwall panels mined are planned to be 1,400 feet wide. The panel lengths are approximately 15,000 feet and have seam height of approximately 7.37 feet.

Hillsboro will operate in the same Herrin No. 6 Seam, and use the same mine design and essentially the same 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 will use a larger shearer and thus we currently expect that the production and productivity at Hillsboro will surpass that at Williamson. Hillsboro is designed for an annual productive capacity of approximately 7 to 9 million tons.

Coal will be washed at Hillsboro’s preparation plant, stockpiled and then shipped by rail or truck to market. Hillsboro has direct access to the UP railroad 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. We are developing additional transportation infrastructure that will ultimately give Hillsboro access to the NS railroad, our river terminal on the Ohio River and an all rail access to New Orleans.

Hillsboro has a contract mining arrangement with Patton Mining LLC, a third party mining contractor. Patton will be paid on a cost-plus basis for coal that is produced and processed from Hillsboro’s mine. As of December 31, 2011, Patton employed 102 workers at our Hillsboro mining complex, 86 of which worked underground. Patton maintains a bonus program for its employees to promote safety and productivity. Hillsboro leases its reserves from Colt and from a subsidiary of NRP. See “Certain Relationships and Related Party Transactions.”

Macoupin Mining Complex

Our Macoupin mining complex is wholly-owned by our subsidiary Macoupin Energy LLC, and primarily includes the mining assets which we acquired from ExxonMobil Coal USA, Inc. on January 22, 2009. Macoupin’s assigned reserve base contains approximately 360 million tons of clean recoverable proven and probable coal in the Herrin No. 6 Seam with an average heat content of 10,958 Btus per pound. Following the acquisition from 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 was designed for an annual productive capacity of approximately 2 to 3 million tons.

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

Macoupin 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,

 

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2011, MaRyan employed 130 workers at Macoupin, 101 of which worked underground. MaRyan maintains a bonus program for its employees to promote safety and productivity.

Macoupin’s favorable geology, new mine layout, and efficient work force make it highly productive. We believe that during the fourth quarter of 2011, Macoupin was among the most productive underground coal mine operated with continuous miners in the United States.

In 2009, Macoupin sold 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 sold to them in 2009 in the same transaction. Macoupin 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 barge, rail 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 low and provide broad market access for our coal. When our various transportation infrastructure projects are complete, we will have spent approximately $115.0 million on rail spurs and coal loading terminals to create this optionality.

We currently have direct and indirect rail access to domestic customers via all 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 various agreements with rail carriers that vary in length from one to ten years. Approximately 44% of our 2010 coal sales volume was shipped to our domestic customers from our mines by barge, 32% to domestic customers by rail or truck and 23% was shipped to export terminals (primarily via rail) for shipment to international customers. 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.

We have constructed a high-capacity coal transloading facility on the Ohio River near Evansville, Indiana. The terminal will include the potential for a dual rail loop that will have capacity for two loaded and two empty unit trains, a bottom discharge rail car unloader, stacking tubes to facilitate ground storage and blending and both barge and rail loading capabilities.

On August 1, 2011, an affiliated company owned by Foresight Reserves acquired the IC Rail Marine Terminal from the Canadian National Railway Company, renamed the Convent Marine Terminal. It 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. The Convent Marine Terminal plans to expand its terminal to significantly increase capacity from 5 million to 8 million tons of coal throughput capacity per year in the near-term to 16 million tons of coal throughput per year in the long-term. Our subsidiary Savatran, a major customer of the terminal before the acquisition, has secured an expanded contract to allow for the eventual throughput of all of our coal production through the terminal. Savatran’s contract at the terminal 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.

These two terminals give us further control of our transportation logistics and broaden the market access for our coal.

 

 

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Coal Reserves

We estimate that we owned or controlled approximately 3 billion tons of proven and probable recoverable reserves at January 1, 2010. 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. Our coal reserve estimate is based on a January 1, 2010 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, our potential inability 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. We use various assumptions in preparing our estimates of our coal reserves. See “We face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability” contained in “Risk Factors.”

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 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.

 

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All of our recoverable coal reserves are assigned reserves that we expect to be mined at operations that were active as of January 1, 2010. We do not have any unassigned reserves. All of our reserves are considered high sulfur coal, with average sulfur content ranging between 1.82% and 3.33% and high Btu coal, with Btu content ranging between 10,958 and 11,980 Btu per pound. The following tables present our estimated recoverable coal reserves at January 1, 2010:

 

																														Theoretical Coal Quality (As Received Basis)
						Average Seam Thickness (Feet)				Area (Acres)				In-Place Tons(1) (000)				Clean Recoverable Tons(2) (000)												Sulfur (%)				Btu/lb
Property Control		Seam																Proven				Probable				Total
Williamson Energy, LLC			6				5.94				27,815				314,620				141,832				46,738				188,570				2.19				11,666
Williamson Energy, LLC			5				4.19				41,596				323,703				115,541				92,078				207,620				1.82				11,980
Sugar Camp Energy, LLC			6				6.32				102,261				1,223,182				343,666				414,695				758,361				2.44				11,716
Sugar Camp Energy, LLC			5				4.75				100,695				892,486				228,850				340,877				569,728				2.36				11,731
Hillsboro Energy LLC			6				7.37				100,711				1,414,578				273,842				605,621				879,463				3.33				10,961
Macoupin Energy LLC			6				7.03				45,708				605,582				197,230				162,876				360,106				2.65				10,958
Total—Foresight Energy LLC															4,774,151				1,300,962				1,662,886				2,963,848

 

(1)	In-Place Tons are on a Dry Basis.

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

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

Williamson

Williamson has a coal mining lease agreement with Independence, owned by NRP, a related party. The term of this agreement is through March 13, 2021 and can be renewed for additional five year periods until all merchantable and mineable coal has been mined and removed. Williamson is required to pay Independence the greater of 9.0% of the gross selling price or $2.85 per ton for the coal mined from the leased premises. In addition to the tonnage royalty, Williamson is required to pay a quarterly minimum royalty of $416,750 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 with limitations as outlined in the agreement. The agreement also has a provision for wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises. Williamson has an overriding royalty agreement with Independence. As such, Independence will receive an overriding royalty interest in the amount of $0.30 per ton for each ton of clean coal mined from certain mineral reserves identified in the agreement that Williamson 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 has coal mining lease agreements with WPP an affiliate of NRP. The agreements allow for the mining, processing, and transporting of coal reserves located in Illinois. The terms of the coal lease agreements include the requirement for Williamson to pay WPP minimum royalties, tonnage royalties based on the tonnage sold, and wheelage. The terms of these agreements are 15 years and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed. Williamson is 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

 

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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 with limitations as outlined in the agreement. Furthermore, the agreements provide for an overriding royalty of $0.10 per ton on the first 8.5 million tons mined from specific coal reserves outlined in the agreements. The agreements also have provisions for wheelage payable at 0.5% of the gross selling price when foreign coal is transported over the premises.

Williamson 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 is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. 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 agreement, is as follows:

 

For calendar year 2011		$	500,000
For calendar year 2012		$	500,000
For calendar year 2013 and thereafter		$	2,000,000

Hillsboro

Hillsboro leases some of its reserves from WPP. In 2009, Colt, an affiliate of Foresight Reserves, entered into a multi-step transaction to sell these and other reserves to WPP with WPP leasing them to Hillsboro. To date, five of the eight steps have been completed. Proceeds received by Colt from this transaction were used to capitalize the mine during construction. The reserves subject to this multi-step transaction but not yet sold to WPP are leased to Hillsboro by its affiliate Montgomery Mineral, LLC. No minimum payments are due under this lease and it is not anticipated that any coal will be produced from the reserves subject to this lease before these reserves are conveyed to WPP.

The primary term of the lease from WPP to Hillsboro is 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. Hillsboro is required to pay WPP the greater of 8.0% of the gross selling price or $4.00 per ton and a fixed royalty in the amount set forth in the agreement for the coal mined from the leased premises. Hillsboro paid a minimum royalty of $3,100,000 on April 20, 2010, covering the period of January 1, 2010 through March 31, 2010. Thereafter, for the remaining three calendar quarters in 2010 and the four calendar quarters of 2011, the quarterly minimum royalty was $3,100,000 due and payable in July, October, January, and March for the prior quarter’s production. Thereafter, beginning with the quarterly minimum royalty due April 20, 2012, the quarterly minimum royalty is $7,500,000 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 with limitations as outlined in the agreement.

As part of the 2010 Reorganization, Hillsboro leased 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 ten years with six renewal periods of five years each. Hillsboro is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. In addition to the tonnage royalty, the minimum royalty for each of these leases, which is recoupable on future tons mined with limitations as outlined in each lease, is as follows:

 

For calendar year 2011		$	600,000
For calendar year 2012		$	1,000,000
For calendar year 2013 and thereafter		$	4,000,000

 

 

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Macoupin

Macoupin leases certain coal reserves from WPP. The primary term is for 20 years and can be extended for additional five-year terms limited to six such renewals. The lease requires a royalty payment by Macoupin of the greater of (i) the sum of 8% of the gross selling price of the coal plus $0.60 per ton or (ii) $5.40 per ton, which is considered the tonnage royalty. In addition to the tonnage royalty, Macoupin paid a royalty in the amount of $10 million on October 20, 2009, covering the period of January 27, 2009 through September 30, 2009. Thereafter, beginning with the quarterly minimum royalty due on January 20, 2010, and ending on the earlier of the expiration of the twenty-year term or the removal of all the respective merchantable and mineable coal, the quarterly minimum royalty will be $4 million payable on the 20th of January, April, July, and October. Thereafter, the quarterly minimum royalty will be $2,500. The minimum royalty is recoupable on future tons mined with limitations as outlined in the agreement.

As part of the 2010 Reorganization, Macoupin leased additional 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. Hillsboro is required to pay the greater of $3.40 per ton or 8.5% of the gross sales price of such coal. In addition to the tonnage royalty, the minimum royalty for each of these leases, which is recoupable on future tons mined with limitations as outlined in each lease, is as follows:

 

For calendar year 2011		$	500,000
For calendar year 2012		$	500,000
For calendar year 2013 and thereafter		$	2,000,000

Sugar Camp

In 2005, Sugar Camp entered into a mineral lease with RGGS Land & Mineral 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 is required to pay the greater of a price per ton or a percentage of the gross sales price of such coal. 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 is the successor lessee to a mineral lease with the United States government acting by and through the Tennessee Valley Authority dated July 15, 2002. The primary term of this lease is for ten years with automatic extension under conditions described in the lease. Sugar Camp is required to pay the greater of a price per ton or a percentage of the gross sales price of such coal. 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 $79,843 per year.

As part of the 2010 Reorganization, Sugar Camp entered into two overriding royalty agreements with Ruger pursuant to which Sugar Camp is given the right to mine certain reserves controlled by Ruger as lessee. Pursuant to these overriding royalty agreements, the total royalty that Sugar Camp will be required to pay for each ton of coal mined is equal to the difference between (i) the actual production royalty paid by Sugar Camp to the lessor of the reserves under the leases assumed by Sugar Camp from Ruger and (ii) the amount which is equal to 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 on future tons mined with limitations as outlined in each lease, is as follows:

 

For calendar year 2011		$	150,000
For calendar year 2012		$	250,000
For calendar year 2013 and thereafter		$	1,000,000

 

 

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As part of the 2010 Reorganization, Sugar Camp leased 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 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.

Transportation

Macoupin 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 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 may purchase the premises for the then fair market value as determined by an independent appraiser.

Coal Sales Contracts

Approximately 78% of our expected coal production in 2012 has been committed under contracts. Our primary 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. We derived approximately 64% and 47% of our total coal revenues from our five largest customers for the year ended December 31, 2010 and the nine months ended September 30, 2011, respectively.

The international thermal coal market has 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 three years we have exported approximately 33% of our coal into these international markets. We currently have 11.9 million tons of coal committed to these international markets under sales agreements that range from one to four years.

Our management and sales force actively monitors trends in contract pricing and seeks to enter into long-term coal sales contracts at favorable prices. Many of our contracts allow us to substitute coal from other facilities. For 2012, we have 12.8 million tons of our projected production under contract with 25 separate customers. The following table describes our contracted position for 2012 and 2013 as of September 30, 2011:

 

		2012								2013
		Tons				Price				Tons				Price
Domestic Coal Sales
Committed and priced			12.8			$	58.13				9.2			$	61.08
Committed and unpriced			0								4.8

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.

Our contracts typically specify minimum and maximum quality specifications regarding the coal to be delivered. 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.

 

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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.

Quality and volumes for the coal are stipulated in coal supply agreements and, in some instances, buyers have the option to vary annual or monthly volumes. 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, hardness, chlorine and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.

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 Patriot Coal Corporation, Peabody Energy Corporation, Alliance Resource Partners, L.P., Murray Energy 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 and steel industries 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 delivered price, coal quality characteristics and reliability of supply.

Employees and Labor Relations

We are managed and operated by the directors and officers of our general partner. Foresight Energy Services employs         % of Foresight Energy LLC’s personnel. Each of the Williamson, Macoupin, Sugar Camp and Hillsboro mines has a contract in place for all aspects of their respective mine operations. Similarly, each of Savatran and Sitran has a contract in place for all aspects of the operation of their assets. As of December 31, 2011, through our contracts described below, we had approximately 568 contract employees throughout our operations. None of our operations have employees (contract or otherwise) represented by a union.

Williamson

Williamson has a contract with Mach pursuant to which Mach provides contract labor for the mining and processing of all coal produced at the Williamson mine on a cost-plus basis. Mach is an unaffiliated entity but consolidated for accounting purposes.

 

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Sugar Camp

Sugar Camp has a contract with M-Class pursuant to which M-Class provides contract labor for the mining and processing of all coal produced at the Sugar Camp mine on a cost-plus basis. M-Class is an unaffiliated entity but consolidated for accounting purposes.

Hillsboro

Hillsboro has a contract with Patton Mining pursuant to which Patton Mining provides contract labor for the mining and processing of all coal produced at the Hillsboro mine on a cost-plus basis. Patton Mining is an unaffiliated entity but consolidated for accounting purposes.

Macoupin

Macoupin has a contract with MaRyan Mining pursuant to which MaRyan provides contract labor for the mining and processing of all coal produced at the Macoupin mine on a cost-plus basis. MaRyan Mining is an unaffiliated entity but consolidated for accounting purposes.

Sitran and Savatran

Savatran has contracts with numerous coal transloading facilities to transfer coal produced by us from railcars to barges for shipment to our customers. Savatran also contracts with rail service and maintenance companies to operate and maintain its rail spurs connecting our mines to the main rail lines servicing those mines.

Sitran has a contract with Coalfield Construction LLC pursuant to which Coalfield Construction provides contract labor for the contracts for the operation and maintenance of a coal transloading dock on the Indiana side of the Ohio River to load coal delivered from our mines via the Evansville Western Railway onto barges for delivery to our customers.

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, exposure to hazardous substances, environmental remediation, employment and contract disputes, and other claims and actions arising in the ordinary course of business.

In March 2009, Sierra Club, two citizens groups and 12 individuals filed Requests for Administrative Review of Hillsboro’s Deer Run Mine SMCRA Permit No. 399, the principal operating permit for the mine. The Petitioners have asked for reconsideration of issuance of the SMCRA permit on several grounds, including environmental impacts of the mine operations on the community of Hillsboro, impact on property values and enjoyment of lands owned in the vicinity, loss of groundwater and issues of mine operations’ impacts on the area environment, as well as adverse effects on streams and other surface and groundwater resources, wetlands, loss of agricultural land, and issues related to coal waste from the mine. In October 2009, the hearing officer granted the IDNR Motion to Dismiss five individual claimants and the two citizens groups. On July 19, 2010, Petitioners filed a motion for summary judgment asking for the permit to be vacated based on their allegation that the IDNR failed to include certain areas in its Cumulative Impact Assessment for the permit, including the headwaters of Miller Creek, a local intermittent stream. On November 22, 2010, the hearing officer denied Petitioners’ motion for summary judgment. No discovery deadline or final hearing date has been set in this matter, currently. While we believe the permit was properly issued and are proceeding at substantial cost in accordance with the permit to prepare the mine for longwall production commencing in 2012, there can be no guarantee that the permit will not be vacated or substantially modified which could result in delay of production, additional costs and/or cessation of some or all operations at the mine.

 

 

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In 2010, one of our subsidiaries, FCS, filed a breach of contract action against the TVA for failure to accept and pay for any coal sold by FCS under a coal purchase confirmation executed by the parties in September 2008. The coal sales confirmation requires FCS to sell and TVA to purchase 700,000 tons of coal per year for each contract year beginning January 1, 2009 and ending December 31, 2011. This suit is stayed to allow the parties to discuss settlement.

Currently we are conducting investigation and remediation of impacts to groundwater from refuse disposal areas at our Macoupin Energy Shay No. 1 Mine pursuant to the Illinois Site Remediation Program and a Compliance Commitment Agreement recently entered into with the Illinois Environmental Protection Agency. At December 31, 2011, we have an accrual for this matter. While there can be no assurance that our ultimate costs will not exceed this amount, we do not expect that to be the case.

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 most recent estimate by the BP Statistical Review, there are approximately 861 billion metric tonnes of worldwide proved coal reserves. The United States has the largest proved reserve base in the world with approximately 237 billion metric tonnes, or 27.6% of total world coal proved reserves. U.S. coal reserves represent approximately 249 years of domestic supply based on current production rates. Coal is also the most abundant domestic fossil fuel, accounting for approximately 94% of the nation’s fossil energy reserves.

Coal is ranked by heat content, with 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. Thermal coal comprises the vast majority of total coal production. In 2010, 95% of US thermal coal consumption was by the electric power sector with the balance used in industrial and commercial applications.

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 2010. Coal consumption grew by 7.6% in 2010, the fastest growing energy source in the world since 2003 and, according to the World Coal Association, its use is forecasted to rise over 50% to 2030, with developing countries responsible for 97% of this increase, primarily to meet electrification rates.

Our Industry Segment

We produce thermal coal from our operations in the Illinois Basin and market our coal domestically principally to scrubbed power generation facilities and industrial users and internationally to a variety of customers. We effectively compete with all producers of thermal coal that supply these respective segments.

Coal Industry Trends

Coal consumption and production in the United States, as well as the seaborne coal market, have been driven in recent periods by several market dynamics and trends and long-term projections for coal demand remain positive. These market dynamics and trends 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 has approximately 45-50% market share of generation in the United States from 2001 to 2010, principally because of its relatively low cost, reliability and abundance. The EIA projects coal prices to be $2.40 on a dollars per mmbtu basis while natural gas is projected to be $4.76 per mmbtu for 2011, or approximately two times the price of coal for 2011. The EIA has estimated the average fuel prices per million of Btu to electricity generators, using coal and competing fossil fuel power generation alternatives, as follows:

Average Cost of Electricity Generation by Fossil Fuel

(dollars per million Btu)

 

Electric Generation Type		2008				2009				2010				2011 Forecast				2012 Forecast
Distillate Fuel Oil		$	21.46			$	13.24			$	16.60			$	22.44			$	23.43
Residual Fuel Oil		$	13.68			$	9.11			$	12.63			$	18.38			$	18.01
Natural Gas		$	9.13			$	4.73			$	5.08			$	4.76			$	4.23
Coal		$	2.07			$	2.21			$	2.26			$	2.40			$	2.40

 

Source: EIA.

 

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Increasing demand for coal produced in the Illinois Basin. Demand for coal produced in the Illinois Basin is expected to grow at a rate faster than overall U.S. coal demand, due predominately to the Illinois Basin’s low delivered cost per Btu and the increased utilization of sulfurous emissions mitigation equipment (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 estimates, 198 GWs, or 63% of total capacity, of electric generating units in the United States will be scrubbed in 2011. Wood Mackenzie expects scrubbed capacity to increase to 268 GWs, or 100% of total capacity, by 2025. In addition, high Btu coal, such as that produced in the Illinois basin, is burned by several utilities throughout Europe and other international locations. Assuming forecasted increases in Pacific Basin demand continue, the shortfall in Atlantic Basin supply is expected to continue creating an opportunity for increased exports from the U.S., particularly the Illinois Basin, as well as, South America. As a result of its low cost coal production, high Btu content and the increased use of scrubbers, Wood Mackenzie projects total demand for Illinois Basin coal to grow from an estimated 120 million tons in 2011 to 216 million tons in 2025, a compounded annual growth rate of 4.3%.

Forecasted Illinois Basin Coal Demand by Region

(tons in millions)

 

Electric Generation Region		2011				2012				2013				2014				2015				2020				2025				2011-2025 CAGR
South Atlantic			15.7				21.5				26.4				43.3				46.9				50.9				55.1				9.4	%
East North Central			42.7				46.6				50.1				43.5				43.4				57.4				59.5				2.4
East South Central			41.8				46.7				49.9				54.5				52.3				57.7				56.5				2.2
Domestic Industrial			9.9				10.0				10.2				10.3				10.6				11.5				12.4				1.6
Other Domestic			3.2				2.9				3.0				2.1				2.2				5.8				7.9				6.6
Exports			6.6				4.9				8.1				2.9				11.5				20.9				25.0				9.9
Total Illinois Basin Coal Demand			119.9				132.7				147.6				156.6				166.9				204.1				216.4				4.3	%

 

Source: Wood Mackenzie.

 

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Developments in U.S. regional coal markets. Coal production in Central Appalachia, which is 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 production challenges, reserve degradation, and difficulties acquiring permits needed to conduct mining operations. In addition, underground mining operations have become subject to additional, more costly and stringent safety regulations, which have had the effect of increasing their operating costs and capital expenditure requirements. Central Appalachian coal production (including both thermal and metallurgical coal) has declined 29% from 261 million tons in 2000 to 186 million tons in 2010, according to EIA. Wood Mackenzie projects thermal coal production in Central Appalachia will decline 51% from 115 million tons in 2011 to 56 million tons by 2025. This decline is expected to be offset by production from other U.S. coal basins, including the Illinois Basin. In 2009, the EPA increased its scrutiny of permit applications for operations conducting mountain top removal and valley fills, which primarily impacts producers in Appalachia, resulting in permitting delays which have and are expected to continue to impact production levels in that region. In addition, producers in Central Appalachia have increasingly shifted production from thermal coal to higher priced metallurgical coal at several existing and planned mines, 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 over the past several years and will continue to put cost pressures on producers, disadvantaging Central Appalachia coal on a delivered cost basis relative to other basins.

 

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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 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. One result of this was that Powder River Basin production increased from 377 million tons in 2000 to 469 million tons in 2010, as coal from this region is predominately lower sulfur coal. Some utilities were able to negotiate long-term rail contracts with one of the two western railroads (Union Pacific and Burlington Northern Santa Fe) to manage their transportation costs. From 1994 to 2004, reported average revenue per carload for these carriers increased 10.3%. However, from 2004 to 2010, the reported average revenue per carload for these carriers increased by 53.1%. The average cost of transportation for western coals has been increasing, and we expect this trend to continue, resulting in higher delivered costs for western coals.

 

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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 scrubbers can remove over 90% of sulfurous gasses prior to emission.

 

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Expected long-term increases in international demand for U.S. coal exports. In 2011 the EIA reported that U.S. coal exports were at their highest levels since 1992. According to the EIA, thermal coal has driven U.S. coal export growth recently, increasing 160% in the first quarter of 2011 compared to the same period in 2010, although coking coal comprises the majority of coal exports, with 64% of the total. U.S. exports began to increase in 2010, supported by recovering global economies and continued rapid growth in electric power generation and steel production capacity in Asia, particularly in China and India. The growth of demand in the Pacific seaborne thermal coal market has had an effect on the delivered price of Pacific market coal sales, which has increased over the last several years. We believe potential supply shortfalls in the Pacific region could pull significant supply which had previously serviced customers in the Atlantic market to the Pacific market, resulting in a shortfall of supply to the Atlantic market. In addition, traditional coal exporting countries such as Australia, Indonesia, Colombia and South Africa have difficulty rapidly increasing exports to meet demand, resulting in further seaborne coal supply constraints. Furthermore, increased international demand for higher priced metallurgical coal has resulted in certain coal from Central Appalachia and Northern Appalachia, which can serve as either metallurgical or thermal coal, being drawn into the metallurgical coal export market, which further reduces supplies of thermal coal from these regions. 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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Development of new coal-related technologies will lead to increased demand for coal. The EIA projects that new coal-to-liquids plants will account for 13 million tons of annual coal demand by 2020, increasing to 128 million tons by 2035. In addition, through ARRA, the federal government has targeted over $1.5 billion to CCS research and another $800 million for the Clean Coal Power Initiative, a ten-year program supporting commercial application of CCS technology. We believe that the Illinois Basin, with its ample supply of low cost coal reserves, will be an important supplier to coal-to-liquids plants over the long-term.

 

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Increasingly stringent air quality legislation will continue to impact the demand for coal. A series of more stringent 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. Considerable uncertainty is associated with these air quality regulations, some of which have been the subject of legal challenges in courts, and the actual timing of implementation remains uncertain. While past air quality legislation targeted primarily to reducing sulfur emissions has resulted in an increase in utilization of scrubbers and a return to growing demand

 

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for high sulfur coal, we believe that it is likely that additional air quality regulations ultimately will be adopted in some form at the federal or state level. While it is currently not possible to determine the impact of any such regulatory initiatives on future demand for coal, it may be materially adverse.

Seaborne Market

 

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Growth in seaborne thermal coal demand. According to Wood Mackenzie, coal consumption in the seaborne thermal coal market has increased from approximately 339 million metric tonnes in 2000 to 791 million metric tonnes in 2011, a compounded annual growth rate of 8.0%. Wood Mackenzie projects consumption of seaborne thermal coal to increase further to over 2.0 billion metric tonnes by 2025, a compounded annual growth rate of 7.2% from 2011. Growth in international coal import demand has resulted primarily from increased demand for thermal coal for electricity generation by emerging global economies, particularly by Asian countries in the Pacific market where coal is the primary fuel source for new power generation. Countries outside of the developed economies of Europe and Japan are expected to import 66% of the world’s seaborne export thermal coal in 2011, and their share of the total seaborne thermal coal market is projected to increase to 85% in 2025 per Wood Mackenzie estimates.

 

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Increased seaborne thermal coal import demand by China. China, which historically was a net exporter of thermal coal, experienced a 105 million metric tonne increase in imports from 2008-2010, up 338% over the three year period, which is expected to grow a further 562% to 899 million metric tonnes by 2025, according to Wood Mackenzie. As a percentage of the overall seaborne thermal coal market, China’s imports accounted for 19% of total seaborne demand and 26% of Asia market demand in 2010. The chart below shows projected import demand and export supply for China between 2011 and 2025:

China Seaborne Thermal Coal Trade (metric tonnes in millions)

 

 

Source: Wood Mackenzie.

 

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Increased seaborne thermal coal import demand by India. Coal demand in India has increased significantly with imports rising from 9 million metric tonnes in 2000 to 62 million metric tonnes in 2010, a 20.7% compounded annual growth rate. India plans to increase coal-fired power generation as a share of its overall generation portfolio. Wood Mackenzie estimates India had 95 GWs of coal-fired generation in 2010 and expects this to increase by 232% to 316 GWs by 2030. This increase in coal-fired generation capacity is expected to create significant increases in coal demand. With these dramatic increases in thermal coal demand, India will be required to increase seaborne thermal coal imports to help balance supply with demand, as domestic thermal coal supply is expected to be insufficient to meet the growing demand. According to Wood Mackenzie, between 2010 and 2025, India’s thermal coal imports are estimated to rise by over 500% to approximately 372 million metric tonnes, and India’s share of the seaborne thermal coal market is estimated to increase from 8.8% in 2010 to 17.9% by 2025.

 

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Supply constraints from traditional thermal coal exporting countries. Traditional export supply countries, including Australia, South Africa, Indonesia, Colombia and Russia, continue to face export supply constraints often limiting these countries’ ability to keep up with the pace of seaborne thermal coal demand. Many of these countries have faced thermal export supply constraints resulting from one or several factors, including, among other factors, limited port capacity; rail transportation capacity, reliability and distance; power generation shortages limiting coal processing; increased domestic consumption; unexpected weather impacts and declining coal qualities. As a result of recent supply constraints and disruptions, large thermal coal importing countries in the Pacific market, have sought to diversify their supply sources and pay premium pricing to guarantee security of supply by importing thermal coal from producers who had traditionally primarily serviced the Atlantic thermal market.

 

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Increase in European thermal coal import demand. In Europe, domestic coal supply has declined due to reductions in domestic production as a result of the region’s declining coal reserve base and a reduction in government subsidies for coal mining, particularly in Poland, Germany and Spain. Additionally, the International Atomic Energy Agency projects slower global growth in nuclear power capacity following the 2011 earthquake in Japan and related nuclear incident. Germany, in particular, has closed certain older facilities and is planning to shutdown its remaining nuclear plants by 2022. Coal-fired generation is expected to meet a large portion of this additional demand. We believe that the decline in domestic production in Europe, coupled with an expected increase in coal-fired power generation, will result in an increase in thermal coal imports.

Coal Demand

According to the World Coal Association, world hard coal consumption in 2010 was estimated at 6.3 billion metric tonnes, of which approximately 1.0 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, the existing power generation infrastructure, governmental regulation impacting power generation, 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 used to generate electricity accounts for 95% of coal consumed in the United States, with the balance used by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Metallurgical coal is predominately consumed in the production of metallurgical coke used in steelmaking blast furnaces. Coal-fired power plants produced approximately 45-50% of all electric power generation over the last ten years, more than natural gas and nuclear, the two next largest domestic fuel sources, combined.

According to the EIA, over the past 35 years, total coal consumption in the United States has nearly doubled to approximately 1.0 billion tons in 2010. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators. As a result of the global economic downturn, which reduced demand for electricity generation, thermal coal consumption decreased in 2009. From 2009 through 2025, the EIA forecasts that total U.S. coal consumption will increase by a compounded annual growth rate of 1.1% as a result of overall increased electric generation demand, offset by the retirement of coal-fired generation capacity and increased share of natural gas and other fuel sources in electric generation.

 

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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)

 

		2008A				2009A				2010A				2015 Forecast				2020 Forecast				2025 Forecast
Electric Power			1,041				934				984				928				989				1,066
Industrial			54				45				48				49				49				48
Steel Production			22				15				21				22				22				21
Residential/Construction			4				3				3				3				3				3
Coal-to-Liquids			0				0				0				11				13				44
Total U.S. Coal Consumption			1,121				997				1,048				1,013				1,076				1,182

 

Source: EIA.

In the United States, the reliance on coal-fired generation is attributable to the abundance and low cost of coal. In 2010, coal was approximately 55.5% lower on a dollar per million Btu basis than natural gas, the next least expensive and readily available fuel source. According to the EIA, coal is expected to remain the largest energy source for electric power generation in the United States for the foreseeable future.

U.S. Scrubber Market

Utilities are increasingly purchasing coal on a heat content basis (measured in dollars per million Btus) and less on a sulfur content basis as the utilization of sulfur mitigation systems, or scrubbers, are installed by utilities to comply with emissions requirements of the Clean Air Act Amendments of 1990. Prior to the Clean Air Act, the Illinois Basin was characterized by low cost mining of high Btu, high sulfur coal. The coal produced in Illinois competed nationally against other coal basins due to its low cost access to widespread transportation outlets and its high heat rate. The Clean Air Act restricted emissions of sulfur by electric utilities, causing some utilities to blend lower sulfur coal with higher sulfur coal or switch to higher cost, lower sulfur fuels as plans to build additional environmental compliance equipment progressed, or purchase sulfur emission credits to comply with regulations.

As a result, coal production in the Illinois Basin declined by 38% from 141 million tons in 1990 to 87 million tons in 2000, and many of the large underground coal mining operations in Illinois were idled or closed. With the increase of scrubber utilization, 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 quality, low cost coal from the Illinois Basin. According to Wood Mackenzie, Illinois Basin coal demand is estimated to grow by nearly 100 million tons from 120 million tons in 2011 to 216 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.

 

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The following map of the eastern United States shows coal-fired plants with existing or announced SO2 emission controls:

 

 

Source: Ventyx, the Velocity Suite

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 are predicted to contribute over 55 million tons of increased demand for Illinois Basin coal from 2011 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 accounting for much of the remainder.

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 approximately 77% of total coal-fired generation in 2011 to 100% in 2025, contributing to an increase in Illinois Basin coal demand of approximately 40 million tons over the same period. In the East North Central region, scrubbed coal-fired electricity generation is expected to increase from 40% in 2011 to 100% in 2025, contributing to an addition of approximately 15 million tons to Illinois Basin demand over the same period. In the East South Central region, Illinois Basin coal demand is expected to increase from 42 million tons in 2011 to 56 million tons in 2025, contributing to an addition of 15 million tons to Illinois Basin demand over the same period. The following table shows, for the Illinois Basin’s primary electric generating regions, projected coal demand by basin and percentage of scrubbed fleet capacity, based on Wood Mackenzie data.

 

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Illinois Basin Consumption by Region

Illinois Basin Coal Demand (short tons in millions)		% From Illinois Basin Coal		Scrubbed % Coal-fired Generation Capacity

 

Source: Wood Mackenzie.

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

Seaborne Coal Market

Wood Mackenzie estimates total seaborne thermal coal demand in 2011 will be approximately 791 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 and Central America. The Atlantic market’s largest consuming countries for seaborne thermal coal are the United Kingdom, Germany, the United States, Italy, Turkey, Spain, France and Denmark. 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.

 

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According to Wood Mackenzie, Atlantic market and Pacific market seaborne thermal coal demand was 194 and 596 million metric tonnes for 2011, respectively. Nearly all major coal-consuming countries in Asia are expected to experience significant demand growth. Wood Mackenzie projects demand for seaborne thermal coal to increase to over 2.0 billion by 2025. The increased growth is driven largely by new Chinese and Indian demand. The charts below illustrate estimated demand for seaborne thermal coal by country, for 2011:

 

Seaborne Thermal Coal Demand—Atlantic Market		Seaborne Thermal Coal Demand—Pacific Market
(% 2011 E demand, 187 million metric tonnes)		(% 2011 E demand, 541 million metric tonnes)

 

Source: Wood Mackenzie.

Coal Production and Supply

China is the world’s largest producer of coal with approximately 48% of the world’s coal production in 2010 on an oil equivalent basis, according to the BP Statistical Review. In 2010, China was followed by the United States (15%), Australia (6%), India (6%), Indonesia (5%), Russia (4%) and South Africa (4%).

 

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United States Coal Production

According to BP Statistical Review, 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 249 years of supply at current production rates. U.S. coal production was approximately 1.1 billion metric tonnes in 2010 according to the EIA. Coal produced in the United States is primarily consumed domestically, with 82 million metric tonnes of coal exported in 2010 according to the EIA. Approximately 93% of coal produced in the United States in 2010 was thermal coal. Wood Mackenzie forecasts thermal coal production in the United States will increase approximately 6% from 2011 through 2025, largely to secure 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

 

		Historical U.S. Coal Production																				2000-2010 Increase / (Decrease)
Coal Basin		1990				1995				2000				2005				2010
		(tons in millions)
Powder River Basin			222				303				377				445				468				24.2	%
Central Appalachia			294				272				261				235				186				(28.7	)
Northern Appalachia			166				167				139				140				129				(7.1	)
Illinois Basin			141				109				87				93				105				20.5
Other			206				182				209				219				196				(6.5	)
Total U.S. Coal Production			1,029				1,033				1,074				1,132				1,084				2.4	%

 

Source: EIA.

Wood Mackenzie forecasts flat or declining thermal coal production through 2025 for all major U.S. coal producing regions other than the Illinois Basin. We believe this is largely a result of heightened regulatory, geologic and permitting scrutiny in Appalachia, rising cost profiles, increased transportation expenses and capacity shortfalls and added scrubber utilization, amongst other factors. 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

 

		Forecasted U.S. Coal Production(1)																2011-2025 Forecasted CAGR
Coal Basin		2011				2015				2020				2025
		(tons in millions)
Powder River Basin			465				508				481				508				0.6	%
Central Appalachia			115				64				46				56				(5.0	)
Northern Appalachia			116				136				132				125				0.5
Illinois Basin			120				167				204				216				4.3
Metallurgical			86				70				81				87				0.1
Other			201				197				190				181				(0.7	)
Total U.S. Coal Production			1,103				1,142				1,135				1,173				0.4	%

 

Source: Wood Mackenzie.

(1)	Regional data represents forecasted thermal coal production.

 

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Wood Mackenzie estimates that demand for Illinois Basin coal will grow at a compound annual rate of 4.3%, taking total consumption from 120 million tons in 2011 to 216 million tons in 2025. Hanou Energy’s forecasts confirm that Illinois Basin planned production is expected to be approximately 210 million tons by 2021 with the potential to be as high as 300 million tons depending on market conditions. This is compared to other U.S. thermal coal excluding the Illinois Basin, which Wood Mackenzie estimates will decrease at a compound annual rate of 0.2% over the same period. Importantly, Illinois Basin coal production is projected to grow more sharply over the 2011-2020 period (6.1% CAGR) than over the latter part of the 15-year projection period.

United States Forecasted Thermal Coal Production

 

 

Source: Wood Mackenzie.

Coal Producing Regions

Coal is mined in over half of the states in the United States, but domestic coal production is primarily attributed to one of 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 by, and 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 10,100 to 12,600 Btu/lb and sulfur content ranging from 1.0% to 4.3%. 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. In addition, planned coal-to-liquids facilities, which are backed by state support and incentives and are indifferent to the sulfur content of coal, may become substantial new consumers of Illinois Basin coal.

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

 

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According to the EIA, coal production in the Illinois Basin was 105 million tons in 2010, an increase of 3.0% over 2009. Wood Mackenzie forecasts that coal production in the Illinois Basin will increase from a forecasted 120 million tons in 2011 to 216 million tons in 2025, an 80.0% 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 10,300 to 13,500 Btu/lb and sulfur content typically ranging from 0.8% to 4.0%. Coal produced in Northern Appalachia is marketed primarily to electric utilities, industrial consumers and the export market, with some metallurgical coal marketed to steelmakers.

According to the EIA, coal production in Northern Appalachia was 129 million tons in 2010, an increase of 2.4% from 2009. Wood Mackenzie forecasts that thermal coal production in Northern Appalachia will increase from a forecasted 116 million tons in 2011 to 125 million tons in 2025, a 7.8% increase.

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 11,400 to 13,200 Btu/lb and sulfur content typically ranging from 0.2% to 2.0%. Coal produced in Central Appalachia is marketed primarily to electric utilities, with metallurgical coal marketed to steelmakers. The combination of reserve depletion and increasing regulatory enforcement, mining costs and geologic complexity in Central Appalachia is expected to lead to substantial production declines over the long-term. In addition, the widespread installation of scrubbers is expected to enable higher sulfur coal from the Illinois Basin and Northern Appalachia to replace coal from Central Appalachia.

According to the EIA, coal production in Central Appalachia was 186 million tons in 2010, a decline of 5.3% from 2009. Wood Mackenzie forecasts that thermal coal production in Central Appalachia will decline from a forecasted 115 million tons in 2011, to 56 million tons in 2025, a 51.3% 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 0.9% and heat content typically ranging from 8,000 to 9,500 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 the EIA, coal production in the PRB was 468 million tons for 2010, an increase of 2.8% from 2009. Wood Mackenzie forecasts that coal production in the PRB will increase from a forecasted 465 million tons in 2011 to 508 million tons in 2025, an increase of 9.2%.

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, where approximately 246 million metric tonnes are expected to be sold in 2011, according to Wood Mackenzie. The Atlantic market traditionally has relied on Pacific market sources of supply such as Indonesia to balance its supply and demand deficit. Indonesia, Australia, China, South Africa and Russia are the principal suppliers of the Pacific seaborne thermal coal market, where approximately 545 million metric tonnes are expected to be sold in 2011.

 

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A key 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 working to increase supply accordingly to meet demand. In Australia, Indonesia and South Africa, three historically key suppliers to Asia, coal producers have experienced infrastructure constraints, rising tax and government regulations, port capacity limitations and increasing domestic demand and export restrictions, among other issues. Today, there is a growing amount of coal produced by traditional Atlantic market suppliers that has begun to move from the Atlantic market into the Pacific market, and we expect this trend to continue. We also believe that there 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 Seaborne Thermal Coal Supply by Country

(metric tonnes in millions)

 

		Supply to Seaborne Market												2011-2025 Forecasted  CAGR
Country of Origin		2011 Forecast				2015 Forecast				2025 Forecast
Australia			161				250				590				9.7	%
Colombia			80				119				135				3.8
Russia			94				94				267				7.8
South Africa			66				90				88				2.0
Indonesia			297				378				588				5.0
U.S.			36				36				325				17.0
Other Supply			56				50				88				3.2
Total Supply			791				1,017				2,081				7.2	%

 

Source: Wood Mackenzie.

U.S. Coal Exports

Relatively higher costs of delivered coal into a vessel, the United States traditionally has been viewed as a swing supplier to the thermal coal export market. Historical coal export volumes in the past have been volatile for both thermal and metallurgical coal, with export levels over the last decade ranging between 39.6 million tons in 2002 and 81.7 million tons in 2010. Of coal exported in 2010, 25.6 million tons of coal was thermal with the balance metallurgical coal. From 2001 through 2010 export thermal coal from the United States increased 10% compared to export metallurgical coal which grew 121% over the same time period.

United States Coal Exports

(tons in millions)

 

Product Type		2001				2002				2003				2004				2005				2006				2007				2008				2009				2010
Thermal Coal			23				18				21				21				21				22				27				39				22				26
Metallurgical Coal			25				22				22				27				29				28				32				43				37				56
Total U.S. Coal Exports			49				40				43				48				50				50				59				82				59				82

 

Source: EIA.

The current strong demand for thermal and metallurgical coal by Chinese and Indian consumers has created an imbalance in the seaborne coal markets. In the past, a portion of the Atlantic market demand had been supplied from Pacific market producers like Indonesia and South Africa. Today, producers in these countries are satisfying the strong demand for their products in Pacific markets rather than the Atlantic markets, which has led

 

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to a tighter Atlantic market supply picture overall. We believe that U.S. coal will play an increasingly important role in supplying the Atlantic, and increasingly the Pacific, seaborne coal markets, given access to infrastructure, excess port capacity, and increasingly more competitive delivered costs on a per Btu basis. Wood Mackenzie has forecasted that U.S. thermal coal exports will reach 325 million metric tonnes in 2025, a 800% increase over 2011 levels.

Coal Pricing

Coal prices vary dramatically by region and are determined by 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. Electric generators purchase coal on the basis of its delivered cost per Btu.

U.S. Thermal Coal Market

The U.S. thermal coal market has experienced a rising trend in prices over the last decade. From January 4, 2000 through January 20, 2012, coal spot prices in Central Appalachia, Northern Appalachia, the Illinois Basin and the Powder River Basin have increased 230%, 290%, 167% and 165%, respectively. Throughout this period, coal prices have experienced price spikes due largely to short- to medium-term supply/demand imbalances and either high or low (relative to normal levels) inventory stockpiles. 2008 saw a substantial increase in thermal coal prices 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; however, prices have since recovered as exports have grown.

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, 2003 to January 20, 2012, as reported by Bloomberg L.P.

U.S. Coal Prices

($ per ton)

 

 

Source: Bloomberg L.P.

 

Note:

Central Appalachian = FOB Big Sandy Barge, 12,000 Btu, less than 1% sulfur, 13.5% ash and 10% moisture.

Northern Appalachian = Pittsburgh coal bed, FOB, 12,500-13,000 Btu, 2%-3% sulfur and 7%-9% ash content.

Illinois Basin = FOB Barge, maximum 11,000 Btu, less than 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.

 

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Seaborne Thermal Coal Market

There are significant variations in the characteristics of thermal coals sold in the international market, with pricing premiums for certain desired characteristics and pricing penalties for certain undesired characteristics. For the 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 alternative fuels and government regulations. There are additional influences on coal prices that affect the normal interaction of supply and demand by producers that are dedicated to a particular market or market segment and purchasers that desire diversified sources.

Similar to the U.S. thermal coal market, the seaborne thermal coal market has experienced a rising trend in prices. Throughout this period, coal prices have experienced price spikes due largely to short- to medium-term supply/demand imbalances and either high or low (relative to normal levels) inventory stockpiles. During the second half of 2007, seaborne thermal coal prices in the Atlantic market began to strengthen and then they peaked in mid-summer of 2008, before falling in the fourth quarter of 2008 as a result of the global economic downturn. Prices have since increased with increasing Atlantic and Pacific market demand and signs of global economic recovery. The following chart sets forth average historical coal prices and forward curve (as of January 10, 2012) for the API#2 Index and API #4 Index, as reported by Bloomberg L.P.

Seaborne Thermal Coal Prices

(US$ per metric tonne)

 

 

Source: Bloomberg L.P.

 

Note:

API#2 = Cost, Insurance and Freight (CIF) at Rotterdam terminal, 10,793 Btu/lb, under 1% sulfur.

API#4 = Freight on Board (FOB) at Richards Bay terminal, 10,793 Btu/lb, under 1% sulfur.

Transportation

The U.S. coal industry is dependent on the availability of a consistent and responsive 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 element in determining 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 often sold FOB at the loading port, and coal producers are responsible for shipment to the export coal-loading facility. Where economic benefits or contractual obligations exist, the coal producer may provide the transportation and transportation services for delivery of the coal to the customer.

 

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Following the implementation of the Clean Air Act, 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 377 million tons in 2000 to 468 million tons in 2010 as demand for these predominately lower sulfur coals increased. Some utilities that burn PRB coal were able to negotiate long-term rail contracts with one of the two western railroads to manage their transportation costs. From 1994 to 2004, reported revenue per carload for these carriers was essentially unchanged. From 2004, fourteen years after implementation of Phase 1 of the Clean Air Act, to 2010, average revenue per carload increased by an average of 53.1%. The average cost of transportation for western coals has increased meaningfully, and we expect this trend to continue.

In the Eastern United States, major export terminals for coal include the Port of New Orleans in New Orleans, Louisiana; Convent Marine Terminal (CMT) in Convent, Louisiana; Alabama State Docks in Mobile, Alabama; Tampa Port Authority in Tampa, Florida; the Jacksonville Port Authority in Jacksonville, Florida; Shipyard River Terminal in Charleston, South Carolina; Port of Virginia in Norfolk, Virginia; and Port of Baltimore in Baltimore, Maryland. To receive these exports, European and Mediterranean markets have an established import terminal infrastructure.

 

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ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Our operations are subject to a variety of 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 or that we will be able to always obtain, maintain or renew required permits or that changes in these requirements or their enforcement, or 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. Currently we are conducting investigation and remediation of impacts to groundwater from refuse disposal areas at our Macoupin Energy Shay No. 1 Mine pursuant to the Illinois Site Remediation Program and a Compliance Commitment Agreement recently entered into with the Illinois Environmental Protection Agency. 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 2011, 2012 or 2013. 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, including related implementing regulations by MSHA, and the Mine Improvement and New Emergency Response Act of 2006 impose stringent mine safety and health standards on all aspects of mining operations. 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. Through the first nine months of 2011, these costs totaled approximately $0.4 million, and we anticipate these costs to total approximately $0.6 million in 2012.

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 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 paid through December 31, 2011.

United States Environmental Laws

We are subject to various United States federal, state and local environmental laws. Some of these laws, discussed below, impose stringent requirements on our coal mining operations. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance. Federal and state inspectors are

 

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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 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 SMCRA, the state programs, and the 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 SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.315 per ton on surface-mined coal and $0.135 per ton on deep-mined coal.

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 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 costs. As of September 30, 2011 we had outstanding surety bonds of $37.4 million and total letters of credit of $2.0 million. Changes in these laws or regulations could require us to obtain additional surety bonds or other forms of financial security.

 

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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 and/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. The general effect of this extensive regulation of air emissions from coal-fired power plants could be to reduce demand for coal.

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. 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. However, in February 2009, the United States Court of Appeals for the District of Columbia Circuit remanded the PM2.5 standard back to the EPA for further review. 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. At this time the EPA intends to proceed to implement the .075 parts per million standard announced in 2008 and to reconsider the permissible levels for good level ozone in 2013. More stringent NAAQS 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 and/or fine particle pollution in other states. Under 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 CSAPR. On December 30, 2011, the D.C. Circuit Court issued a stay of CSAPR and reinstated CAIR pending judicial review. Briefing and oral argument is expected to be concluded by mid-2012. It is unclear what effect, if any, CAIR would have on our operations or results. If the stay on CSAPR is lifted or if CSAPR is upheld, more stringent emissions limitations could increase the costs of operating coal-fired power plants and affect demand for coal.

Mercury and Air Toxic Standards. On December 16, 2011, 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

 

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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 burning 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 burning power plants, to obtain permits to emit, and to use best available control technology to curb, GHG emissions. EPA also recently proposed new source performance standards for GHG for coal and oil burning power plants but has deferred the deadline for finalizing this proposal. While EPA’s actions are subject to legal challenges and efforts are underway in Congress to limit or remove EPA’s authority to regulate GHG emissions, they will remain in effect unless altered by the courts or Congress.

Regional Emissions Trading. Ten 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. While efforts are underway in a few states to withdraw from this arrangement, nine states participated in the latest auction of carbon dioxide allowances which was held in December 2011. 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 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 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 RCRA; the other would regulate coal ash as a non-hazardous solid waste. 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 scope and details of any final EPA regulations are uncertain at this time. In addition, environmental groups have filed a notice of intent to sue the EPA for failing to update effluent limitation

 

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guidelines under the Clean Water Act for coal-fired power plants, to limit discharges of toxic metals from handling of coal combustion waste. The EPA has announced its intention to revise its existing effluent limitation guidelines before 2012 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 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

The Clean Water Act of 1972 affects coal mining operations several ways.

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.

We must obtain numerous permits from applicable state and federal regulatory authorities. 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,

 

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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 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.

In addition to SMCRA and CWA permits, the mining companies are required to obtain permits from MSHA, IEPA and the IDNR Office of Water Resources for the construction of slurry impoundments (dams). MSHA conducts a technical review of the engineering and stability aspects of the dam. IEPA reviews to determine whether the dam requires revisions to any existing CWA permit. And, finally, the Office of Water Resources, the state agency with jurisdiction over all dams in Illinois, reviews the permit under its rules for dam construction, stability and maintenance.

Currently only Macoupin has filed for the permits required for underground disposal of slurry. A permit application for underground slurry disposal was submitted jointly to IDNR and IEPA. IDNR will determine whether the proposed underground slurry disposal meets the SMCRA rules and requirements, while IEPA is required to assess whether the underground slurry disposal will require modifications to the CWA permit.

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.

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 Partners LP

We are managed and operated by the board of directors and executive officers of our general partner. Following this offering,     % of our outstanding common units and all of our outstanding subordinated units and incentive distribution rights will be directly or indirectly owned by 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 the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain 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 seven directors,                      of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a 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/corporate governance committee. We are, however, required to have an audit committee of at least three members, and, within one year of the listing of our common units on the NYSE, all of its members are required to be independent as defined by the NYSE.

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.

The following table sets forth information concerning the officers and directors of our general partner effective upon the listing of our common units on the NYSE:

 

Name		Age		Position
Christopher Cline		53		Chairman of the Board of Directors and Principal Strategy Officer
Michael J. Beyer		53		Director and President and Chief Executive Officer
Oscar A. Martinez		42		Senior Vice President—Chief Financial Officer
H. Drexel Short		55		Senior Vice President—Mining Operations
Rashda M. Buttar		43		Senior Vice President—General Counsel & Corporate Secretary
				Director Nominee
				Director Nominee
				Director Nominee
				Director Nominee
				Director Nominee

Christopher Cline is the Chairman of our Board and Principal Strategy Officer. 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.

Michael J. Beyer is the President and Chief Executive Officer and a member of our Board of Directors. Mr. Beyer has more than 30 years’ experience in management, operations, finance and acquisitions related to coal and other energy-related businesses. Before joining Foresight in 2006, Mr. Beyer served as President of AEP

 

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Coal, Inc., Vice President of Business Development at Enron Corp. and 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.

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.

H. Drexel Short is the Senior Vice President—Mining Operations. Mr. Short has more than 30 years’ 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.

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.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee.

Audit Committee

The audit committee of our general partner will initially consist of Messrs.             ,              and             , and, within one year of the listing of our common units on the NYSE, all of its members will be independent. We expect the board of directors of our general partner to determine that at least one of the independent directors is an “audit committee financial expert” within the meaning of the SEC rules. Upon completion of this offering, our audit committee will operate pursuant to a written charter. This committee will oversee, review, act on and report to our board of directors of our general partner on various auditing and accounting matters, including the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements.

 

Conflicts Committee

At least              independent members 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 determine to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is in our best interest. 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

 

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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 in our best interest, approved by 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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COMPENSATION DISCUSSION AND ANALYSIS

Introduction

This Compensation Discussion and Analysis (“CD&A”) is organized into two principal sections. The first section describes the compensation of Foresight Management’s named executive officers during the year ended December 31, 2011. Foresight Energy LLC did not have any direct employees in 2011. Instead, it engaged Foresight Management, a company owned by Foresight Reserves, to provide management services to it pursuant to a Management Services Agreement. As a result, during all of 2011, named executive officers participated in compensation plans that were sponsored or maintained by Foresight Management. The second section contains a discussion of certain compensation-related actions taken or that are expected to be taken in connection with this offering. Actual compensation programs that we adopt may differ materially from the programs summarized in this discussion and analysis. Unless otherwise noted, within the remainder of this Compensation Discussion and Analysis, references to “we” and “our” refer to both the philosophy and policies implemented by Foresight Management as well as the philosophy and policies to be implemented by our general partner upon completion of this offering. The philosophy and policies may change in the future.

2011 Compensation

Executive Summary

The primary objectives of the executive compensation program in effect for 2011 were to attract and retain talented executive officers to effectively manage and lead our business and to create value for our equity holders. The executive compensation program was designed to recognize and reward diligent, intelligent and effective performance that enables our business to grow and to achieve our financial goals. The discussion below includes a review of the executive compensation decisions with respect to 2011. Our named executive officers for 2011 were Christopher Cline, our Principal Strategy Officer; Michael J. Beyer, our President and Chief Executive Officer; Oscar A. Martinez, our Senior Vice President—Chief Financial Officer; Donald R. Holcomb, our previous Principal Financial Officer; H. Drexel Short, our Senior Vice President—Mining Operations; and Rashda M. Buttar, our Senior Vice President—General Counsel & Corporate Secretary. The compensation packages for our named executive officers generally included a base salary, annual cash bonuses and other benefits and perquisites.

Determination Process

The structure of the compensation program for our named executive officers reflects the view that executive compensation components should be set at the levels necessary to successfully attract and retain skilled executives and that are fair and equitable in light of market practices. In setting an individual executive officer’s initial compensation package and the relative allocation among different types of compensation, consideration is given to the nature of the position being filled, the scope of associated responsibilities, the individual’s prior experience and skills and the individual’s compensation expectations, as well as the compensation of existing executive officers and general impressions of prevailing conditions in the market for executive talent.

In 2011, the amounts of the base salaries of our named executive officers were established by Mr. Cline at the commencement of each such executive officer’s employment with us and were subject to adjustment by Mr. Cline. The amounts of the discretionary annual cash bonuses for the named executive officers were determined at the end of the 2011 fiscal year by Mr. Cline, taking into account Mr. Cline’s evaluation of all the facts and circumstances surrounding the record of accomplishment of the executive and our business during the 2011 fiscal year. Mr. Cline considered factors such as demonstrated leadership, success in motivating others to strive for excellence, strategic creativity and efficiency, level of responsibility, departmental challenges and contributions to increased value for our equity owners.

 

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Elements of Compensation

Base Salary

Base salaries are intended to provide a fixed level of compensation sufficient to attract and retain an effective management team when considered in combination with other components of the executive compensation program. We believe that the base salary element is required to provide our named executive officers with a stable income stream that is commensurate with their responsibilities and competitive market conditions. Annual base salaries are established on the basis of market conditions at the time an executive is hired. Any subsequent modifications to annual base salaries are influenced by the performance of the executive and by significant changes in market conditions.

Annual Cash Bonuses

Discretionary annual cash bonuses are awarded to recognize the accomplishments of each executive and of our business during the prior fiscal year. For 2011, bonuses were awarded to              and              to recognize successful development of the mines and overall performance of the company during the 2011 fiscal year and to remain competitive with the external market for executive talent.

Other Compensation

Various other benefits are also provided to our named executive officers that are intended to be part of a competitive compensation program. These benefits include a 401(k) defined contribution retirement plan, health insurance and life insurance, which benefits are generally available to all employees on substantially similar terms. The executives are also entitled to personal use of company aircraft at their own expense. In addition, we pay certain club membership dues for Michael J. Beyer. We believe that these benefits are comparable to those offered by other companies that compete with us for executive talent.

Compensation

The following tables contain information with respect to Foresight Management’s named executive officers for 2011. As required by SEC rules, Foresight Management’s named executive officers include individuals who have served as Foresight Management’s Principal Executive Officer or Principal Financial Officer at any time during 2011, Foresight Management’s three other most highly paid executive officers in office at the end of 2011 and up to two additional former executive officers who would have been one of Foresight Management’s three most highly paid executive officers if he or she had continued to be employed at the end of 2011. Foresight Management’s named executive officers for 2011 were Christopher Cline, Michael J. Beyer, Oscar A. Martinez, Donald R. Holcomb, H. Drexel Short and Rashda M. Buttar.

 

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Summary Compensation Table for the Fiscal Year Ended December 31, 2011

The following summary compensation table and related footnotes presents the compensation during fiscal year 2011 provided to the named executive officers:

 

Name and Principal Position

Year

Salary ($)

Bonus ($)

Stock Awards ($)

Option Awards ($)

Non-Equity Incentive Plan Compensation ($)

Change in Pension Value And Nonqualified Deferred Compensation Earnings ($)

All Other Compensation ($)

Total ($)

Michael J. Beyer,

2011

President and Chief Executive Officer

Oscar A. Martinez,

2011

Senior Vice President—Chief Financial Officer

Donald R. Holcomb,

2011

previous Principal Financial Officer

Christopher Cline,

2011

Principal Strategy Officer

H. Drexel Short,

2011

Senior Vice President—Mining Operations

Rashda M. Buttar,

2011

Senior Vice President—General Counsel & Corporate Secretary

Narrative Disclosure Regarding Employment Arrangements of Named Executive Officers

The employment arrangements of             ,             and              are described below.

Grants of Plan-Based Awards in 2011

There were no grants of plan-based awards to any of the named executive officers in 2011.

Outstanding Equity Awards at Fiscal Year-End 2011

The named executive officers did not have any outstanding equity awards as of December 31, 2011.

Option Exercises and Stock Vested in 2011

There were no option exercises by, or share vesting events for, the named executive officers in 2011.

Pension Benefits

Foresight Management does not maintain any defined benefit pension plans for the named executive officers.

 

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Nonqualified Deferred Compensation in 2011

 

Name and Principal Position

Source

Executive Contributions in Last FY ($)

Registrant Contributions in Last FY ($)

Aggregate Earnings in Last FY ($)

Aggregate Withdrawals/ Distributions ($)

Aggregate Balance at Last FYE ($)

Michael J. Beyer,

President and Chief Executive Officer

Oscar A. Martinez,

Senior Vice President—Chief Financial Officer

Donald R. Holcomb,

previous Principal Financial Officer

Christopher Cline,

Principal Strategy Officer

H. Drexel Short,

Senior Vice President—Mining Operations

Rashda M. Buttar,

Senior Vice President—General Counsel & Corporate Secretary

Potential Payments Upon Termination or in the Event of a Change in Control

 

Name and Principal Position		Involuntary Termination for Cause or Resignation Without Good Reason		Death or Disability		Involuntary Termination without Cause or Resignation for Good Reason		Change in Control
Michael J. Beyer,
President and Chief Executive Officer
Oscar A. Martinez,
Senior Vice President—Chief Financial Officer
Donald R. Holcomb,
previous Principal Financial Officer
Christopher Cline,
Principal Strategy Officer
H. Drexel Short,
Senior Vice President—Mining Operations
Rashda M. Buttar,
Senior Vice President—General Counsel & Corporate Secretary

 

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Compensation Structure Following the Offering

This section discusses certain compensation-related actions taken or that are expected to be taken in connection with this offering.

Long-Term Incentive Plan

In connection with this offering, the board of directors of our general partner may adopt the long-term incentive plan for directors, officers and employees, contractors and consultants who perform services for us.

Other Benefit Plans

Following the completion of this offering, our named executive officers and other employees will continue to be eligible to participate in retirement, health, life, severance and other benefit plans that we may offer. These benefits will be provided under plans that will be established by our general partner in connection with this offering.

Director Compensation

Following the consummation of this offering, we will provide compensation to the non-employee directors of the board of our general partner; however, certain terms of that compensation policy have not yet been established. Our employees who also serve as directors will not receive additional compensation. It is anticipated that each non-employee director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees, and that each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

 

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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 affiliates, including Foresight Reserves, on the one hand, and our partnership and our unaffiliated limited partners, on the other hand. 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 duty to manage our partnership in a manner it believes is in our best interests. 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 and 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 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. 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 interests of the partnership. See “Management—Management of Foresight Energy Partners LP—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 or accelerate the right to convert subordinated units.

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;

 

•

Cash expenditures;

 

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•

Borrowings;

 

•

Entry into and repayment of current and future indebtedness, including the redemption or defeasance of the Senior Notes;

 

•

Issuance of additional units; and

 

•

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 any subordinated units held by them or the incentive distribution rights; or

 

•

Hastening the expiration of the subordination period.

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 subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash or equity distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. 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 and our subordinated 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, in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that permissibly reduce 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.

In addition, at any time after August 15, 2014, our general partner may, in its sole discretion, redeem, repurchase, refinance or otherwise amend the indenture governing the Senior Notes or amend the Senior Secured Credit Facility, in each case in a manner that terminates the PIK period. Under our partnership agreement, such decision will explicitly be deemed not a violation of fiduciary duties that might otherwise be owed by our general partner to the limited partners.

 

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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 shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was not adverse to the interests of our partnership;

 

•

our general partner and its officers and directors will not be liable for monetary damages 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 our general partner or those other persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that its conduct was unlawful; and

 

•

in resolving conflicts of interest, it will be presumed that in making its decision the general partner, the board of directors of the 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.

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.”

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;

 

•

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;

 

•

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

 

•

distributing cash;

 

•

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

 

•

maintaining insurance for our benefit;

 

•

forming, acquiring an interest in, and contributing property and loaning money to, any further limited partnerships, joint ventures, corporations, limited liability companies or other relationships;

 

•

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;

 

•

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 interests relating to our partnership interests; and

 

•

entering into agreements with any of its affiliates 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 market price calculated in accordance with the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your 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 call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. See “The Partnership Agreement—Call Right.”

We may not choose to 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. We do not intend to do so in most cases.

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 is restricted from engaging in any business other than those incidental to its ownership of interests in us. However affiliates of our general partner are not

 

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prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Foresight Reserves or its affiliates, may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to acquire those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

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 incentive distribution levels without the approval of our unitholders. This election may 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 they have received incentive distributions at the highest level to which they are entitled (50.0%) 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, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for them to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved. As a result, a reset election may cause our common unitholders to experience dilution 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—Adjusted Operating Surplus—Incentive Distribution Rights.”

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 modifying and restricting 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. The modifications to the fiduciary standards benefit our general partner

 

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by enabling it to take into consideration all parties involved in the proposed action. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

 

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” and will not be subject to any other 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 standards replace the obligations to which our general partner would otherwise be held.

 

If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general partner or its affiliates, 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, its board, which may include board members affected by the conflict of interest, 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. These standards replace the obligations to which our general partner would otherwise be held.

 

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

 

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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.

 

Partnership agreement modified standard

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its good faith reliance on the provisions of our partnership agreement.

By purchasing our common units, each common unitholder automatically 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 these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their 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 will own, directly or indirectly,             common units and              subordinated units representing an aggregate approximately     % limited partner interest in us, and will own and 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.

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 Partners 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 and a structuring fee and the expenses of this offering) to Foresight Reserves. 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. Any common units not purchased by the underwriters pursuant to their option will be issued to Foresight Reserves.

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.

 

During the PIK period, we will pay distributions in respect of our subordinated units in the form of additional subordinated units. At

 

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the closing of this offering, our general partner and its affiliates will own 100% of the subordinated 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 Partners 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.

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 the Company. In exchange, we caused each of Williamson, Sugar Camp, Hillsboro and Macoupin to enter into Surface Lease and Transportation Agreements with Savatran and Sitran. In addition, in August 2011, an affiliated company owned by Foresight Reserves acquired the IC RailMarine Terminal in Convent, Louisiana. We have entered into an agreement to operate this terminal for 10 years. Those agreements are described in “Business—Transportation.” See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of these lease agreements.

Natural Resource Partners, L.P. Transactions

We have engaged in a series of transactions with NRP, an entity in which Christopher Cline indirectly owns 15.7% of the limited partnership interests (as well as 31% of the limited partnership interests in its general partner). Foresight Reserves and its subsidiaries have sold to NRP or subsidiaries of NRP certain coal reserves and

 

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transportation assets in exchange for equity in NRP and its general partner as well as entering into Restricted Business Contribution Agreement leases under which we will make royalty payments and pay fees as we mine leased coal and use leased transportation facilities, 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 a subsidiary of NRP subject to the lease agreements. The agreements allowed for the mining, processing, and transporting of coal reserves located in Illinois. The terms of the coal lease agreements included the requirement for Williamson to pay minimum royalties, tonnage royalties based on the tonnage sold, and wheelage.

We sold approximately 144 million tons of reserves to NRP in a 3-stage transaction throughout 2005 and 2006, and amended and restated the associated coal mining lease. 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.

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. We expect to consummate additional deals under the Restricted Business Contribution Agreement in the future.

One of the entities acquired by NRP at the closing was Williamson Transport, LLC, which has a sublease agreement related to leased surface rights at Williamson for the Williamson Rail Load Out facility. 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.

Also at the closing, an NRP affiliate acquired Independence Land Company, LLC, which had previously been owned by Foresight Reserves. We had previously entered into a coal mining lease with Independence to lease a certain tract of approximately 3,500 acres adjacent to the Williamson mining complex to perform certain mining activities on the tract. The term of this agreement is 15 years and can be renewed for an additional five years or until all merchantable and mineable coal has been mined and removed. 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.

In January 2009, NRP acquired additional coal reserves and infrastructure assets related to Macoupin for $143.7 million. Simultaneous with the closing, Macoupin entered into a lease transaction with affiliates of NRP 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, minimums, and wheelage fees.

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 annual rental payment. Macoupin is responsible for operations, repairs and maintenance and for keeping rail facilities in good working order.

In September 2009, NRP through its subsidiary WPP LLC, 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 will lease this coal from NRP. See “Management’s Discussion and Analysis of Financial Condition and

 

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Results of Operations.” Five of the eight transactions have closed for an aggregate amount of $175 million. In February 2012, WPP is scheduled to close the sixth transaction for $40 million. The last two transactions, for an aggregate amount of $40 million, are scheduled to occur five days after the first pass of the longwall shearer across the face, after which WPP will have acquired all of the approximately 200 million tons of coal reserves. We will not directly receive any of the proceeds of these three future sale transactions. 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 and minimums.

In addition, we have entered into various ancillary agreements with NRP and its subsidiaries providing for acquisition of additional mineral rights, sub-leases and surface leases, all in support of our mining and transportation transactions with NRP for leased reserves and use of transportation assets.

As a result of these transactions and contracts, at December 31, 2010, we had accounts payable to NRP or its affiliates totaling $5.3 million. For the years ended December 31, 2010 and 2009, we made payments of approximately $62.0 million and $42.0 million, respectively, to NRP or its affiliates. As of December 31, 2010, we have paid NRP or affiliates $22.8 million in advance minimum royalty payments that have not been recouped.

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

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.

Other Related Party Transactions

We have entered into mineral and surface leases with Colt, Montgomery Mineral, New River Royalty LLC and other affiliates by common ownership to obtain rights to mine coal at our mines. The terms of these leases are consistent with lease arrangements with third party lessors and provide for royalty payments, minimums and wheelage charges on substantially similar terms.

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 our travel expenses incurred by us and our subsidiaries.

 

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As part of the 2010 Reorganization we entered into a series of mineral leases requiring minimum royalty payments and production royalty payments to our affiliated companies Colt and Ruger. See “Business—Coal Reserves.”

Several affiliates by common ownership which own or lease property on which we conduct mining have obtained subsidence rights either from the surface owner or lessor. Normally, these rights permit us to subside the surface owner’s property in exchange for subsidence mitigation. The extent of the mitigation is normally determined at the time we undermine the surface, and the cost is normally not material to our operations. Because those subsidence rights were previously held by affiliates by common ownership, we have entered into global assignments of such rights in exchange for our obligation to satisfy all subsidence mitigation.

 

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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 100% by Foresight Reserves.

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 to be Beneficially Owned				Percentage of Common Units to be Beneficially Owned				Subordinated Units to be Beneficially Owned				Percentage of Subordinated Units to be Beneficially Owned				Percentage of Total Common and Subordinated Units to be Beneficially Owned
Foresight Energy GP LLC			—				—				—				—				—
Foresight Reserves															100	%
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 Facility

General

Our Senior Secured Credit Facility provides for a $400 million revolving credit facility with a maturity date of August 12, 2014, including a $125 million letter of credit sub-facility and a $25 million swingline loan sub-facility. In addition, we may request up to $25 million (which amount may be increased to $100 million upon the satisfaction of certain conditions) in incremental revolving credit or term loan facilities, subject to certain conditions and receipt of commitments by existing or additional financial institutions or institutional lenders. All borrowings under our Senior Secured Credit Facility 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 Senior Secured 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 or (2) a base rate plus an applicable margin, in each case, determined in accordance with our consolidated net leverage ratio. We paid an upfront fee to the lenders equal to a percentage of each lender’s commitment under the Senior Secured Credit Facility. We are also required to pay a commitment fee to the lenders under the Senior Secured Credit Facility in respect of unutilized commitments thereunder, such commitment fee being determined in accordance with our consolidated net leverage ratio. In addition, we are required to pay customary letters of credit fees.

Prepayments and commitment reductions

Voluntary prepayments and commitment reductions are permitted, in whole or in part, in minimum amounts without premium or penalty, other than customary breakage costs with respect to LIBOR loans.

Collateral and guarantors

Our obligations under the Senior Secured Credit Facility are unconditionally guaranteed by Foresight Energy Finance Corporation and our direct and indirect domestic subsidiaries, and is secured by first priority perfected liens on substantially all of our existing and future assets, including all material personal, real or mixed property, a pledge of our capital stock, the capital stock of our domestic subsidiaries and up to 66.6% of the voting capital stock of our future foreign subsidiaries that are directly owned by us or any of the guarantors.

Restrictive covenants and other matters

Our Senior Secured Credit Facility requires that we comply on a quarterly basis with certain financial covenants, including a minimum consolidated interest coverage ratio test and a maximum consolidated net leverage ratio test. In addition, our Senior Secured Credit Facility includes 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 except that we may incur additional indebtedness pursuant to increases to the senior secured revolving credit facility, subject to certain restrictions;

 

•

Make investments, loans, guarantees or advances;

 

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•

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 under the senior secured revolving credit facility; and

 

•

Enter into certain swap contracts.

Our Senior Secured Credit Facility contains certain usual and customary representations and warranties, affirmative covenants and events of default. If an event of default occurs, the lenders under our Secured Senior Secured Credit Facility are entitled to take various actions, including the acceleration of amounts due under our Senior Secured Credit Facility 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 Facility is tied to, among other things, and subject to specified exceptions, our pro forma compliance with the then applicable financial covenants described above. If we are in pro forma compliance with our financial covenants, our Senior Secured Credit Facility generally permits us to pay restricted payments in an amount equal to 50% of our cumulative consolidated net income since January 1, 2011 (reduced by 50% of our cumulative consolidated net loss for the same period). However, even if we are not in pro forma compliance with our financial covenants, 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 (including this offering) and an additional 6% per annum (renewing annually) based on net cash proceeds received by or contributed to Foresight Energy LLC from public equity offerings. As of December 31, 2011, we estimate we had approximately $             million of availability under the cumulative consolidated net income and qualified equity offering build-up baskets for restricted payments under the Senior Secured Credit Facility.

Senior Notes

General

On August 12, 2010, Foresight Energy LLC and Foresight Energy Finance Corporation (the “Issuers”) issued $400 million aggregate principal amount of Senior Notes with a maturity date of August 15, 2017. The Senior Notes bear interest at a rate of 9.625% per annum based upon a 360-day year of twelve 30-day months, payable semi-annually on February 15th and August 15th 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 formed to serve as the co-issuer of the Senior Notes and has no material assets or operations of its own.

Optional Redemption

Prior to August 15, 2014, the Issuers may redeem the 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, 2013, the Issuers may redeem up to 35% of the aggregate principal amount of the Senior Notes at a price equal to

 

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109.625% of the aggregate principal thereof with the proceeds of a qualified equity offering, subject to at least 65% of the aggregate principal amount the Senior Notes remaining outstanding after giving effect to any such redemption.

After August 15, 2014, the Issuers may redeem the Senior Notes at a price equal to 104.813% of the aggregate principal amount of the Senior Notes redeemed prior to August 15, 2015, 102.406% of the aggregate principal amount of the Senior Notes redeemed prior to August 15, 2016 and at 100.000% of the aggregate principal amount of the Senior Notes redeemed thereafter.

Repurchase at the Option of Holders

Upon the occurrence of a change of control triggering event (defined as the occurrence of a change of control and a decline in the ratings of the Senior Notes) or the receipt by the Issuers of asset sale proceeds in excess of $35.0 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 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.

Guarantors

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

Restrictive covenants and other matters

The 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:

 

•

Create liens on assets;

 

•

Incur additional indebtedness;

 

•

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

In addition, at any time that the 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 Senior Notes decline below investment grade.

 

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Restricted Payments Covenant

In particular, our ability to make certain restricted payments including dividends under the indenture governing our Senior Notes is tied to, among other things, and subject to specified exceptions, our adjusted EBITDA to fixed charge coverage ratio of at least 2.125 to 1.0. If we are able to incur $1.00 of additional debt under such fixed charge coverage ratio test, our indenture permits us to pay restricted payments in an amount equal to 50% of our cumulative consolidated net income since July 1, 2010 (reduced by 100% of our cumulative consolidated net loss for the same period), plus net cash proceeds received by or contributed to Foresight Energy LLC from certain qualified equity offerings (including this offering) and certain additional amounts. Even if we do not meet the fixed charge coverage ratio test, we may still make certain restricted payments, including, without limitation, in an amount up to 6% per annum (renewing annually) based on net cash proceeds received by or contributed to Foresight Energy LLC from public equity offerings. As of December 31, 2011, we estimate we had approximately $             million of availability under the cumulative consolidated net income and qualified equity offering build-up baskets for restricted payments under the indenture governing our Senior Notes.

Sugar Camp Financing Arrangement

Sugar Camp, as the borrower, and Foresight Energy LLC, as a guarantor, entered into a credit agreement with financial institutions Calyon Deutschland Niederlassung Einer Franzoosischen Societe Anonyme and Credit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent (the “Sugar Camp Credit Agreement”). The Sugar Camp Credit Agreement provides financing for, and is secured by, the longwall mining system, which Sugar Camp has entered into an agreement to purchase. The total estimated cost of the longwall miner is approximately $98.1 million. Currently, Sugar Camp received financing of up to $83.4 million toward the $98.1 million estimated cost of the longwall mining system. In addition, the Sugar Camp Credit Agreement provides for financing of 100% of the fees related to the loan and for 100% of $9.4 million of eligible interest on the loan during the construction of the longwall miner. The Sugar Camp Credit Agreement provides a total commitment of approximately $97.8 million.

Interest accrues on the loan at a fixed rate per annum of 5.78% and is due semi-annually beginning June 30, 2010, unless considered as eligible interest as noted above. Principal is to be repaid in equal semi-annual payments over eight years starting on the first semi-annual principal payment date occurring after the commercial operation date of the longwall miner.

The Sugar Camp Credit Agreement contains various covenants, including financial covenants and restrictions on dividends, liens, investments and other indebtedness. The Sugar Camp Credit Agreement also contains certain customary events of default provisions, which give the lenders the right to accelerate payments of outstanding debt in certain circumstances. At September 30, 2011, we were in compliance with the covenants of the Sugar Camp Credit Agreement.

In connection with these transactions, we will seek certain amendments and/or waivers under this facility.

Hillsboro Financing Arrangement

On May 14, 2010, Hillsboro, 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”). The Hillsboro Credit Agreement provides financing for, and is secured by, the longwall mining system, which Hillsboro has entered into an agreement to purchase. The total estimated cost of the longwall mining system is approximately $89.3 million. Currently, Hillsboro received financing of up to $77.3 million toward the $91.0 million estimated cost of the longwall mining system. In addition, the Hillsboro Credit Agreement provides for financing of 100% of the fees related to the loan and for 100% of $9.4 million of eligible interest on the loan during the construction of the longwall mining system. The Hillsboro Credit Agreement provides a total commitment of approximately $91.0 million.

 

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The Hillsboro Credit Agreement has a set commitment period through September 2012. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semi-annually beginning January 2011 unless considered as eligible interest as noted above. Principal is to be repaid in equal semi-annual payments over eight years starting on the first semi-annual principal payment date occurring after the commercial operation date of the longwall mining system.

The Hillsboro Credit Agreement contains various covenants, including financial covenants and restrictions on dividends by subsidiaries, liens, investments and other indebtedness. The Hillsboro Credit Agreement also contains certain customary events of default provisions, which give the lenders the right to accelerate payments of outstanding debt in certain circumstances. At September 30, 2011, we were in compliance with the covenants of the credit agreement.

In connection with these transactions, we will seek certain amendments and/or waivers under this facility.

 

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DESCRIPTION OF COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of 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 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

            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 the unitholder; and

 

•

other similar fees or charges.

There will be no charge to 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 removals, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

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. Each transferee:

 

•

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

 

•

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

 

•

gives the consents, waivers and approvals 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.

 

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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 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 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. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

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

 

•

with regard to distributions, 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 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 free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. 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.

Distributions

Our partnership agreement specifies the manner in which we will make distributions to holders of our common and subordinated units, 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 require the approval of a “unit majority” require:

 

•

during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the combined subordinated units, voting as separate classes;

 

•

when the subordination period expires, the approval of a majority of the common units, voting as a single class.

In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or 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 June 30, 2023 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. 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.”

 

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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 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:

 

•

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);

 

•

brought in a derivative manner on our behalf;

 

•

asserting a claim of breach of a fiduciary 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;

 

•

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

 

•

asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case, 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 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:

 

•

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 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.

 

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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 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 our limited partners.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated 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 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 special voting rights to which the common unitholders 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 the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. Our 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 fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or 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:

 

•

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

 

•

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 will own approximately     % 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:

 

•

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

 

•

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

 

•

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);

 

•

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;

 

•

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;

 

•

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

 

•

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;

 

•

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

 

•

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

 

•

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:

 

•

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

 

•

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;

 

•

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;

 

•

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

 

•

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 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 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 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 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 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.

 

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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 fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or 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 securities 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:

 

•

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

 

•

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

 

•

the entry of a decree of judicial dissolution of our partnership pursuant to the provisions of the Delaware Act; or

 

•

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.

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:

 

•

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 U.S. 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 March 31, 2022 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 March 31, 2022, 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 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 will own                 of our outstanding limited partner units, including all of our subordinated units.

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

 

•

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, provided such person is not an affiliate of the successor general partner; and

 

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•

if all subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units, respectively, 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 assume, among other things, 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, the 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 partner with respect to such interest transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

•

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

 

•

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.”

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 beneficial owners 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:

 

•

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

 

•

the average of the daily closing prices of the partnership securities of such class over the 20 consecutive trading days immediately preceding the date three days before the date the notice is first 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 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.”

 

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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 the 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 U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, 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:

 

•

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

 

•

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 the U.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 U.S. 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, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

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

 

•

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 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.

 

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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.

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, in their capacity as such, 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.

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;

 

•

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 they make on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. The 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 general partner is entitled to determine in good faith 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.

We will furnish each record holder with information reasonably required for U.S. 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 U.S. federal and state tax liability and in filing his U.S. federal and state income tax returns, regardless of whether he supplies us with the necessary information.

 

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Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, upon reasonable demand and at his own expense, have furnished to him:

 

•

a current list of the name and last known address of each record holder;

 

•

information as to the amount of cash, and a description and statement of the agreed value of any other capital contribution, contributed or to be contributed by each partner and the date on which each became a partner;

 

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copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

 

•

information regarding the status of our business and financial condition (provided that obligation shall be satisfied to the extent the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC pursuant to Section 13 of the Exchange Act); and

 

•

any other information regarding our affairs that our general partner determines is just and reasonable.

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 believes in good faith is not in our best interests, could damage us or our business or that we are required by law or by agreements with third parties to keep confidential.

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. 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 unless they convert prior to the end of PIK period, in which case they would convert into PIK common units. 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, beginning 90 days after we have been subject to the public company reporting requirements 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 equity securities 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, our general partner and its affiliates 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, 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. 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.

 

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Lock-up Agreements

Foresight Reserves, 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                     , 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 U.S. federal income tax consequences that may be relevant to prospective common unitholders. To the extent this section discusses federal income taxes, that discussion is based upon current provisions of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed U.S. 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 common 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.

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 common unitholders. Furthermore, this section focuses on common unitholders who are individual citizens or residents of the United States (for federal income tax purposes), whose functional currencies are the U.S. dollar and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, entities treated as partnerships for federal income tax purposes, estates, trusts, non-resident aliens or other common 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, because each common unitholder may have unique circumstances beyond the scope of the discussion herein, we encourage each common unitholder to consult such unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences that are particular to that unitholder resulting from ownership or disposition of its units.

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 IRS or courts. 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 our units and the prices at which such units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our common unitholders because the costs will reduce our cash available for distribution. Furthermore, our tax treatment, or the tax treatment of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which might 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 common unitholder whose units are loaned to a short seller to cover a short sale of units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (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 federal income tax purposes and, therefore, generally will not be liable for federal income taxes. Instead, as described below, each of our common 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 common unitholder had earned such income directly, even if no cash distributions are made to the common unitholder. Distributions by us to a common unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed to a common unitholder 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 approximately             % 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 regarding the composition of our income and the other representations set forth below, 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 treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes. In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied include, without limitation:

(a) Neither we nor any of our limited liability company 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 has been and 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 common 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 distributing that stock to our common unitholders in liquidation of their units. This deemed contribution and liquidation should not result in the recognition of taxable income by our common 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.

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 common unitholders. Accordingly, our taxation as a corporation would materially reduce our cash distributions to common unitholders and thus would likely substantially reduce the value of our units. In addition, any distribution made to a common unitholder would be treated as (i) taxable dividend income to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the common unitholder’s tax basis in our 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.

Tax Consequences of Unit Ownership

Limited Partner Status

Common unitholders who are admitted as limited partners of the partnership, as well as common 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

 

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federal income tax purposes. For a discussion related to the risks of losing partner status as a result of short sales, please read “—Treatment of Short Sales.” Common 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 common unitholders, we will not pay any federal income tax. Rather, each common unitholder will be required to report on its income tax return its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a common 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, 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less 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 (i) make a future offering of common units and use the proceeds of the offering or (ii) use the cash not distributed to the subordinated units during the PIK period, in each case, 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 common unitholder’s tax basis in its units initially will be the amount it paid for those units plus its initial share of our liabilities. That basis generally will be (i) increased by the common unitholder’s share of our income and any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions to it, by its share of our losses, any decreases in its share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized.

 

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Treatment of Distributions

Distributions made by us to a common unitholder generally will not be taxable to the common unitholder, unless such distributions are of cash or marketable securities that are treated as cash and exceed the common unitholder’s tax basis in its units, in which case the common unitholder will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a common unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that common unitholder. A decrease in a common unitholder’s percentage interest in us because of our issuance of additional units will decrease the common unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a common unitholder’s share of our nonrecourse liabilities generally will be based upon that common unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the common unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution described above) may cause a common unitholder to recognize ordinary income, if the distribution reduces the common unitholder’s share of our “unrealized receivables,” including depreciation 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 common unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for an allocable portion of the non-pro rata distribution. This latter deemed exchange generally will result in the common unitholder’s realization of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the common unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

The deduction by a common unitholder of its share of our losses will be limited to the lesser of (i) the common unitholder’s tax basis in its units, and (ii) in the case of a common unitholder who is an individual, estate, trust or corporation (if more than 50% of the corporation’s stock is owned directly or indirectly by or for five or fewer individuals or a specific type of tax exempt organization), the amount for which the common unitholder is considered to be “at risk” with respect to our activities. In general, a common 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 common 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 common unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another common unitholder or can look only to the units for repayment.

A common unitholder subject to the basis and at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions as a result of a reduction in a common unitholder’s share of nonrecourse liabilities) cause the common unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a common unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that the common 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 common 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.

In addition to the basis and at risk limitations, passive activity loss limitations generally limit the deductibility of losses incurred by individuals, estates, trusts, some closely held corporations and personal 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

 

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partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future. Passive losses that are not deductible because they exceed a common unitholder’s share of 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 activity loss rules 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” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

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interest on indebtedness properly allocable to property held for investment;

 

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interest expense attributed to portfolio income; and

 

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a common 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. Such term generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A common 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 common unitholder, we are authorized to pay those taxes and treat the payment as a distribution of cash to the relevant common unitholder. Where the relevant common unitholder’s identity cannot be determined, we are authorized to treat the payment as a distribution to all current common unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a common unitholder, in which event the common unitholder may be entitled to claim a refund of the overpayment amount. Common 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

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. At any time that cash distributions are made to the common units in excess of cash distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. In addition, we may make special allocations of income, gain, loss, deduction, unrealized gain, and unrealized loss among the partners in a manner to create economic uniformity among the common units or PIK common units into which the subordinated units convert and the common units held by public unitholders. If we have a net loss, our items of income, gain, loss and deduction will be allocated first among our common unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and thereafter to our general partner.

 

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Specified items of our income, gain, loss and deduction will be allocated under 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”). In addition, items of recapture income will be specially allocated to the extent possible to the common unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other common unitholders.

An allocation of items of our income, gain, loss or deduction, generally must have “substantial economic effect” as determined under Treasury Regulations. If an allocation does not have substantial economic effect, it will be reallocated to our common unitholders the basis of their interests in us, which will be determined by taking into account all the facts and circumstances, including:

 

•

our partners’ relative contributions to us;

 

•

the interests of all of our partners in our profits and losses;

 

•

the interest of all of our partners in our cash flow; and

 

•

the rights of all of our partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. 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 under our partnership agreement will have substantial economic effect.

Treatment of Short Sales

A common unitholder whose units are loaned to a “short seller” to cover a short sale of units may be treated as having disposed of those units. If so, such common 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 common unitholder, and (ii) any cash distributions received by the common unitholder as to those units would be fully taxable, possibly as ordinary income.

Due to lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a common unitholder whose units are loaned to a short seller to cover a short sale of our units. Common 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 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.”

Treatment of Liquidation and Termination

In general, if we liquidate or terminate the Partnership and sell all of the partnership’s assets, any gain or loss recognized upon such sale generally will be allocated among our unitholders in the manner described under “—Allocation of Income, Gain, Loss and Deduction”. Please read “—Treatment of Distributions” for a discussion of the treatment of any distributions that may result from a liquidation of the partnership. For a general discussion of the events and circumstances of a liquidation and termination of the Partnership, please read “The Partnership Agreement—Dissolution” and “The Partnership Agreement—Liquidation and Distribution of Proceeds.”

Alternative Minimum Tax

If a common unitholder is subject to federal alternative minimum tax, such tax will apply to such common unitholder’s distributive share of any items of our income, gain, loss or deduction. The current alternative minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable

 

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income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective common unitholders are urged to consult with their tax advisors with respect to the impact of an investment in our units on their alternative minimum tax liability.

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 35% and 15%, respectively. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

A 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts will apply for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a common unitholder’s allocable share of our income and gain realized by a common unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the common unitholder’s net investment income from all investments, or (ii) the amount by which the common unitholder’s modified adjusted gross income exceeds $250,000 (if the common unitholder is married and filing jointly or a surviving spouse), $125,000 (if the common unitholder is married and filing separately) or $200,000 (in any other case).

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 purchased units under Section 743(b) of the Code to reflect the unit purchase price. 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. The Section 743(b) adjustment does not apply to a person who purchases units directly from us. For purposes of this discussion, a common unitholder’s basis in our assets will be considered to have two components: (1) its share of the tax basis in our assets as to all common unitholders (“common basis”) and (2) its Section 743(b) adjustment to that tax basis (which may be positive or negative).

Under Treasury Regulations, a Section 743(b) adjustment attributable to property depreciable under Section 168 of the Code may be amortizable over the remaining cost recovery period for such property, while a Section 743(b) adjustment attributable to properties subject to depreciation under Section 167 of the Code, must be amortized straight-line or using the 150% declining balance method. As a result, if we owned any assets subject to depreciation under Section 167 of the Code, the amortization rates could give rise to differences in the taxation of common unitholders purchasing units from us and common unitholders purchasing from other common unitholders.

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 these or any other Treasury Regulations. Please read “—Uniformity of Units.” Consistent with this authority, we intend to treat properties depreciable under Section 167, if any, in the same manner as properties depreciable under Section 168 for this purpose. These positions are consistent with the methods employed by other publicly traded partnerships but are inconsistent with the existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach.

The IRS may challenge our position 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 common 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 common unitholder’s basis in its units, and may cause the common 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.

 

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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 common 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 common 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 common 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 basis 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. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interests in us prior to this offering. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

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 previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a common 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” and “—Disposition of Units—Recognition of Gain or Loss.”

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 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

 

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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 common unitholders could change, and common 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. Please read “—Tax Consequences of Unit Ownership—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.

We generally elect to defer mine development expenses, consisting of expenditures incurred in making coal available for extraction, after the exploration process has disclosed the existence of coal in commercially marketable quantities, and deduct them on a ratable basis as the coal benefited by the expense is sold.

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.

 

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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 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.

 

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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 recently released President Obama’s Proposed Fiscal Year 2012 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) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment for coal royalties and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. 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.

 

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Disposition of Units

Recognition of Gain or Loss

A common unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the common unitholder’s amount realized and tax basis for the units sold. A common unitholder’s amount realized 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 common 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 common 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, primarily depletion and depreciation 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 common unitholder may recognize both ordinary income and a capital 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.

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 common 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 above, a common 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 common 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 common 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” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) 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.

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 also 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.

 

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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 common 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”). Nevertheless, we allocate certain deductions for depletion and depreciation of capital additions based upon the date the underlying property is placed in service, and 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 common unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a common 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 common unitholders. Nonetheless, the safe harbor in the proposed regulations differs slightly from the proration method we have adopted because the safe harbor would allocate tax items among the months based upon the relative number of days in each month, and could require certain tax items which our general partner may not consider extraordinary to be allocated to the month in which such items actually occur. 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 common unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the common unitholder’s interest, our taxable income or losses might be reallocated among the common unitholders. We are authorized to revise our method of allocation between transferee and transferor common unitholders, as well as among common unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A common 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 common unitholder who sells or purchases any 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). 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 terminated our 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 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 our partnership for federal income tax purposes. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all common unitholders. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such common unitholder’s taxable income for the year of termination.

 

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A constructive termination occurring on a date other than December 31 will result in us filing 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, among other things, a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a 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 might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units and for 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, both statutory and regulatory. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6), which is not anticipated to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

If necessary to preserve the uniformity of our units, our partnership agreement permits our general partner to take positions in filing our tax returns even when contrary to a literal application of regulations like the one described above. These positions may include reducing for some common unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some common unitholders than that to which they would otherwise be entitled. The general partner does not anticipate needing to take such positions, but if they were necessary, Vinson & Elkins L.L.P. would be unable to opine as to validity of such filing positions in the absence of direct and controlling authority.

A common 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 common unitholder’s basis in its units, and may cause the common 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, other tax-exempt organizations, non-resident aliens, 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 common unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor 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 common unitholder.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of their ownership of our units. Consequently, they will be 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

 

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traded partnerships, distributions to non-U.S. common unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. common 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. A change in applicable law may require us to change these procedures.

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 United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate common unitholder is a “qualified resident.” In addition, this type of common unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A foreign common 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 foreign common unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign common unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that common unitholder’s gain would be effectively connected with that common unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common 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 common 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, foreign common 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 common 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 common unitholder’s share of income, gain, loss and deduction. We cannot assure our common unitholders that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

Neither we, nor Vinson & Elkins L.L.P. can assure prospective common unitholders that the IRS will not successfully contend in court that those positions are impermissible, and such a contention could negatively affect the value of the units. The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each common unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of its own return. Any audit of a common unitholder’s return could result in adjustments not related to our returns as well as those related to its returns.

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 with 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 will make some elections on our behalf and on behalf of common unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against common unitholders for items in our returns. The Tax Matters Partner may bind a common unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that common 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 common 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 common unitholder having at least a 1% interest in profits or by any group of common unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each common unitholder with an interest in the outcome may participate in that action.

A common 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 common 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

An additional tax equal to 20% of the amount of any portion 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, is imposed by the Code. 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.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority”; or

(2) as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

 

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If any item of income, gain, loss or deduction included in the distributive shares of common unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for common unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit common unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly our common unitholders and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single tax year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly our common unitholders’ tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our common unitholders may be subject to the following additional consequences:

 

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accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

 

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for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

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in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local and Other Tax Considerations

In addition to federal income taxes, common unitholders will 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 or in which the common unitholder is a resident. Moreover, we may also own property or do business in other states in the future that

 

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impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective common unitholder should consider their potential impact on its investment in us.

It is the responsibility of each common unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of its investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in us. We strongly recommend that each prospective common unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each common unitholder to file all tax returns that may be required of it.

 

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INVESTMENT IN FORESIGHT ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to 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. For these purposes 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 and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

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whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

 

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whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

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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, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan or IRA.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified 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.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

                 are acting as joint book-running managers of the offering and 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
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.

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. 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, 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                  , dispose of or hedge any common units or any securities convertible into or exchangeable for our common units, with certain exceptions.

Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our company occurs; or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.                  , in their sole discretion, may release any of the securities subject to these lock-up agreements at any time and without notice.

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

 

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available for sale to the general public will be reduced by the number of directed units purchased by participants in the program. 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                         , 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.                         , in their sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice.                           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 will apply 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 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.

 

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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.

 

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“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.

 

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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.

 

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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.

 

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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.

 

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Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

 

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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 Facility. Other than the participation as lenders under our Senior Secured Facility 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.

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, Foresight Reserves, our general partner and certain of our affiliates 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:

 

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to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

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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

 

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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 Sales Prospectus Act (Verkaufsprospektgesetz), 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

 

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well as information or statements contained therein, may not be supplied to the public in Germany or used in 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 8f paragraph 2 no. 4 of the German Sales Prospectus 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 or 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.

 

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INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The consolidated financial statements of Foresight Energy LLC as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010 included in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, whose report thereon appears herein. Such financial statements have been so included in reliance on their report given on their authority as experts in auditing and accounting.

The balance sheet of Foresight Energy Partners LP as of January 26, 2012 (date of inception) included in this prospectus and Registration Statement has been audited by Ernst & Young LLP, whose report thereon appears herein. Such balance sheet has been included in reliance on their report given on their authority as experts in auditing and accounting.

 

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EXPERTS—COAL RESERVES

The estimates of our proven and probable coal reserves referred to in this prospectus have been prepared by us and reviewed by Weir International, Inc. and have been included herein upon the authority of this firm as an expert.

 

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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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INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

		Page
Foresight Energy Partners LP:
Report of Independent Registered Public Accounting Firm			F-2
Balance Sheet as of January 26, 2012			F-3
Note to the Balance Sheet as of January 26, 2012			F-4
Foresight Energy LLC and subsidiaries:
Report of Independent Registered Public Accounting Firm			F-5
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008			F-6
Consolidated Balance Sheets as of December 31, 2010 and 2009			F-7
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2010, 2009 and 2008			F-8
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008			F-9
Notes to Consolidated Financial Statements			F-10
Unaudited Condensed Consolidated Statements of Operations for the Nine Months Ended September  30, 2011 and 2010 and the Three Months Ended September 30, 2011 and 2010			F-35
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010			F-36
Unaudited Condensed Consolidated Statements of Members’ Equity for the Nine Months Ended September 30, 2011 and 2010			F-37
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September  30, 2011 and 2010			F-38
Notes to Unaudited Condensed Consolidated Financial Statements			F-39

 

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Table of Contents

Report of Independent Registered Public Accounting Firm

The Partners of Foresight Energy Partners LP

We have audited the accompanying balance sheet of Foresight Energy Partners LP (the Company) as of January 26, 2012 (date of inception). This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit 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 balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Foresight Energy Partners LP at January 26, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Charleston, West Virginia

February 1, 2012

 

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Table of Contents

FORESIGHT ENERGY PARTNERS LP

BALANCE SHEET

AS OF JANUARY 26, 2012 (DATE OF INCEPTION)

 

		January 26, 2012 (Date of Inception)
Assets		$	—
Liabilities		$	—
Partners’ equity:
Limited partner’s equity		$	1,000
General partner’s equity			0
Receivable from partners			(1,000	)
Total partners’ equity		$	—
Total liabilities and partners’ equity		$	—

See note to balance sheet.

 

F-3

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Table of Contents

FORESIGHT ENERGY PARTNERS LP

NOTE TO THE BALANCE SHEET

AS OF JANUARY 26, 2012

(DATE OF INCEPTION)

1. ORGANIZATION AND OPERATIONS

Foresight Energy Partners LP, the “Partnership” is a Delaware limited partnership formed on January 26, 2012 to be the parent of Foresight Energy LLC, an entity engaged primarily in the mining and sale of coal.

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, the Partnership will issue common units and subordinated units, representing additional limited partner interests, to Foresight Reserves, L.P. (“Foresight Reserves”), a Delaware limited partnership, in exchange for its ownership in Foresight Energy LLC. Foresight Energy GP LLC (the “General Partner”), an entity owned by Foresight Reserves, will maintain its non-economic general partner interest in the Partnership. In addition, the Partnership will issue to the General Partner the 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

To the Board of Directors of Foresight Energy LLC

We have audited the accompanying consolidated balance sheets of Foresight Energy LLC, subsidiaries, and affiliates as of December 31, 2010 and 2009, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2010. 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, subsidiaries, and affiliates at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Charleston, West Virginia

March 14, 2011

 

F-5

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Consolidated Statements of Operations

(in thousands)

 

		Year Ended December 31,
		2010				2009				2008
Revenues
Coal sales revenue		$	362,592			$	271,249			$	238,842
Costs and expenses
Cost of coal sales			130,610				101,528				109,421
Transportation expenses			58,482				48,933				46,942
Depreciation, depletion and amortization			55,590				38,937				27,886
Accretion			2,068				1,735				203
Selling, general, and administrative			28,367				22,610				11,913
Gain on coal sale contract termination			—				—				(44,019	)
Other operating (income) expense, net			(2,611	)			(3,208	)			334
Operating income			90,086				60,714				86,162
Other income and expense:
Interest and securities income			67				427				1,360
Interest expense			(40,498	)			(46,466	)			(43,625	)
Loss on interest rate swaps			—				(586	)			—
Net income from continuing operations			49,655				14,089				43,897
Net loss from discontinued operations			(40,893	)			(50,545	)			(41,249	)
Net income (loss)			8,762				(36,456	)			2,648
Less: Net income attributable to noncontrolling interests			909				246				56
Net income (loss) attributable to controlling interests		$	7,853			$	(36,702	)		$	2,592

See accompanying notes.

 

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Consolidated Balance Sheets

(in thousands)

 

		December 31,
		2010				2009
Assets
Current assets:
Cash		$	33,451			$	14,757
Investments in available-for-sale securities			—				42,274
Accounts receivable			24,424				19,569
Affiliate receivables			—				186
Inventories			29,014				19,508
Prepaid and other current assets			4,334				5,913
Assets of discontinued operations			—				63,054
Total current assets			91,223				165,261
Property, plant, equipment, and mine development, net of accumulated depletion and depreciation			995,425				634,250
Prepaid royalties			10,075				7,839
Other assets			35,157				2,467
Assets of discontinued operations			—				226,343
Total assets		$	1,131,880			$	1,036,160
Liabilities and members’ equity
Current liabilities:
Accounts payable – trade		$	40,656			$	48,990
Current portion of notes payable			—				7,263
Current portion of asset retirement obligation			534				1,044
Current portion of accrued interest payable			14,973				19
Accrued expenses and other current liabilities			2,256				2,508
Affiliate payable			8,057				16,751
Liabilities of discontinued operations			—				103,412
Total current liabilities			66,476				179,987
Notes payable, long-term portion			605,390				338,490
Capitalized sale-leaseback financing arrangements, long-term portion			143,484				143,484
Accrued interest payable, long-term portion			12,678				8,742
Asset retirement obligation			21,786				24,865
Liabilities of discontinued operations			—				207,489
Total liabilities			849,814				903,057
Members’ equity:
Stock purchase warrant			—				5,000
Controlling interest			283,031				127,862
Noncontrolling interests			(965	)			241
Total members’ equity			282,066				133,103
Total liabilities and members’ equity		$	1,131,880			$	1,036,160

See accompanying notes.

 

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Consolidated Statements of Members’ Equity (Deficiency)

(in thousands)

 

		Controlling Interests				Noncontrolling Interests				Holder of Stock Purchase Warrant				Total
Members’ equity (deficiency) at January 1, 2008		$	(12,600	)		$	79			$	5,000			$	(7,521	)
Cash contributed by members			118,097				—				—				118,097
Net income			2,592				—				—				2,592
Net income of noncontrolling interests			—				56				—				56
Other comprehensive income:
Unrealized losses on available-for-sale securities			70				—				—				70
Total comprehensive income															2,718
Distributions to members			(26,520	)			(72	)			—				(26,592	)
Members’ equity at December 31, 2008			81,639				63				5,000				86,702
Cash contributed by members			145,210				—				—				145,210
Net loss			(36,702	)			—				—				(36,702	)
Net income of noncontrolling interests			—				246				—				246
Other comprehensive loss:
Unrealized losses on available-for-sale securities			(70	)			—				—				(70	)
Total comprehensive loss															(36,526	)
Distributions to members			(62,215	)			(68	)			—				(62,283	)
Members’ equity at December 31, 2009			127,862				241				5,000				133,103
Cash contributed by members			231,073				—				—				231,073
Other members’ contribution			170,216												170,216
Net income			7,853				—				—				7,853
Net income of noncontrolling interests			—				909				—				909
Total Comprehensive Income															8,762
Distribution of subsidiaries			(226,694	)			(1,053	)			(5,000	)			(232,747	)
Distributions to members			(27,279	)			(1,062	)			—				(28,341	)
Members’ equity at December 31, 2010		$	283,031			$	(965	)		$	—			$	282,066

See accompanying notes.

 

F-8

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Consolidated Statements of Cash Flows

(in thousands)

 

		Year Ended December 31,
		2010				2009				2008
Operating activities
Net income (loss)		$	8,762			$	(36,456	)		$	2,648
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization			70,818				57,003				41,643
Accretion on asset retirement obligation			2,068				1,735				203
Change in estimate - ARO			(5,040	)			—				—
Interest on related-party debt			14,689				—				—
Write off of unamortized loan costs			2,977				—				—
Gain on sale of marketable securities			(30	)			(97	)			(88	)
(Gain) loss on interest rate swaps			—				(1,409	)			2,425
Increase (decrease) in cash provided by (used in) attributable to:
Accounts receivable			(346	)			(1,047	)			(12,570	)
Amount due from affiliates, net			(29,440	)			(1,056	)			18,070
Inventories			(8,138	)			(12,040	)			(781	)
Other current assets			2,513				10,527				(3,912	)
Prepaid royalties			(23,251	)			2,943				(5,601	)
Other assets			(24,689	)			10,920				(10,512	)
Accounts payable – trade			(15,405	)			10,371				11,163
Accrued interest payable			42,512				43,483				29,181
Accrued expenses			(5,396	)			603				3,755
Other liabilities			(560	)			21,920				—
Net cash provided by operating activities			32,044				107,400				75,624
Investing activities
Investment in mining rights, equipment, and development			(255,460	)			(348,445	)			(182,627	)
Purchases of investments in available-for-sale securities			(14,948	)			(262,772	)			(24,969	)
Proceeds from sale of available-for-sale securities			33,951				202,503				9,458
Deconsolidation of subsidiaries as part of reorganization			(13,711	)			—				—
Net cash used in investing activities			(250,168	)			(408,714	)			(198,138	)
Financing activities
Member contributions			231,073				145,210				118,097
Proceeds from notes and equipment loans			482,595				60,429				17,300
Repayment of notes and equipment loans			(509,120	)			(14,800	)			—
Proceeds from financing arising from sale-leasebacks			—				143,484				—
Distributions to members			(1,062	)			(4,719	)			—
Net cash provided by financing activities			203,486				329,604				135,397
Net (decrease) increase in cash			(14,638	)			28,290				12,883
Cash at beginning of year			48,089				19,799				6,916
Cash at end of year			33,451				48,089				19,799
Less: Cash included in assets of discontinued operations			—				33,332				16,184
Cash at end of period for continuing operations		$	33,451			$	14,757			$	3,615
Non-cash financing and investing activities
Transfer out of marketable securities to member		$	23,300			$	42,992			$	—
Member contributions		$	17,850			$	—			$	—
Member distributions		$	—			$	14,572			$	26,592

See accompanying notes.

 

F-9

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Consolidated Financial Statements

December 31, 2010

1. Description of Business and Entity Structure

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 (and sometimes preexisting) entities under common control. Foresight Energy is principally engaged in developing, mining, preparation, transportation, and the sale of coal mined in the Illinois basin principally to electric utilities. Foresight Energy is a wholly owned subsidiary of Foresight Reserves, LP (Foresight Reserves). As used herein, “Companies” shall mean Foresight Energy, its subsidiaries and affiliates.

Reorganization and Refinancing

On August 12, 2010, Foresight Energy completed a reorganization of its reporting entity (hereinafter referred to as the Reorganization) and a refinancing of its debt (see Note 6). Prior to the Reorganization, Foresight Energy had mining operations in both the Appalachian and Illinois basins. As part of the Reorganization, the Appalachian operations were transferred outside of the Foresight Energy group and therefore are classified as discontinued operations in the accompanying consolidated financial statements. As such, Foresight Energy now operates only in one segment in the Illinois basin. Also as part of the Reorganization, certain assets and liabilities of Foresight Reserves were transferred into the Foresight Energy group, and certain management costs of Foresight Reserves were allocated to the Foresight Energy group. Transfers of operations, assets, and liabilities between Foresight Reserves and Foresight Energy have been accounted for as transfers among entities under common control. Assets and liabilities transferred are accounted for at historical costs. The accompanying financial statements reflect the above as if they had occurred at the beginning of the first period presented.

On August 12, 2010, Foresight Energy completed a $400 million unsecured senior notes financing transaction and a revolving credit commitment of $285 million. As part of the bond issuance and refinancing, Foresight Reserves committed to make a $100.0 million equity contribution, with $50.0 million due by December 31, 2010, and the remaining $50.0 million due by March 31, 2011. As of December 31, 2010, Foresight Reserves had contributed $70.0 million. Subsequent to year end, Foresight Reserves contributed $30.0 million, bringing the total contributions to $100.0 million as of January 14, 2011. The proceeds from the senior notes, revolving credit agreement and the equity contribution were used to repay existing debt and financing arrangements.

Reorganization - Continuing Operations

Effective with the Reorganization, the following subsidiaries were contributed to and are now 100%-owned subsidiaries of Foresight Energy: Hillsboro Energy LLC (Hillsboro Energy), Macoupin Energy LLC (Macoupin Energy), Sugar Camp Energy, LLC (Sugar Camp Energy), Williamson Energy, LLC (Williamson Energy), Oeneus LLC (dba Savatran LLC) (Savatran), Williamson Track, LLC (Williamson Track), Sitran LLC (Sitran), Adena Resources, LLC (Adena Resources), and Foresight Holding Company LLC (Foresight Holding). Foresight Coal Sales LLC (Foresight Coal Sales), a 100%-owned subsidiary of Foresight Energy, remained unchanged.

At the same time, Williamson Track was merged into Savatran and Foresight Holding was merged into Foresight Energy and was effectively dissolved. All entities involved in the Reorganization were under common control, and the transferred amounts were recorded at their historical values. Accordingly, the accompanying financial statements present the merged entities as though they had always been combined.

 

F-10

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Consolidated Financial Statements (continued)

 

1. Description of Business and Entity Structure (continued)

 

The following entities are perpetual-term Delaware limited liability companies and are included in continuing operations of Foresight Energy as a result of the Reorganization:

 

Entity		Activity
Williamson Energy		Developing, mining, and processing of coal located in Williamson County, Illinois
Hillsboro Energy		Developing, mining, and processing of coal located in Montgomery County, Illinois
Macoupin Energy		Developing, mining, and processing of coal located in Macoupin County, Illinois
Sugar Camp Energy		Developing, mining, and processing of coal located in Franklin County, Illinois
Foresight Coal Sales		Marketing and brokering coal sales for the various coal producing entities
Savatran		Holds title to certain land, right-of-way agreements, and other contracts and is constructing certain transportation systems in the Illinois region
Sitran		Holds title to certain coal transportation facilities in the Indiana and Illinois regions
Adena Resources		Holds certain interests in water agreements and contracts for the mining operations in the Illinois basin

On July 28, 2010, Foresight Energy Corporation, a wholly owned Delaware C-Corporation, was formed for the purpose of assisting Foresight Energy with the selling of certain senior unsecured notes. As of December 31, 2010, there has been no financial activity in this entity.

Foresight Energy, Williamson Energy, Hillsboro Energy, Macoupin Energy, Sugar Camp Energy, Foresight Coal Sales, Savatran, Sitran, Adena Resources, and Foresight Energy Corporation are all affiliated entities under common control and are collectively referred to as the “continuing operations.”

Reorganization – Discontinued Operations

Simultaneous with the financing transactions, Foresight Energy’s entity structure was reorganized resulting in certain entities of the consolidated group being deconsolidated. Foresight Energy distributed 100% of its investments in Gatling LLC (Gatling), Gatling Ohio LLC (Gatling Ohio), Meigs Point Dock LLC (Meigs Point), Lower Wilgat, Middle Wilgat, LLC (Middle Wilgat), and Upper Wilgat, and all of their subsidiaries and affiliates, except for Williamson Energy, to Foresight Reserves. The effects of the deconsolidation are reflected as the discontinued operations in the 2010, 2009, and 2008 financial statements.

As such, the following entities are included in discontinued operations of Foresight Energy:

 

Entity		Activity
Upper Wilgat		Holding company for coal mining operations
Middle Wilgat		Holding company for coal mining operations
Lower Wilgat		Holding company for coal mining operations
Gatling		Developing, mining, and processing of coal located in Mason County, West Virginia
Gatling Ohio		Developing, mining, and processing of coal located in Meigs County, Ohio
Meigs Point		Holds title to certain coal transportation facilities in Meigs County, Ohio

Upper Wilgat, Middle Wilgat, Lower Wilgat, Gatling, Gatling Ohio, and Meigs Point are all affiliated entities under common control and are collectively referred to as the “discontinued operations.”

 

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Consolidated Financial Statements (continued)

 

1. Description of Business and Entity Structure (continued)

 

Variable Interest Entities

In accordance with accounting principles generally accepted in the United States of America, these financial statements include certain other entities considered variable interest entities (VIEs) for which the Companies are the primary beneficiary. These entities include Mach Mining, LLC (Mach Mining), Big River Mining, LLC (Big River Mining), Clearwater Processing, LLC (Clearwater Processing), M-Class Mining, LLC (M-Class Mining), Yellow Bush Mining, LLC (Yellow Bush Mining), Coal Field Construction Company LLC (Coal Field Construction), MaRyan Mining LLC (MaRyan Mining), and Patton Mining LLC (Patton Mining). Big River Mining, Yellow Bush Mining, and Clearwater Processing are VIEs of entities included in discontinued operations as a result of the Reorganization and, therefore, are also included in discontinued operations in the accompanying financial statements. Additional VIEs of Mach Processing LLC, Meigs Processing LLC, Patton Processing LLC, and MaRyan Processing LLC were included and merged with the existing VIEs above effective December 31, 2009. These entities are owned by Coal Field Transports, Inc. whose common stock is wholly owned by a third party. All of the entities described above own no equipment, real property, or other intangible assets and each holds a contract to provide contract mining, processing, and/or loading services or construction services to a Foresight Energy subsidiary as outlined below.

 

•

Foresight Energy (continuing operations)

Coal Field Construction has various contracts with and is responsible for providing construction services for various Foresight Energy entities. Currently, these are the only contracts that Coal Field Construction has entered into.

 

•

Williamson Energy (continuing operations)

Mach Mining is responsible for providing all contract mining services, processing, and loading services for coal mined from the Williamson Energy mining complex on a cost-plus basis. These contracts are currently the only contracts for mining, processing, and loading services executed by Mach Mining. The contracts are not exclusive and can be terminated at any point by Williamson Energy. Under the terms of the agreements, Mach Mining has the right to mine such properties at the Williamson Energy complex located in Williamson County, Illinois.

 

•

Sugar Camp Energy (continuing operations)

M-Class Mining is responsible for providing all contract mining services, processing, and loading services for coal mined from the Sugar Camp Energy mining complex on a cost-plus basis. These contracts are currently the only contracts for mining, processing, and loading services executed by M-Class Mining. The contracts are not exclusive and can be terminated at any point by Sugar Camp Energy. Under the terms of the agreements, M-Class Mining has the right to mine such properties at the Sugar Camp Energy complex located in Franklin County, Illinois.

 

•

Hillsboro Energy (continuing operations)

Patton Mining is responsible for providing all contract mining services, processing, and loading services for coal mined from the Hillsboro Energy mining complex on a cost-plus basis. These contracts are currently the only contracts for mining, processing, and loading services executed by Patton Mining. The contracts are not exclusive and can be terminated at any point by Hillsboro Energy. Under the terms of the agreements, Patton Mining has the right to mine such properties at the Hillsboro Energy complex located in Montgomery County, Illinois.

 

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Consolidated Financial Statements (continued)

 

1. Description of Business and Entity Structure (continued)

 

•

Macoupin Energy (continuing operations)

MaRyan Mining is responsible for providing all contract mining services, processing, and loading services for coal mined from the Macoupin Energy mining complex on a cost-plus basis. These contracts are currently the only contracts for mining, processing, and loading services executed by MaRyan Mining. The contracts are not exclusive and can be terminated at any point by Macoupin Energy. Under the terms of the agreements, MaRyan Mining has the right to mine such properties at the Macoupin Energy complex located in Macoupin County, Illinois.

 

•

Gatling (discontinued operations)

Big River Mining has a contract with Gatling to provide contract labor for the mining of coal for Gatling on a cost-plus basis. Currently, this is the only contract for mining services executed by Big River Mining. Under the terms of the agreement, Big River Mining has the right to mine such properties at the Gatling mining complex located in Mason County, West Virginia. Clearwater Processing has a contract with Gatling to provide all the processing for coal mined from the Gatling mining complex by Big River Mining.

 

•

Gatling Ohio (discontinued operations)

Yellow Bush Mining has a contract with Gatling Ohio to provide contract labor for the mining of coal for Gatling Ohio on a cost-plus basis. Currently, this is the only contract for mining services executed by Yellow Bush Mining. Under the terms of the agreement, Yellow Bush Mining has the right to mine such properties at the Gatling Ohio mining complex located in Meigs County, Ohio. Clearwater Processing has a contract with Gatling Ohio to provide all the processing for coal mined from the Gatling Ohio mining complex by Yellow Bush Mining.

The VIEs and Foresight Energy and its subsidiaries and affiliates are collectively referred to as the Companies. None of the Companies or their affiliates’ labor force are represented by a collective bargaining unit. The Companies are subject to federal, state, and local environmental laws and regulations. Foresight Energy does not rely on any single significant customer or vendor.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of Foresight Energy and its subsidiaries, and affiliate entities classified as either continuing operations or discontinued operations. Continuing operations include Williamson Energy, Hillsboro Energy, Macoupin Energy, Sugar Camp Energy, Foresight Coal Sales, Foresight Energy Corporation, Adena Resources, Savatran, Sitran, and other entities determined to be VIEs for which management has determined that the Companies are the primary beneficiary as defined by accounting principles generally accepted in the United States of America. As described in Note 1, Coal Field Construction, Mach Mining, M-Class Mining, Patton Mining, and MaRyan Mining have been determined to be VIEs of the continuing operations of Foresight Energy and its subsidiaries. The interests in net assets of other parties, if any, are shown as noncontrolling interests. Discontinued operations of Foresight Energy include Upper Wilgat, Middle Wilgat, Lower Wilgat, Gatling, Gatling Ohio, Meigs Point, and other entities determined to be VIEs for which management has determined that the Companies are the primary beneficiary as defined by accounting principles generally accepted in the United States of America. Furthermore, as described in Note 1, Big River

 

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Table of Contents

Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

Mining, Clearwater Processing, and Yellow Bush Mining have been determined to be VIEs of Foresight Energy’s discontinued operations and its subsidiaries. All significant intercompany transactions are eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenue includes sales to customers of coal produced at the Companies’ operations and the sale of coal purchased from third parties. The Companies recognize sales at the time legal title and risk of loss pass to the customer at contracted amounts, which is generally when the coal is delivered to an agreed-upon destination. Quality adjustments are recorded as necessary based on contract specifications and are netted against mining revenue and accounts receivable.

As of December 31, 2010, the Sugar Camp Energy and Hillsboro Energy mining operations were considered to be in the development stage because the entities were engaged in the preparation of an established, commercially minable reserve for its extraction. Substantially all of the efforts of Sugar Camp Energy and Hillsboro Energy, through December 31, 2010, were devoted to establishing the business and principal operations. Principal operations for Sugar Camp Energy and Hillsboro Energy are anticipated to begin in 2011 and 2012, respectively. In addition, for the year ended December 31, 2009, the Macoupin Energy mining operations were considered to be in development stage because the entities were engaged in the preparation of an established, commercially minable reserve for its extraction and is not in the production stage. As such, some mining of salable coal will occur in preparation of the installation of the super-sections and the long-wall miners. In accordance with accounting principles generally accepted in the United States of America, the production phase is not deemed to commence with the removal of salable mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to an ore body. Accordingly, coal sales of $10.0 million and $14.3 million for the years ended December 31, 2010 and 2009, respectively, have been recorded as a reduction of mine development costs capitalized.

Gain on Coal Sale Contract Termination

During the year ended December 31, 2008, the Companies recognized a one-time $44 million gain on the cancellation of a coal sales agreement by a third party.

Shipping and Handling Costs

Fees related to the handling and transportation of coal inventory during the production process are included in coal inventory in the consolidated balance sheets. Any transportation expenses related to contract mining sales are included in cost of sales on the consolidated statements of operations. These expenses are directly offset by transportation revenue, included in total revenues on the consolidated statements of operations for amounts billed to customers.

 

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Table of Contents

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Notes to Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

Cash

The Companies consider cash deposits and cash equivalents having an original maturity of less than three months to be cash. Cash is stated at cost, which approximates fair value.

Financial Instruments

Financial instruments include cash and cash equivalents, accounts receivable, investments, accounts payable, and long-term debt. The carrying value of such amounts reported at the applicable balance sheet dates approximates fair value.

Derivative Financial Instruments

The Companies generally utilize derivative financial instruments to manage exposures to commodity prices. Derivative financial instruments consist of oil and diesel fuel futures contracts. The Companies record the fair value of the instruments as either a current asset or current liability on the consolidated balance sheets. The change in value is recorded as a loss or gain in the consolidated statements of operations. Derivative financial instruments are recognized in the consolidated balance sheets at fair value. Certain coal contracts may meet the definition of a derivative instrument, but because they provide for the physical purchase or sale of coal in quantities expected to be used or sold by the Companies over a reasonable period in the normal course of business, they are not recognized on the consolidated balance sheets.

During 2009 and 2010, the Companies had an oil and diesel futures contract which expired during 2010. The total gain or (loss) in the contract for 2010 and 2009 was $0 and $54 thousand, respectively. At December 31, 2010, there were no outstanding diesel future contracts. Also during 2009 through August of 2010, certain discontinued operations had interest rate swap agreements that were terminated during 2010. The Companies recorded liabilities for the fair value of the swaps for continuing operations and discontinued operations as of December 31, 2009 of $586 thousand and $3 million, respectively. The total losses on the interest rate swaps included in continuing operations for 2010, 2009, and 2008 were $1.5 million, $500 thousand, and $0, respectively. At December 31, 2010, there were no outstanding interest rate swaps.

Investments

During 2009, the Companies’ investments consisted of auction-rate securities, money market, and other short-term investment funds. These investments are considered available for sale and are carried at fair value based on the quoted market price at December 31, 2010 and 2009. Auction-rate securities have long-term underlying maturities ranging from 20 to 40 years. Proceeds from sales of securities were $34.0 million, $202.5 million, and $9.5 million during the years ended December 31, 2010, 2009, and 2008, respectively, and are attributable to continuing operations. Net realized and unrealized gains and losses are not significant at December 31, 2010, 2009, or 2008.

 

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Notes to Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

During 2010, the Companies liquidated their investment market portfolio. The composition of investments in available-for-sale securities is as follows as of December 31, 2009 (in thousands):

 

		Carrying Value				Fair Value
Money market funds		$	18,463			$	18,464
Municipal bonds over ten years			23,800				23,810
		$	42,263			$	42,274

As of December 31, 2010 and 2009, the Companies had $0 and $23.8 million, respectively, of auction-rate securities. Interest on these securities is exempt from U.S. federal income tax and the interest rate on the securities typically resets every 30 days. All of the Companies’ auction-rate securities are student loan structured issues, where the loans have been originated under the U.S. Department of Education’s Federal Family Education Loan Program (FFELP). The principal and interest are 100% insured by the U.S. Department of Education.

As a basis for considering market participant assumptions in fair value measurements, the Companies utilize a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Due to the lack of actively traded market data or other observable inputs, the value of the Companies’ auction-rate securities and the resulting unrealized loss, if applicable, would be determined using Level 3 hierarchical inputs. These inputs include management’s assumptions of pricing by market participants, including assumptions about risk. In accordance with the guidance, the Companies reviewed the potential impairment amount through a model where the expected rate of return on the Companies’ auction-rate securities was compared to similar rates of return which an investor would demand in the market.

The Companies review securities for impairment to determine the classification of the impairment as “temporary” or “other than temporary.” In determining whether the decline in value of the auction-rate securities investments was other than temporary, the Companies considered several factors including, but not limited to, the following: (a) the reasons for the decline in value (credit event, interest related, or market fluctuations); (b) the Companies’ ability and intent to hold the investments for a sufficient period of time to allow for recovery of value; (c) whether the decline is substantial; and (d) the historical and anticipated duration of the events causing the decline in value. The evaluation for other-than-temporary impairments is a quantitative and qualitative process, which is subject to various risks and uncertainties. The risks and uncertainties include changes in the credit quality of the securities, changes in liquidity affected by the auction mechanism or issuer calls of the securities, and the effects of changes in interest rates. At December 31, 2009 and 2008, the Companies had the intent and ability to hold their auction-rate securities investments until maturity, if necessary, and, therefore, did not consider any unrealized losses to be other than temporary. During 2010, all auction-rate securities were transferred to Foresight Reserves. No gain or loss was recognized on this transfer to a related party.

Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Companies evaluate the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables,

 

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Notes to Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

bankruptcies, and disputed amounts. At December 31, 2010 and 2009, management had recorded no allowance for uncollectible accounts receivable as all amounts were deemed collectible.

Inventories

Supplies and coal inventories are valued at the lower of cost or market. Supplies inventory consists of spare parts for various equipment and other mining supplies valued using the first-in, first-out method. Raw coal represents coal stockpiles that may be sold in their current condition or may be further processed prior to shipment to a customer. Clean coal represents coal stockpiles that will be sold in their current condition. Coal inventory costs include labor, supplies, equipment costs, and transportation costs prior to title transfer to customers as well as operating overhead. The total amount of operating overhead included in clean coal inventory for continuing operations at December 31, 2010 and 2009, was $1.5 million and $934 thousand, respectively. The total amount of operating overhead included in raw coal inventory for continuing operations at December 31, 2010 and 2009, was $257 thousand and $94 thousand, respectively. Inventories consisted of the following at December 31 (in thousands):

 

		2010				2009
Supplies inventory		$	8,682			$	7,892
Raw coal			2,046				1,431
Clean coal			18,286				10,185
		$	29,014			$	19,508

Prepaid Royalties

Prepaid royalties consist of recoupable minimum royalty payments due under various lease agreements entered into by the Companies and are disclosed in Note 7.

Reclamation Pledged Bond Collateral

The reclamation pledged bond collateral includes cash held by a third-party broker and regulatory oversight authority in a money market account and is included in other assets. The cash is pledged collateral toward the long-term reclamation bonds required by the state of Illinois for the Williamson Energy, Hillsboro Energy, Sugar Camp Energy, and Macoupin Energy mining complexes. The amounts pledged are restricted for the term of the bond and cannot be withdrawn by the Companies without approval from the bonding companies. Reclamation bond collateral approximating $435 thousand and $382 thousand is included in other assets at December 31, 2010 and 2009, respectively. As disclosed in Note 5, certain reclamation bond collateral is maintained at the Foresight Reserves parent level.

Debt Issuance Costs

The Companies capitalize costs incurred in connection with borrowings or establishment of credit facilities, issuance of debt securities, or 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 interest method. At December 31, 2010 and 2009, costs incurred in connection with the issuance of certain debt facilities included in continuing operations totaling $37.1 million and $2.6 million, respectively, were capitalized and are being amortized over the life of the related indebtedness using the effective-interest-rate method. Accumulated amortization at

 

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Notes to Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

December 31, 2010 and 2009, was $2.3 million and $555 thousand, respectively. As of December 31, 2010 and 2009, the unamortized balance of $34.7 million and $2.1 million, respectively, is included in other assets on the consolidated balance sheets.

Exploration Costs

Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred.

Property, Plant, and Equipment

Property, plant, and equipment are recorded at cost, or at fair value in the case of acquired businesses. Interest costs applicable to major additions are capitalized during the construction period. Interest costs capitalized for continuing operations for the years ended December 31, 2010, 2009, and 2008, were $19.1 million, $7.2 million, and $956 thousand, respectively. 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. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 40 years. Additionally, the asset retirement obligation (ARO) for the various assets has been recorded as a component of the specific asset.

Mine Development

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 useful life of the mineral reserves. Additionally, the ARO for the mine development asset has been recorded as a component of mine development. Revenue generated from all mining production during development is offset against the costs of developing the new mines.

Impairment

If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates that the carrying value of the assets will not be recovered, as determined based on projected undiscounted cash flows related to the asset over its remaining life, the carrying value of the asset is reduced to its estimated fair value through an impairment loss.

Asset Retirement Obligation and Reclamation

The Companies’ ARO liabilities primarily consist of estimated spending related to reclaiming surface land and support facilities at both surface facilities and underground mines in accordance with federal and state reclamation laws as defined by each mining permit. Obligations are incurred at the time development of a mine commences for underground mines and surface facilities or in the case of support facilities, refuse areas, and slurry ponds, when construction begins.

The liability is determined using discounted cash flow techniques and is accreted to its present value at the end of each period. The Companies estimate their ARO liabilities 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

 

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Notes to Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

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 Companies record an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. 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 on the straight-line method over its expected life. 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.

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 and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining, and the effects of mining on groundwater quality and availability. One of the primary regulatory matters affecting the Companies’ mining operations, as well as its competitors, pertains to the federal Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSM). The Companies obtain SMCRA permits and permit renewals for their mining operations from the Illinois Department of Natural Resources – Land Reclamation Division. The Companies’ 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 – Land Reclamation Division, 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 Companies endeavor to conduct their 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.

Other Mining-Related Costs and Obligations

Significant components of mining costs are wages and related benefit costs which are paid to employees and the employees of the Companies’ affiliates. Under the current mining arrangements, the Companies’ 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

 

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Notes to Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

benefit pensions and health care coverage for retired employees and future retirees and their dependents. The Companies have obtained workers’ compensation coverage from an independent provider. This coverage includes federal and state black lung and is billed on an annual basis based on estimated gross payroll.

Income Taxes

The Companies and their controlled entities were established as Limited Liability Companies (LLCs) or Limited Partnerships (LPs); thus for federal and, if applicable, state and local income tax purposes, the LLCs/LPs are treated as a partnership. No provision for income taxes related to the operations of the partnership has been included in the accompanying consolidated financial statements because, as a partnership, it is 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 financial reporting basis of assets and liabilities and the taxable income allocation requirements under its partnership agreement. In the event of an examination of the tax return, the tax liability of the partners could be changed if an adjustment in the partnership’s income is ultimately sustained by the taxing authorities.

New Accounting Pronouncements

Fair Value

In January 2010, the Financial Accounting Standards Board (FASB) amended fair value disclosure requirements. This amendment requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The amendment also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements in the reconciliation of activity in Level 3 fair value measurements. The guidance was adopted January 1, 2010 and adoption did not have a material impact on our financial reporting.

Consolidating

In September 2009, the FASB issued new guidance that amends previously issued guidance related to the identification of whether the reporting entity’s variable interest in another entity gives the reporting entity a controlling financial interest in the variable interest entity (VIE), resulting in the requirement to consolidate the VIE. Under the new guidance, the reporting entity is responsible for assessing whether it is responsible for ensuring that the VIE operates as it was designed, as well as determining whether the reporting entity’s ability to direct the activities of the VIE that most significantly impact the other entity’s economic performance. The guidance was adopted January 1, 2010 and adoption did not have a material impact on our financial reporting.

Recognition and Disclosure

In February 2010, the FASB amended certain recognition and disclosure requirements. For certain entities, the amendment requires that the evaluation of subsequent events should be made through the date the financial statements are issued, and that date is not required to be separately disclosed in the subsequent event disclosure. In addition, there were amendments to certain definitions and the scope of disclosure requirements related to reissued financial statement was refined to include revised financial statements only. The amendment is effective for interim or annual periods ending after June 15, 2010. The guidance was adopted January 1, 2010, and adoption did not have a material impact on our financial reporting.

 

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Notes to Consolidated Financial Statements (continued)

 

3. Acquisitions

Macoupin Energy LLC Purchase

On January 22, 2009, Macoupin Energy acquired the idled assets of the MCC No. 1 Mine owned by an unrelated third party in the Illinois coal basin. Under the terms of the sale and purchase agreement, Macoupin Energy purchased the mineral reserves, existing mining equipment, buildings, and structures and other assets. Macoupin Energy also assumed certain liabilities for reclamation and deposited a reclamation bond in the amount of $8.2 million with the state of Illinois. In accordance with accounting principles generally accepted in the United States, the transaction was accounted for as the acquisition of assets and liabilities, which does not constitute a business combination. The total cash purchase price was $45.3 million and the assets and related liabilities acquired were as follows (in thousands):

 

Surface facility, improvements, coal handling facilities, and other equipment		$	24,628
Preparation plant			1,842
Permits			662
Underground production equipment			1,618
Surface lands			2,981
Mineral reserves (within the 30-year mine plan)			30,243
Residual mineral reserves (outside of the 30-year mine plan)			3,849
			65,823
Asset retirement obligation			(20,267	)
Liability for option agreement assumed			(306	)
Cash purchase price		$	45,250

On January 27, 2009, Macoupin Energy entered into a sales agreement with WPP, LLC (WPP) and HOD, LLC (HOD) (entities held by Natural Resource Partners, LP (NRP, LP)) to sell certain mineral reserves and rail facility assets. In exchange for the assets, Macoupin Energy received a total of $143.7 million in cash. Simultaneous with the closing, Macoupin Energy leased back the mineral reserves and the rail facility. The transaction has been accounted for as a lease financing transaction (see Note 7).

 

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Notes to Consolidated Financial Statements (continued)

 

4. Property, Plant, Equipment, and Mine Development

Property, plant, equipment, and mine development consist of the following at December 31 (in thousands):

 

		2010				2009
Land		$	57,719			$	23,420
Land options			807				1,214
Mineral rights			42,744				30,344
Machinery and equipment (3-20 years)			595,798				385,106
Buildings and structures (3-40 years)			144,335				112,508
Mine development costs			326,534				179,122
Railroad spur/track (20 years)			1,151				1,151
Furniture and fixtures (3-10 years)			732				707
Vehicles (3-5 years)			210				210
Less accumulated depreciation			(174,605	)			(99,532	)
		$	995,425			$	634,250

At December 31, 2010, the Companies have committed approximately $3.4 million for construction contracts and approximately $32.4 million for equipment contracts to bring certain mining operations into full production.

In June 2009, Sugar Camp Energy and a third party entered into a purchase and sale agreement to purchase certain long-wall equipment to be utilized by the respective mining operation for a total purchase price of $98.2 million. As of December 31, 2010, the remaining commitment under the agreements totaled $19.9 million.

In March 2010, Hillsboro Energy and a third party entered into a purchase and sale agreement to purchase certain long-wall equipment to be utilized by the respective mining operation for a total purchase price of $91.0 million. As of December 31, 2010, the remaining commitment under the agreement totaled $50.3 million.

5. Related-Party Transactions

The Companies and other affiliated entities routinely engage in transactions in the normal course of business with other affiliated entities under common control, including obtaining contract mining labor, administrative services, and other services and supplies incidental to the production of coal and development of the mine locations. The Companies had affiliate accounts receivable and payable as follows (in thousands):

 

				Receivable (Payable) at December 31
Affiliated Company		Description of Service		2010				2009
Williamson Development, LLC		Affiliate advance		$	—			$	3
Foresight Reserves		Affiliate advance			—				183
				$	—			$	186
NRP, LP/WPP, LLC		Royalties and transportation fees		$	(5,288	)		$	(3,031	)
Foresight Management, LLC		Labor and employee benefits			(2,769	)			(13,720	)
				$	(8,057	)		$	(16,751	)

 

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Notes to Consolidated Financial Statements (continued)

 

5. Related-Party Transactions (continued)

 

A summary of transactions with affiliated entities is as follows for the years ended December 31 (in thousands):

 

		2010				2009				2008
Royalty payments paid to NRP, LP		$	49,408			$	31,665			$	17,030
Fees for transportation services paid to NRP, LP			12,945				9,990				9,170
Allocated management costs to Foresight Energy			10,532				6,980				2,810

In addition, at December 31, 2010 and 2009, certain reclamation bond collateral totaling $18.9 million and $18.7 million, respectively, is now maintained by Foresight Reserves. The Companies also entered into various lease agreements with affiliates as described in Note 7. Foresight Reserves, the parent of Foresight Energy allocates certain management costs to Foresight Energy. Labor, benefits and travel costs are allocated for employees whose primary duties are on behalf of Foresight Energy. Plane usage costs are allocated based on review of the flight logs, including hours, passengers, destinations, and purposes to determine whether a flight was on behalf of Foresight Energy. Fair value billing rates for the respective aircraft obtained from a third party were utilized to determine plane usage costs.

6. Debt and Financing Arrangements

Notes payable consist of the following as of December 31 (in thousands):

 

		2010				2009
9.625% Senior unsecured notes due 2017		$	397,594			$	—
Revolving credit agreement due 2014			90,000				—
5.780% Long-wall financing arrangement			78,239				—
5.555% Long-wall financing arrangement			39,455				—
Sale-leaseback financing arrangement - NRP, LP			143,484				143,484
Other notes, payable monthly through 2011			102				338
Williamson Royalty Ventures financing loan			—				203,750	*
Crédit Agricole Corporate and Investment Bank term loan and revolving line of credit financing			—				237,500	*
The Huntington National Bank loan payable quarterly through 2014, interest at 2.75% plus three-month LIBOR			—				20,091	*
The Huntington National Bank loan payable quarterly, interest only through 2010, quarterly principal and interest payments payable quarterly 2011 through 2014 with an interest rate of 2.75% plus three-month LIBOR			—				20,000	*
Total		$	748,874			$	625,163

 

*	On August 12, 2010, these debt and financing arrangements were extinguished and repaid through the issuance of new debt facilities. See the footnote at Note 1.

 

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Notes to Consolidated Financial Statements (continued)

 

6. Debt and Financing Arrangements (continued)

 

Because of the inherent difficulty in distinguishing the elements of certain subsidiaries’ capital structures, the historical income statements of those subsidiaries have not included an interest charge on intercompany funding related to the operations of these subsidiaries. To fund the subsidiaries, Foresight Energy’s parent made capital contributions funded with debt. Repayments of such debt were then made through distributions from the subsidiaries to the parent. Management analyzed both the cash distributions and cash contributions to the various affiliated subsidiaries and allocated a portion of the debt to each of the entities. The analysis included cash transfers between the related entities for the period of January 1, 2010 through August 12, 2010, and for the years ended December 31, 2009 and 2008, to develop an average balance due to the parent. As such, debt from notes payable and accrued interest was reclassified to affiliate payable debt to reflect the appropriate discontinued operations and reorganization changes. The parent’s consolidated average borrowing rate of 8.00%, 10.37% and 10.71% for the period of January 1, 2010 through August 12, 2010 and for the years ended December 31, 2009, and 2008, respectively, was then applied to the average balances of $530.7 million, and $330.0 million, for the periods ended August 12, 2010, and December 31, 2009, respectively, to reflect a charge on intercompany debt. Total debt allocated to continuing operations was approximately $150.3 million and $345.0 million at August 12, 2010 and December 31, 2009, respectively, and total interest expense allocated to continuing operations was $14.8 million, $46.0 million, and $44.0 million for the period of January 1, 2010 through August 12, 2010 and for the years ended December 31, 2009, and 2008, respectively. Total debt allocated to discontinued operations was approximately $380.5 million and $136.0 million at August 12, 2010 and December 31, 2009, respectively, and total interest expense allocated to discontinued operations was $16.9 million, $19.0 million, and $7.0 million for the period of January 1, 2010 through August 12, 2010 and for the years ended December 31, 2009 and 2008, respectively.

9.625% Senior Unsecured Notes and Revolving Credit Agreement

On August 12, 2010, Foresight Energy completed a $400.0 million unsecured senior notes financing transaction. After certain fees and expenses were paid, the net proceeds of the financing agreement totaled approximately $387.5 million. The financing agreement calls for interest payments at 9.625% to be made semiannually each February 15 and August 15 beginning on February 15, 2011, with the entire principal balance due on August 15, 2017. The discount on the unsecured senior notes financing transaction was $2.5 million and is being amortized using the effective interest method. During 2010, $98 thousand of this discount was amortized. In addition, Foresight Energy entered into a revolving credit commitment of up to $285.0 million, of which a maximum of $125.0 million is available to secure letters-of-credit in lieu of drawing down cash. The revolving credit agreement bears interest at floating rates based on a Eurodollar rate or a bank base rate, at our election, plus applicable margins (6% at December 31, 2010) and is paid quarterly. The revolving credit commitment expires on August 12, 2014 and is collateralized by virtually all assets of the business other than those subject to sale and leaseback arrangements. Upon execution of the agreement, approximately $65.0 million was drawn against the revolver and no amounts were set aside for letters of credit. As part of the bond issuance and refinancing, Foresight Reserves committed to make a $100.0 million equity contribution, with $50.0 million due by December 31, 2010, and the remaining $50.0 million due by March 31, 2011. As of December 31, 2010, Foresight Reserves had contributed $70.0 million. Subsequent to year-end, Foresight Reserves contributed $30.0 million, bringing the total contributions to $100.0 million as of January 14, 2011. In addition, the financing arrangements entered into contain certain standard debt covenants with which management believes Foresight Energy is in compliance. The total proceeds of the senior notes and related transactions were $480.0 million.

The proceeds from the senior notes, revolving credit agreement and the equity contribution were used to repay certain existing debt and financing arrangements. The total amount paid including prepayment fees, to pay in full Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch) totaled approximately $178.8

 

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Notes to Consolidated Financial Statements (continued)

 

6. Debt and Financing Arrangements (continued)

 

million. In addition, the repayment in full of The Huntington National Bank financing agreements totaled approximately $62.9 million, the bond discount amounts of $2.5 million and the five open interest rate swaps were terminated, resulting in total early termination fees of approximately $4.1 million. A payment of approximately $209.0 million was also made to Williamson Royalty Ventures as part of the restructuring of those credit facilities to release Foresight Energy and its subsidiaries from any obligations under those credit facilities. Total other fees related to the transaction were approximately $17.5 million and have been capitalized as debt issuance costs. The remaining proceeds of approximately $5.2 million were retained by Foresight Energy for working capital needs.

On behalf of Foresight Energy, Foresight Reserves also assumed a $5.0 million warrant related to the Williamson Royalty Ventures (an unrelated third-party private equity company) financing arrangement which allowed for the purchase of 300 Class B Units of Upper Wilgat’s ownership at a price of $50 thousand per Class B Unit. In addition to the $5.0 million original issuance amount, Foresight Reserves assumed the remaining liability, comprised primarily of accrued interest and any prepayment fees, due from Foresight Energy to Williamson Royalty Ventures, then relieving Foresight Energy of any future liabilities to Williamson Royalty Ventures.

Subsequent to the refinancing transaction, an additional $25.0 million was drawn on the line of credit, and $8.5 million has been pledged as letters of credit.

Long-Wall Financing Arrangements

On January 5, 2010, Sugar Camp Energy, as the borrower and guarantor, and Foresight Reserves, as a guarantor, entered into a credit agreement with financial institutions Calyon Deutschland Neiderlassung Einer Franzoosischen Societe Anonyme and Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent. The credit agreement provides financing for the long-wall miner and related parts and accessories of up to $83.4 million toward the $98.1 million estimated cost of the long-wall miner. In addition, the financing agreement provides for financing of 100% of the loan fees estimated at $4.9 million and for 100% of $9.4 million of eligible interest on the loan during the construction of the long-wall miner. The financing arrangement is collateralized by the long-wall miner and its related equipment. The loan provides a total commitment of approximately $97.8 million. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually beginning September 30, 2010, unless considered as eligible interest as noted above. Principal repayments are due semiannually at the first semiannual date occurring after the commercial operation date (estimated to be December 31, 2011). Principal is to be repaid in equal semiannual payments over eight years starting on the first semi-annual date.

On May 14, 2010, Hillsboro Energy, as the borrower and guarantor, and Foresight Reserves, as a guarantor, entered into a credit agreement with financial institutions Calyon Deutschland Neiderlassung Einer Franzoosischen Societe Anonyme and Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent. The credit agreement provides financing for the long-wall miner and related parts and accessories of up to $77.3 million toward the $91.0 million estimated cost of the long-wall miner. In addition, the financing agreement provides for financing of 100% of the loan fees estimated at $4.5 million and for 100% of $7.5 million of eligible interest on the loan during the construction of the long-wall miner. The financing arrangement is collateralized by the long-wall miner and its related equipment. The loan provides a total commitment of approximately $89.3 million. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually beginning January 2011, unless considered as eligible interest as noted above. Principal repayments are due semiannually at the first semiannual date occurring after the commercial operation date (estimated to be June 30, 2012). Principal is to be repaid in equal semiannual payments over eight years starting on the first semiannual date.

 

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Notes to Consolidated Financial Statements (continued)

 

6. Debt and Financing Arrangements (continued)

 

The guaranty agreements between the lender and Foresight Reserves related to the long-wall financing agreements discussed above contain certain financial covenants that require, among other things, maintenance of minimum amounts and ratios of debt service coverage and leverage. Certain financial covenants have not been met, and the bank has waived such noncompliance as of December 31, 2010. The next compliance period evaluation date is March 31, 2011. The Company is evaluating several options to ensure compliance with those financial covenants, has the ability to do so, and will take necessary corrective action before March 31, 2011.

Sale-Leaseback Financing Arrangement - NRP, LP

On January 27, 2009, Macoupin Energy entered into a sales agreement with WPP and HOD (entities held by NRP, LP) to sell certain mineral reserves and rail facility assets. Simultaneous with the closing, Macoupin Energy entered into a lease transaction with WPP for mining of the mineral reserves and with HOD for the rail facility. Macoupin Energy received a total of $143.7 million in cash in exchange for the assets. At December 31, 2010 and December 31, 2009, the amount outstanding under the sale leaseback financing was $143.5 million and is classified as noncurrent on the balance sheet. Payments of the principal amount of the liability are expected to commence in 2030 based upon the mining plan. The effective interest rate on the financing was 16% at December 31, 2010 and 2009. Macoupin Energy recorded interest expense of $23.4 million and $19.2 million for the Years Ended December 31, 2010, and 2009, related to the sale-leaseback transaction.

Williamson Royalty Ventures Financing Arrangements

On March 13, 2006, Upper Wilgat entered into a financing arrangement with Williamson Royalty Ventures, an unrelated third-party private equity company. Under the arrangement with Williamson Royalty Ventures, Upper Wilgat borrowed $203.8 million. The financing arrangement requires no collateral and is not guaranteed. Interest on the note accrues at a rate of 12.44%, compounded annually, unless the note is paid prior to December 31, 2011, in which case the interest rate ranges from 9.10% to 11.51% for the duration of the note. No payments of principal or interest are due under the note unless distributions are made to the owners from the Companies’ net cash flows. The balance of accrued interest payable on the loan as of December 31, 2009 was $110.1 million. As of August 12, 2010, this loan had been extinguished and repaid through the issuance of new debt facilities.

The note was also issued with a warrant to purchase 300 Class B Units of Upper Wilgat’s ownership at a price of $50 thousand per Class B Unit. Upper Wilgat issued the warrant for $5.0 million and recorded the issuance as additional paid-in capital. The warrant may be exercised when the note is paid in full or the balance is reduced to zero, or when the note is forgiven, according to the terms of the warrant, but no later than March 13, 2022. As disclosed in Note 1, on August 12, 2010, Foresight Reserves purchased this warrant and canceled the obligation.

Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch) Financing Arrangement

On November 25, 2008 and as amended on December 31, 2009, Lower Wilgat and Middle Wilgat, as the borrower and guarantor, respectively, entered into two term loan commitments totaling $230 million. The loans require quarterly payments of 2% of the outstanding principal balance due beginning December 31, 2008. Interest was paid quarterly as accrued and bears interest at a rate per annum equal to the eurodollar rate determined for such day plus the applicable margin in effect for such day for eurodollar loans. The applicable margin ranges from 2.5% to 4.0%. To the extent not previously paid, all term loans are due and payable on the term loan maturity date of October 24, 2011. The loans are guaranteed by Middle Wilgat, Lower Wilgat, Gatling,

 

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Notes to Consolidated Financial Statements (continued)

 

6. Debt and Financing Arrangements (continued)

 

Williamson Energy, Gatling Ohio, and Meigs Point (Guarantors). The loan amounts are secured by all of the borrower’s and the Guarantors’ property, including contracts, agreements and documents, leases or sublease agreements in connection with the mines, and all applicable permits; all rents, profit, income, and revenues derived from the mines; all machinery, equipment, furnishings, vehicles, and other fixed assets; all intangibles; all cash; and all other property. As of August 12, 2010, this loan had been extinguished and repaid through the issuance of new debt facilities.

The Huntington National Bank Financing

On September 10, 2009, Hillsboro Energy, Macoupin Energy, and Sugar Camp Energy, as borrowers, entered into a term loan agreement with The Huntington National Bank as lender for an aggregate principal amount of $50 million. The term loan maturity date was September 10, 2014 and bears interest on the outstanding principal balance at a rate of the sum of (i) three-month LIBOR and (ii) 2.75%. As of August 12, 2010, this loan had been extinguished and repaid through the issuance of new debt facilities.

The Huntington National Bank Financing – Second Financing

On December 22, 2009, Hillsboro Energy, Macoupin Energy, and Sugar Camp Energy, as borrowers, entered into a second term loan agreement with The Huntington National Bank as lender for an aggregate principal amount of $20 million. The term loan maturity date was December 22, 2014 and bears interest on the outstanding principal balance at a rate of the sum of (i) three-month LIBOR and (ii) 2.75%. As of August 12, 2010, this loan had been extinguished and repaid through the issuance of new debt facilities.

The following summarizes the maturities of long-term debt, sale-leaseback financing arrangements, and accrued interest at December 31, 2010, for the continuing operations (in thousands):

 

		Long-Term Debt				Sale- Leaseback Arrangement				Accrued Interest
2011		$	—			$	—			$	14,973
2012			11,793				—				—
2013			14,392				—				—
2014			104,360				—				—
2015			14,325				—				—
Thereafter			460,520				143,484				12,678
		$	605,390			$	143,484			$	27,651

7. Lease Obligations

The Companies lease certain surface rights, mineral reserves, mining, transportation, and other equipment under various lease agreements with related entities under common ownership, NRP, LP, and other independent third parties. These leases are subject to certain terms and conditions and 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. Generally, the mineral reserve leases contain provisions that require the payment of minimum royalties regardless of the volume of coal produced or the level of mining activity. The leases generally require a production royalty at the greater amount of a base amount per ton or a percent of the gross selling price

 

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Notes to Consolidated Financial Statements (continued)

 

7. Lease Obligations (continued)

 

of the coal. Some of these agreements also require overriding royalty and/or wheelage payments dependent upon the specific agreement. Transportation leases generally require a per ton fee amount for coal transported at the facility and contain certain escalation clauses and/or renegotiation clauses for the amounts. For certain transportation assets, the Companies are responsible for operations, repairs, and maintenance and for keeping transportation facilities in good working order. Surface rights, mining, and other equipment leases require monthly payments based upon the specified agreements. Certain of these leases provide options for the purchase of the property at various times during the life of the lease, generally at its then fair market value. Under the terms of some mineral reserve mining leases, the Companies are to use commercially reasonable efforts to acquire additional mineral reserves in certain properties as defined in the agreements. Under the agreement, the Companies are responsible for the acquisition costs and the assets are to be titled to WPP.

The Companies also lease certain office space under various leases with monthly payments that expire during January of 2012.

The following presents future minimum rental payments, by year, required under leases with related entities with initial terms greater than one year, as of December 31, 2010 (in thousands):

 

		Minimum Coal Royalties
2011		$	38,167
2012			55,767
2013			55,767
2014			55,767
2015			55,767
Thereafter			758,699
Total minimum lease payments		$	1,019,934

The following presents future minimum rental payments, by year, required under leases with third parties with initial terms greater than one year, as of December 31, 2010 (in thousands):

 

		Minimum Coal Royalties				Other Lease Agreements
2011		$	2,004			$	598
2012			2,004				598
2013			2,004				349
2014			2,004				—
2015			2,004				—
Thereafter			19,205				—
Total minimum lease payments		$	29,225			$	1,545

Total royalty and rental expense under these agreements for the years ended December 31, 2010, 2009, and 2008 were approximately $5.8 million, $4.6 million, and $2.6 million, for continuing operations, respectively.

 

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Notes to Consolidated Financial Statements (continued)

 

8. Asset Retirement Obligations and Reclamation

The following is a reconciliation of the Companies’ liability for ARO as of December 31 (in thousands):

 

		2010				2009				2008
Asset retirement obligation liability at beginning of year		$	25,909			$	2,441			$	1,134
Additions resulting from property acquisitions or construction			—				23,144				1,414
Accretion expense			2,011				1,655				100
Expenditures for reclamation			(560	)			(306	)			—
Changes in estimate			(5,040	)			(1,025	)			(207	)
Asset retirement obligation liability at end of year		$	22,320			$	25,909			$	2,441

9. Employee Benefit Plans

The Companies offer 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 Companies. 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. Participants may elect to have their deferred compensation invested in one of several investment alternatives. The safe harbor matching feature calls for the employers to contribute 100% of each participant’s elective deferrals up to 3% of the participant’s compensation, and 50% of the deferral that exceeds 3% of compensation, not to exceed a total employer contribution of 4% of compensation.

Employer contributions for the continuing operations under the Plans for the years ended December 31, 2010, 2009, and 2008 were $1.1 million, $795 thousand, and $561 thousand, respectively.

The Companies also provide medical coverage (through a self-funded health plan) and life insurance coverage for current employees. Essentially all employees are eligible for these benefits as of their hire date, with cessation of benefits upon termination of employment with the Companies. As of December 31, 2010 and 2009, the continuing operations have accrued approximately $608 thousand and $567 thousand, respectively, for health claims incurred but not reported. The amount is based on historical claims activity and the amount of claims processed and paid subsequent to the respective year-end, that were for services rendered prior to that date. For the years ended December 31, 2010, 2009, and 2008, expenses for the continuing operations approximated $4.8 million, $3.8 million, and $2.2 million, respectively.

10. Risk Concentrations

Credit Risk and Major Customers

The Companies have a formal written credit policy that establishes procedures to determine creditworthiness and credit limits for trade customers and counterparties in the over-the-counter coal market. Generally, credit is extended 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.

The Companies market their coal principally to electric utilities in the United States. Sales to customers in foreign countries for continuing operations were $116.8 million, $97.2 million, and $105.4 million for the years

 

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Notes to Consolidated Financial Statements (continued)

 

10. Risk Concentrations (continued)

 

ended December 31, 2010, 2009, and 2008, respectively. As of December 31, 2010 and 2009, accounts receivable for continuing operations from electric utilities located in the United States totaled $10.1 million and $12.3 million, respectively, or 39% and 66% of total trade receivables, respectively.

The Companies are committed, under long-term contracts, to supply coal that meets certain quality requirements at specified prices. These prices are generally adjusted based on indices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer. The Companies and their continuing operations subsidiaries sold approximately 7.0 million, 5.9 million, and 5.5 million tons of coal in the years ended December 31, 2010, 2009, and 2008, respectively. For the years ended December 31, 2010, 2009, and 2008, approximately 83%, 33%, and 59% of this tonnage, respectively (representing approximately 86%, 28%, and 75% of the Companies’ revenue, respectively), was sold under long-term contracts (contracts having a term of greater than one year). Prices for coal sold under long-term contracts ranged from $30.00 to $95.00 per ton for the year ended December 31, 2010, $39.20 to $47.74 per ton for the year ended December 31, 2009, and $29.50 to $106.00 per ton for the year ended December 31, 2008. Long-term contracts ranged in remaining life from one to nine years. For the year ended December 31, 2010, sales (including spot sales) to the Companies’ two largest customers were $67.3 million and $61.7 million, respectively (representing approximately 19% and 17% of the Companies’ total revenue, respectively). For the year ended December 31, 2009, sales (including spot sales) to the Companies’ two largest customers were $61.6 million and $54.0 million, respectively (representing approximately 23% and 20% of the Companies’ total revenue, respectively). For the year ended December 31, 2008, sales (including spot sales) to the Companies’ largest customer was $43.1 million.

Coal Sale Agreements

As of December 31, 2010 Foresight Energy had several commitments under sales contracts with terms to deliver coal through 2018, or until termination or cancellation as allowed under the agreements. The agreements specify various terms and conditions, including the price per ton with annual sales commitments of 9.4 million tons for 2011 and 12.0 million tons for 2012. The price of coal is based on coal quality.

Transportation

The Companies depend on barge, rail, truck, and belt transportation systems to deliver coal to their customers. Disruption of these services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair the Companies’ ability to supply coal to their customers, resulting in decreased shipments. As such, the Companies have entered into long-term contracts with transportation providers to ensure available transportation is available to transport their coal.

11. Fair Values of Financial Instruments

Under accounting principles generally accepted in the United States of America, 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 1 assets include diesel fuel futures that are submitted for clearing on the New York Mercantile Exchange and other available-for-sale securities.

 

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Notes to Consolidated Financial Statements (continued)

 

11. Fair Values of Financial Instruments (continued)

 

•

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. The Companies’ Level 2 liabilities include interest rate swaps based on the LIBOR swap rate.

 

•

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 Companies’ Level 3 assets include auction-rate securities. Management’s assumptions used are included in Note 2 to the consolidated financial statements.

The table below sets forth, by level, the Companies’ financial assets that are accounted for at fair value at December 31, 2009 (in thousands):

 

		Total				Level 1				Level 2				Level 3
Assets:
Available-for-sale investments		$	42,274			$	18,464			$	—			$	23,810
Derivatives			219				219				—				—
Total assets		$	42,493			$	18,683			$	—			$	23,810
Liabilities:
Derivatives		$	586			$	—			$	586			$	—

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 (in thousands):

 

		December 31
		2010				2009
Balance at January 1		$	23,810			$	24,970
Total gains or losses (unrealized/realized):
Included in earnings			—				(60	)
Purchases, issuances, and settlements			(23,810	)			(1,100	)
Balance at December 31		$	—			$	23,810

12. Variable Interest Entities

The Companies consolidate VIEs of which they are the primary beneficiary. The liabilities recognized as a result of consolidating these VIEs do not necessarily represent additional claims on the general assets; rather, they represent claims against the specific assets of the consolidated VIEs. Conversely, assets recognized as a result of consolidating these VIEs do not represent additional assets that could be used to satisfy claims against the Companies’ general assets. There are no restrictions on the VIE assets that are reported in the Companies’ general assets.

 

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Notes to Consolidated Financial Statements (continued)

 

12. Variable Interest Entities (continued)

 

The total consolidated VIE assets and liabilities reflected in the Companies’ consolidated balance sheets for continuing operations are as follows (in thousands):

 

		December 31,
		2010				2009
Assets:
Cash		$	672			$	1,418
Receivables			170				560
Prepaid insurance			1,722				894
Other assets			755				65
Total assets		$	3,319			$	2,937
Liabilities:
Accounts payable		$	581			$	732
Accrued expenses			1,486				—
Other liabilities			2,217				1,248
Total liabilities		$	4,284			$	1,980

13. Commitments and Contingencies

The Companies are subject to various market, operational, financial, regulatory, and legislative risks summarized in “Regulatory Matters” in Note 2. 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 Companies believe that they have obtained all permits currently required to conduct present mining operations. From time to time in the normal course of business, the Companies 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.

These requirements could prove costly and time consuming and could delay commencing or continuing exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the Companies’ 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 Companies endeavor to conduct their 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 Companies have been material.

Periodically, there are various claims and legal proceedings against the Companies 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 Companies. In the opinion of management, based upon consultation with the Companies’ outside legal counsel, such proceedings are substantially covered by insurance, and the ultimate disposition of such proceedings is not expected to have a material adverse effect on the Companies’ consolidated financial position, results of operations, or cash flows.

 

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Notes to Consolidated Financial Statements (continued)

 

13. Commitments and Contingencies (continued)

 

Option Agreements

The Companies are parties to various option agreements to acquire property and mineral rights. These option agreements are capitalized at the time of transaction and are expensed if the option is not exercised. As of December 31, 2010 and 2009, the Companies have capitalized $800 thousand and $1.2 million of land options, respectively, included in property, plant, and equipment on the consolidated balance sheets, for approximately $4.4 million and $9.7 million, respectively, of total properties.

14. Discontinued Operations

As disclosed in Notes 1 and 6, the Foresight Energy Appalachian basin operations, along with several of the holding companies, have been accounted for as discontinued operations. On August 12, 2010, Foresight Energy distributed 100% of its investment in Gatling, Gatling Ohio, Meigs Point, Lower Wilgat, Middle Wilgat, and Upper Wilgat and all of their related subsidiaries and affiliates to Foresight Reserves, the parent of Foresight Energy.

The operating results of the discontinued operations are summarized below for the period of January 1, 2010 through August 12, 2010 and the years ended December 31, 2009 and 2008 (in thousands):

 

		2010				2009				2008
Coal sales revenues		$	41,452			$	31,902			$	37,765
Cost of coal sales			34,322				43,535				44,484
Net loss from discontinued operations			(40,893	)			(50,545	)			(41,249	)

Details of balance sheet items for discontinued operations as of December 31, 2009, are summarized below (in thousands):

 

Cash		$	33,332
Accounts receivable			9,159
Affiliates receivable			16,870
Coal inventory			1,368
Other current assets			2,325
Total current assets			63,054
Property, plant, equipment, and mine development, net of accumulated depletion and depreciation			203,615
Other assets			22,728
Total assets		$	289,397
Total current liabilities		$	103,412
Asset retirement obligation			947
Other liabilities			206,542
Total liabilities		$	310,901

 

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Notes to Consolidated Financial Statements (continued)

 

15. Summary Quarterly Financial Information (Unaudited)

A summary of the unaudited quarterly results of continuing operations for the Years Ended December 31, 2010 and 2009 is presented below (in thousands):

 

		2010
		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Coal sales revenues		$	56,868			$	79,424			$	109,795			$	116,505
Cost of coal sales			21,426				26,157				40,552				42,475
Net (loss) income from continuing operations			(2,924	)			19,976				17,485				15,118
Net loss from discontinued operations			(12,097	)			(13,995	)			(14,801	)			—
Net (loss) income			(15,021	)			5,981				2,684				15,118
		2009
		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Coal sales revenues		$	50,484			$	79,823			$	71,386			$	69,556
Cost of coal sales			22,549				30,037				25,095				23,841
Net (loss) income from continuing operations			(4,035	)			9,729				(334	)			8,729
Net loss from discontinued operations			(15,628	)			(20,677	)			(8,026	)			(6,214	)
Net (loss) income			(19,663	)			(10,948	)			(8,360	)			2,515

 

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Unaudited Condensed Consolidated Statements of Operations

 

		Three Months Ended September 30								Nine Months Ended September 30
		2011				2010				2011				2010
		(in thousands)								(in thousands)
Revenues
Coal sales revenue		$	171,285			$	109,795			$	358,931			$	246,087
Costs and expenses
Cost of coal sales			62,853				40,590				119,762				88,272
Transportation expenses			35,159				18,941				72,615				32,489
Depreciation, depletion and amortization			17,792				14,972				52,451				39,778
Accretion			426				484				1,279				1,477
Selling, general, and administrative			10,944				5,100				26,083				17,386
(Gain) loss on commodity contracts			(3,674	)			—				847				—
Other operating (income) expense, net			(72	)			(266	)			52				(964	)
Operating income			47,857				29,974				85,842				67,649
Other expense:
Interest expense, net			(12,222	)			(12,489	)			(35,192	)			(33,113	)
Net income from continuing operations			35,635				17,485				50,650				34,536
Net loss from discontinued operations			—				(14,800	)			—				(40,893	)
Net income (loss)			35,635				2,685				50,650				(6,357	)
Less: net income attributable to noncontrolling interest			12				846				50				867
Net income (loss) attributable to controlling interests		$	35,623			$	1,839			$	50,600			$	(7,224	)

See accompanying notes.

 

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Unaudited Condensed Consolidated Balance Sheets

 

		September 30, 2011				December 31, 2010 - (Note 1)
		(in thousands)
Assets
Current assets:
Cash		$	22,434			$	33,451
Investments in available-for-sale securities			—
Accounts receivable			36,256				24,424
Affiliate receivables			16				—
Inventories			62,205				29,014
Prepaid and other current assets			11,988				4,334
Total current assets			132,899				91,223
Property, plant, equipment, and mine development, net of accumulated depletion and depreciation			1,233,767				995,425
Prepaid royalties			23,354				10,075
Other assets			31,724				35,157
Total assets		$	1,421,744			$	1,131,880
Liabilities and members’ equity
Current liabilities:
Accounts payable – trade		$	41,984			$	40,656
Current portion of notes payable			9,900				—
Current portion of asset retirement obligation			358				534
Current portion of accrued interest payable			7,807				14,973
Accrued expenses and other current liabilities			11,388				2,256
Affiliate payable			8,820				8,057
Total current liabilities			80,257				66,476
Notes payable, long-term portion			797,005				605,390
Sale-leaseback financing arrangement, long-term portion			143,484				143,484
Accrued interest payable, long-term portion			14,610				12,678
Asset retirement obligations			22,673				21,786
Coal commodity contracts			1,026				—
Total liabilities			1,059,055				849,814
Members’ equity:
Controlling interests			363,631				283,031
Noncontrolling interests			(942	)			(965	)
Total members’ equity			362,689				282,066
Total liabilities and members’ equity		$	1,421,744			$	1,131,880

See accompanying notes.

 

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Unaudited Condensed Consolidated Statements of Members’ Equity

 

		Controlling Interests				Noncontrolling Interests				Holder of Stock Purchase Warrant				Total
		(in thousands)
Members’ equity at January 1, 2010		$	127,862			$	241			$	5,000			$	133,103
Cash contributed by members			372,327				—				—				372,327
Net loss attributable to controlling interests			(7,224	)			—				—				(7,224	)
Net income attributable to noncontrolling interests			—				867				—				867
Comprehensive loss															(6,357	)
Distribution of subsidiaries			(226,694	)			(1,053	)			(5,000	)			(232,747	)
Distributions to members ($23,300 non-cash)			(23,300	)			(31	)			—				(23,331	)
Members’ equity at September 30, 2010		$	242,971			$	24			$	—			$	242,995
Members’ equity at January 1, 2011		$	283,031			$	(965	)		$	—			$	282,066
Cash contributed by members			30,000				—				—				30,000
Net income attributable to controlling interests			50,600				—				—				50,600
Net income attributable to noncontrolling interests			—				50				—				50
Comprehensive income															50,650
Distributions to members			—				(27	)			—				(27	)
Members’ equity at September 30, 2011		$	363,631			$	(942	)		$	—			$	362,689

See accompanying notes.

 

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Foresight Energy LLC, Subsidiaries, and Affiliates

Unaudited Condensed Consolidated Statements of Cash Flows

 

		Nine Months Ended September 30,
		2011				2010
		(in thousands)
Cash Flows From Operating activities
Net income (loss)		$	50,650			$	(6,357	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation, depletion and amortization			52,451				54,267
Accretion on asset retirement obligation			1,279				1,477
Interest on related party debt			—				14,689
Gain on sale of marketable securities			—				(30	)
Write off of unamortized loan costs							2,977
Gain on interest rate swap			—				(586	)
Loss on commodity contracts			1,026				—
Changes in assets and liabilities:
Accounts receivable			(11,832	)			(2,669	)
Amount due from affiliates, net			747				(37,271	)
Inventory			(33,191	)			(24,914	)
Prepaid expenses			(7,654	)			(11	)
Prepaid royalties			(13,279	)			(34,862	)
Other assets			548				(35,327	)
Accounts payable – trade			1,328				(24,328	)
Accrued interest payable			(5,234	)			32,385
Accrued expenses			9,132				(1,861	)
Other liabilities			(568	)			(372	)
Net cash from operating activities			45,403				(62,793	)
Cash Flows From Investing activities
Investment in mining rights, equipment, and development			(242,490	)			(176,958	)
Purchases of investments in available-for-sale securities			—				(14,948	)
Proceeds from sale of available-for-sale securities			—				33,952
Deconsolidation of subsidiary			—				(13,710	)
Net cash from investing activities			(242,490	)			(171,664	)
Cash Flows From Financing activities
Member contributions			30,000				208,538
Proceeds from notes and equipment loans			156,199				500,956
Repayment of notes and equipment loans			(102	)			(509,120	)
Distributions to members			(27	)			(31	)
Net cash from financing activities			186,070				200,343
Net change in cash			(11,017	)			(34,114	)
Cash, beginning of period, continuing operations			33,451				14,757
Cash, beginning of period, discontinued operations			—				33,332
Cash, beginning of period, total			33,451				48,089
Cash, end of period		$	22,434			$	13,975
Supplemental Information:
Interest paid, net of amounts capitalized		$	40,426			$	23,852
Supplemental disclosures of non-cash financing activities:
Transfer out of marketable securities to member		$	—			$	23,300
Purchases of equipment under finance agreement		$	45,418			$	56,575
Member contributions		$	—			$	163,789

See accompanying notes.

 

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Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Unaudited Condensed Consolidated Financial Statements

1. Description of Business and Entity Structure

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 (and sometimes preexisting) entities under common control. Foresight Energy is primarily engaged in the development, mining, preparation, transportation and sale of coal mined in the Illinois basin. Foresight Energy is a wholly-owned subsidiary of Foresight Reserves, LP (Foresight Reserves).

Reorganization and Refinancing

On August 12, 2010, Foresight Energy completed a reorganization of its entity structure and a refinancing of its debt (see note 5). Prior to the reorganization, Foresight Energy had mining operations in both the Appalachian and Illinois basins. As part of the reorganization, the Appalachian operations were transferred outside of the Foresight Energy group and therefore are classified as discontinued operations in the nine month period ended September 30, 2010 in the accompanying consolidated financial statements. Also as part of the reorganization, certain assets and liabilities of Foresight Reserves were transferred into the Foresight Energy group and certain management costs of Foresight Reserves were allocated to the Foresight Energy group. Transfers of operations, assets and liabilities between Foresight Reserves and Foresight Energy have been accounted for as transfers among entities under common control and are accounted for at historical costs.

Reorganization - Continuing Operations

Effective with the reorganization, the following Foresight Energy subsidiaries were merged: Foresight Holding LLC (Foresight Holding) was merged into Foresight Energy and dissolved. Foresight Holding subsidiaries Hillsboro Energy LLC (Hillsboro Energy), Macoupin Energy LLC (Macoupin Energy), and Sugar Camp Energy, LLC (Sugar Camp Energy) were contributed to Foresight Energy and are now 100% owned subsidiaries of Foresight Energy. Williamson Energy, LLC (Williamson Energy), a subsidiary of Lower Wilgat, LLC (Lower Wilgat) was contributed to Foresight Energy and is now a 100% owned subsidiary of Foresight Energy. Foresight Coal Sales LLC (Foresight Coal Sales), a 100% owned subsidiary of Foresight Energy, remained unchanged.

In addition, effective with the reorganization, Foresight Reserves contributed a 100% ownership interest in Oeneus LLC d/b/a Savatran LLC (Savatran), Williamson Track, LLC (Williamson Track), Sitran LLC (Sitran), and Adena Resources, LLC (Adena Resources) to Foresight Energy. At the same time, Williamson Track was merged into Savatran, and Williamson Track was effectively dissolved. As all entities involved in the restructuring were under common control, the transferred amounts were recorded at their historical values. Accordingly, these financial statements present the merged entities as though they had always been combined.

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

1. Description of Business and Entity Structure (continued)

 

The following entities are perpetual term Delaware limited liability companies and are included in the continuing operations of Foresight Energy:

 

Entity		Activity
Williamson Energy		Developing, mining, and selling coal located in Williamson County, Illinois.
Hillsboro Energy		Developing, mining, and selling coal located in Montgomery County, Illinois.
Macoupin Energy		Developing, mining, and selling coal located in Macoupin County, Illinois.
Sugar Camp Energy		Developing, mining, and selling coal located in Franklin County, Illinois.
Foresight Coal Sales		Brokering coal sales for the various coal mining entities.
Savatran		Holding title to certain land, right-of-way agreements, and other contracts; constructing and operating certain transportation systems in the Illinois region.
Sitran		Holding title to a coal transload facility located in Indiana on the Ohio River.
Adena Resources		Holding certain interests in water agreements and contracts for the mining operations in the Illinois Basin.
Foresight Energy Corporation		Co-issuer of the Company’s senior unsecured notes. Through September 30, 2011 there has been no financial activity in this entity.
Foresight Supply Company LLC (Foresight Supply Company)		Contracting entity for centrally purchasing supplies for the Illinois coal operations.

The following entity is a private limited company incorporated under the laws of the United Kingdom and is included in continuing operations:

 

Foresight International Coal Sales Limited (Foresight International)		Entity established for potential future international sales. Through September 30, 2011 there has been no financial activity in this entity.

Foresight Energy, Williamson Energy, Hillsboro Energy, Macoupin Energy, Sugar Camp Energy, Foresight Coal Sales, Savatran, Sitran, Adena Resources, Foresight Energy Corporation, Foresight Supply Company, and Foresight International are all affiliated entities under common control and are collectively referred to as the “continuing operations.”

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

1. Description of Business and Entity Structure (continued)

 

Reorganization - Discontinued Operations

As a part of Foresight Energy’s reorganization certain entities of the consolidated group were deconsolidated. Foresight Energy contributed 100% of its investment in the following entities, subsidiaries and affiliates of Gatling LLC (Gatling), Gatling Ohio LLC (Gatling Ohio), Meigs Point Dock LLC (Meigs Point), Lower Wilgat, Middle Wilgat, LLC (Middle Wilgat) and Upper Wilgat, LLC (Upper Wilgat) to Foresight Reserves. The effects of the deconsolidation are reflected as the discontinued operations in the 2010 condensed consolidated financial statements.

As such, the following entities are included in discontinued operations of Foresight Energy:

 

Entity		Activity
Upper Wilgat		Holding company for coal mining operations.
Middle Wilgat		Holding company for coal mining operations.
Lower Wilgat		Holding company for coal mining operations.
Gatling		Developing, mining, and selling coal located in Mason County, West Virginia.
Gatling Ohio		Developing, mining, and selling coal located in Meigs County, Ohio.
Meigs Point		Holding title to certain coal transportation facilities in Meigs County, Ohio.

Upper Wilgat, Middle Wilgat, Lower Wilgat, Gatling, Gatling Ohio, and Meigs Point are all affiliated entities under common control and are collectively referred to as the “discontinued operations.”

Variable Interest Entities

These financial statements include certain other entities considered variable interest entities for which Foresight Energy is the primary beneficiary. The entities included in continuing operations are Mach Mining, LLC (Mach Mining), M-Class Mining, LLC (M-Class Mining), Coal Field Construction LLC (Coal Field Construction), MaRyan Mining LLC (MaRyan Mining), and Patton Mining LLC (Patton Mining). Certain other entities whose primary beneficiary was transferred outside the Foresight Energy group as part of the reorganization are included in discontinued operations. Entities included as discontinued operations are Big River Mining, LLC (Big River Mining), Clearwater Processing, LLC (Clearwater Processing), and Yellow Bush Mining, LLC (Yellow Bush Mining). Effective March 31, 2011, Clearwater Processing was merged into Yellow Bush Mining. These entities own no equipment, real property, or other intangible assets, and each holds a contract to provide contract mining, construction services, processing, and/or loading services to a Foresight Energy subsidiary or a discontinued operations entity.

Basis of Presentation

The accompanying unaudited condensed consolidated interim financial statements have been prepared in accordance with accounting principles for interim financial information generally accepted in the United States of America (USGAAP). The condensed consolidated financial statements do not include footnotes and certain financial information normally presented annually under USGAAP, and therefore, should be read in conjunction

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

1. Description of Business and Entity Structure (continued)

 

with the annual consolidated financial statements for the year ended December 31, 2010. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end. The results of operations for the three and nine months periods ended September 30, 2011 are not necessarily indicative of results that can be expected for the fiscal year ending December 31, 2011. The condensed consolidated balance sheet as of December 31, 2010 has been derived from the audited financial statements for the year ended December 31, 2010.

The condensed consolidated financial statements included herein are unaudited; however, the financial statements contain all significant adjustments (consisting of normal recurring accruals), which, in the opinion of management, are necessary to present fairly our consolidated financial position at September 30, 2011, our consolidated results of operations and our cash flows for the three and nine months ended September 30, 2011 and 2010, in conformity with USGAAP.

The variable interest entities and Foresight Energy and its subsidiaries and affiliates are collectively referred to as the Companies. None of the Companies or its affiliates’ labor force is represented by a collective bargaining unit. The Companies are subject to federal, state, and local environmental laws and regulations. Foresight Energy does not rely on any single significant customer or vendor.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The condensed consolidated financial statements include the accounts of Foresight Energy, its subsidiaries, and affiliate entities classified as either continuing operations or discontinued operations. All significant intercompany transactions are eliminated.

Revenue Recognition

Once mines are in production, coal sales revenue includes sales to customers of coal produced and the sale of coal purchased from third parties. The Companies recognize sales at the time legal title and risk of loss pass to the customer at contracted amounts, which is generally when the coal is delivered to an agreed-upon destination. Quality adjustments are recorded as necessary based on contract specifications as a reduction of mining revenue and accounts receivable.

As of September 30, 2011 and 2010, the Sugar Camp Energy and Hillsboro Energy mining operations were considered to be in the development stage because the entities were engaged in the preparation of an established, commercially minable reserve for its extraction. Substantially all of the efforts of Sugar Camp Energy and Hillsboro Energy, through September 30, 2011, were devoted to establishing the business and principal operations. Principal operations for Sugar Camp Energy and Hillsboro Energy are anticipated to begin at the end of the first quarter 2012 and the beginning of the third quarter of 2012, respectively. In accordance with USGAAP, the production phase is not deemed to commence with the removal of salable mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to an ore body. Accordingly, coal sales of $6.6 million and $4.2 million for the three months ended September 30, 2011 and 2010 and of $19.6 million and $4.2 million for the nine months ended September 30, 2011 and 2010, respectively, have been recorded as a reduction of mine development costs capitalized. For reporting on the statements of cash flows, cash expended in the investment in mining rights, equipment, and development is reported net of capitalized coal sales.

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

2. Summary of Significant Accounting Policies (continued)

 

Derivative Financial Instruments

The Companies generally utilize derivative instruments to manage exposures to commodity prices. The Companies record the fair value of each instrument as either an asset or liability on the consolidated balance sheets. The change in fair value is recorded as a loss or gain in the consolidated statements of operations. Derivative financial instruments are recognized in the consolidated balance sheets at fair value. Certain coal contracts may meet the definition of a derivative instrument, but because they 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, they are not recognized on the consolidated balance sheets.

3. Inventories

Supplies and coal inventories are valued at the lower of cost or market. Supplies inventory consists of spare parts for various equipment and other mining supplies valued using the first-in, first-out method. Raw coal represents coal stockpiles that will be further processed prior to shipment to a customer. Clean coal represents coal stockpiles that will be sold in current condition. Coal inventory costs include labor, supplies, equipment costs, and transportation costs prior to title transfer to customers as well as operating overhead. Inventories consisted of the following (in thousands):

 

		September 30, 2011				December 31, 2010
Supplies inventory		$	15,086			$	8,682
Raw coal			7,170				2,046
Clean coal			39,949				18,286
		$	62,205			$	29,014

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

4. Property, Plant, Equipment, and Mine Development

Property, plant, equipment, and mine development consist of the following (in thousands):

 

		September 30, 2011				December 31, 2010
Land and options		$	63,122			$	58,526
Mineral rights			42,744				42,744
Machinery and equipment			758,657				595,798
Buildings and structures			165,994				144,335
Mine development costs			452,885				326,534
Other			3,476				2,093
Less accumulated depreciation, depletion and amortization			(253,111	)			(174,605	)
		$	1,233,767			$	995,425

At September 30, 2011, the Companies have committed approximately $4.2 million for construction contracts and approximately $27.4 million for equipment contracts to bring certain mining operations into production.

In June 2009, Sugar Camp Energy and a third party entered into a purchase and sale agreement for certain long-wall equipment to be utilized by Sugar Camp Energy for a total purchase price of $98.1 million. As of September 30, 2011, the remaining commitment under the agreement totaled $6.6 million.

In May 2011, Sugar Camp Energy and a third party entered into a letter of intent for acquisition of certain long-wall equipment for a total purchase price of $70.5 million. Our parent, Foresight Reserves, has committed to fund this future commitment and acquire the equipment. As of September 30, 2011, the remaining commitment totaled $59.9 million. In the future, Foresight Energy expects to reimburse Foresight Reserves, at its cost, and take assignment of the definitive purchase agreement or title to the equipment itself, as appropriate.

In March 2010, Hillsboro Energy and a third party entered into a purchase and sale agreement to purchase certain long-wall equipment to be utilized by Hillsboro Energy for a total purchase price of $91.0 million. As of September 30, 2011, the remaining commitment under the agreement totaled $9.5 million.

5. Debt and Financing Arrangements

Outstanding amounts due under the Companies’ debt and financing arrangements at September 30, 2011 and at December 31, 2010 consist of the following (in thousands):

 

		September 30, 2011				December 31, 2010
9.625% Senior unsecured notes due 2017		$	397,795			$	397,594
Revolving credit agreement due 2014			246,000				90,000
5.780% Long-wall financing agreement			87,000				78,239
5.555% Long-wall financing agreement			76,110				39,455
Sale-leaseback financing arrangement - Natural Resource Partners, LP (NRP, LP)			143,484				143,484
Other notes, payable monthly through 2011			—				102
Total		$	950,389			$	748,874

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

5. Debt and Financing Arrangements (continued)

 

9.625% Senior Unsecured Notes and Revolving Credit Agreement

On August 12, 2010, Foresight Energy completed a $400.0 million unsecured senior notes financing transaction. After certain fees and expenses were paid, the net proceeds of the financing agreement totaled approximately $387.5 million. The financing agreement calls for interest payments at 9.625% to be made semiannually each February 15 and August 15 beginning on February 15, 2011, with the entire principal balance due on August 15, 2017. The discount on the unsecured senior notes financing transaction was $2.5 million and is being amortized using the effective interest method. For the three and nine months ended September 30, 2011, $69 thousand and $202 thousand, respectively, of this discount was amortized and recorded as interest expense. In addition, Foresight Energy entered into a revolving credit commitment of up to $285.0 million, of which a maximum of $125.0 million is available to secure letters-of-credit in lieu of drawing down cash. The revolving credit agreement bears interest at floating rates based on a Eurodollar rate or a bank base rate, at our election, plus applicable margins (4.0% at September 30, 2011) and is paid quarterly. The revolving credit commitment expires on August 12, 2014 and is collateralized by virtually all assets of the business other than those subject to sale and leaseback arrangements. Upon execution of the agreement, approximately $65.0 million was drawn against the revolver and no amounts were set aside for letters of credit. As part of the bond issuance and refinancing, Foresight Reserves committed to make a $100.0 million equity contribution to Foresight Energy. Foresight Reserves satisfied this commitment as of March 31, 2011. In addition, the financing arrangements entered into contain certain standard debt covenants with which management believes Foresight Energy is in compliance. The total proceeds of the senior notes and related transactions were $480.0 million.

The proceeds from the senior notes, revolving credit agreement, and the equity contribution were used to repay certain existing debt and financing arrangements. The total amount paid, including prepayment fees, to pay in full Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch) totaled approximately $178.8 million. In addition, the note was used to repay in full The Huntington National Bank financing agreements totaling approximately $62.9 million, the bond discount amounts of $2.5 million and the five open interest rate swaps were terminated, resulting in total early termination fees of approximately $4.1 million. A payment of approximately $209.0 million was also made to Williamson Royalty Ventures as part of the restructuring of those credit facilities to release Foresight Energy and its subsidiaries from any obligations under those credit facilities. Total other fees related to the transaction were approximately $17.5 million and have been capitalized as debt issuance costs. The remaining proceeds of approximately $5.2 million were retained by Foresight Energy for working capital needs.

On behalf of Foresight Energy, Foresight Reserves also extinguished a $5.0 million warrant related to the Williamson Royalty Ventures (an unrelated third-party) financing arrangement which allowed for the purchase of 300 Class B Units of Upper Wilgat’s ownership at a price of $50 thousand per Class B Unit. In addition to the $5.0 million original issuance amount, Foresight Reserves assumed the remaining liability, comprised primarily of accrued interest and any prepayment fees, due from Foresight Energy to Williamson Royalty Ventures, thus relieving Foresight Energy of any future liabilities to Williamson Royalty Ventures.

Subsequent to the refinancing transaction, an additional $181.0 million has been drawn on the revolving credit commitment, and $2.0 million has been pledged as letters of credit.

Long-Wall Financing Arrangements

On January 5, 2010, Sugar Camp Energy, as the borrower and guarantor, and Foresight Reserves, as a guarantor, entered into a credit agreement with financial institutions Calyon Deutschland Neiderlassung Einer

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

5. Debt and Financing Arrangements (continued)

 

Franzoosischen Societe Anonyme and Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent. The credit agreement provides financing for the long-wall mining system and related parts and accessories of up to $83.4 million toward the $98.1 million estimated cost of the long-wall mining system. In addition, the financing agreement provides for financing of 100% of the loan fees estimated at $4.9 million and for 100% of $9.4 million of eligible interest on the loan during the construction of the long-wall mining system. The financing arrangement is collateralized by the long-wall mining system and its related equipment. The loan provides a total commitment of approximately $97.8 million. Interest accrues on the note at a fixed rate per annum of 5.78% and is due semiannually beginning September 30, 2010 unless considered as eligible interest as noted above. Principal repayments are due semiannually commencing on December 31, 2011. Principal is to be repaid in equal semiannual payments over eight years starting on the first semi-annual date. Effective May 27, 2011, Foresight Reserves was released as guarantor and replaced by Foresight Energy.

On May 14, 2010, Hillsboro Energy, as the borrower and guarantor, and Foresight Reserves, as a guarantor, entered into a credit agreement with financial institutions Calyon Deutschland Neiderlassung Einer Franzoosischen Societe Anonyme and Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent. The credit agreement provides financing for the long-wall mining system and related parts and accessories of up to $77.3 million toward the $91.0 million estimated cost of the long-wall mining system. In addition, the financing agreement provides for financing of 100% of the loan fees estimated at $4.5 million and for 100% of $7.5 million of eligible interest on the loan during the construction of the long-wall mining system. The financing arrangement is collateralized by the long-wall mining system and its related equipment. The loan provides a total commitment of approximately $89.3 million. Interest accrues on the note at a fixed rate per annum of 5.555% and is due semiannually beginning January 2011 unless considered as eligible interest as noted above. Principal repayments are due semiannually commencing on June 30, 2012. Principal is to be repaid in equal semiannual payments over eight years starting on the first semiannual date. Effective May 27, 2011, Foresight Reserves was released as guarantor and replaced by Foresight Energy.

The guaranty agreements between the lender and Foresight Energy related to the long-wall financing agreements discussed above contain certain financial covenants that require, among other things, maintenance of minimum amounts and compliance with debt service coverage and leverage ratios. The Company has met the required financial covenants as of September 30, 2011.

Sale-Leaseback Financing Arrangement - NRP, LP

On January 27, 2009, Macoupin Energy entered into a sales agreement with WPP, LLC (WPP) and HOD, LLC (HOD) (entities held by NRP, LP) to sell certain mineral reserves and rail facility assets. Simultaneous with the closing, Macoupin Energy entered into a lease transaction with WPP for mining of the mineral reserves and with HOD for the rail facility. Macoupin Energy received a total of $143.7 million in cash in exchange for certain mineral reserve assets. At September 30, 2011 and December 31, 2010, the amount outstanding under the sale-leaseback financing was $143.5 million and is classified as noncurrent on the balance sheet. Payments of the principal amount of the liability are expected to commence in 2030 based upon the mining plan. The effective interest rate on the financing was 17% and 16% at September 30, 2011 and December 31, 2010, respectively. Macoupin Energy recorded interest expense of $18.8 million and $16.8 million for the nine months ended September 30, 2011 and 2010 related to the sale-leaseback transaction.

 

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Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

5. Debt and Financing Arrangements (continued)

 

The following summarizes the maturities of long-term debt, sale-leaseback financing arrangement, and accrued interest at September 30, 2011 for the following periods (in thousands):

 

		Long-term Debt				Sale - Leaseback Arrangement				Accrued Interest
10/1/11 - 9/30/12		$	9,900			$	—			$	7,807
10/1/12 - 9/30/13			20,066				—				—
10/1/13 - 9/30/14			266,033				—				—
10/1/14 - 9/30/15			19,998				—				—
10/1/15 - 9/30/16			19,959				—				—
Thereafter			470,949				143,484				14,610
		$	806,905			$	143,484			$	22,417

6. Coal Commodity Contracts

The Companies entered into four coal purchase and sale commodity contracts. The first contract is effective January 1, 2012 through December 31, 2012, and calls for the Companies to receive a fixed price per ton for a 20,000 ton monthly volume commitment. The second contract is effective January 1, 2013 through December 31, 2013, and calls for the Companies to receive a fixed price per ton for a 20,000 ton monthly volume commitment. The third contract was effective September 1, 2011 through September 30, 2011, at a fixed price per ton for a 60,000 ton volume commitment. The fourth contract is effective November 1, 2011 through November 30, 2011, at a fixed price per ton for a 60,000 ton volume commitment. The Companies will pay a floating price which is based on the reported pricing effective on the pricing date as published in the Argus/McCloskey’s Coal Price Index Report under the category as specified in the agreement. The Companies have elected to account for the coal commodity contracts as free standing derivatives. As such, all gains and losses related to the change in fair value of coal commodity contracts are being recognized in periodic earnings. At September 30, 2011, the fair value of the coal commodity contracts resulted in a liability of $1.0 million, and net gains (losses) attributed thereto were $3.7 million and ($847 thousand) for the three and nine months ended September 30, 2011, respectively.

7. Related-Party Transactions and Lease Obligations

The Companies and other affiliated entities routinely engage in transactions in the normal course of business with other affiliated entities under common control, including obtaining contract mining labor, administrative services, and other services and supplies incidental to the production of coal and development of the mine locations. The Companies had affiliate accounts receivable and payable as follows (in thousands):

 

				Receivable / (payable)
Affiliated Company		Description of Service		September  30, 2011				December 31, 2010
Foresight Management		Affiliate advance		$	4			$	—
Raven Energy		Affiliate advance			12				—
				$	16			$	—
NRP, LP		Royalties and transportation fees		$	(8,022	)		$	(5,288	)
Gatling		Affiliate advance			(5	)			—
Gatling Ohio		Affiliate advance			(4	)			—
Foresight Management, LLC		Labor and employee benefits			(789	)			(2,769	)
				$	(8,820	)		$	(8,057	)

 

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Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

7. Related-Party Transactions and Lease Obligations (continued)

 

A summary of transactions with affiliated entities is as follows (in thousands):

 

		Three Months Ended								Nine months Ended
		September 30, 2011				September 30, 2010				September 30, 2011				September 30, 2010
Royalty payments paid to NRP, LP		$	14,420			$	20,948			$	42,878			$	38,675
Fees for transportation services paid to NRP, LP			4,119				3,392				11,786				9,036
Management costs allocated to Foresight Energy by Foresight Management LLC			3,448				1,809				8,556				5,846

The following presents future minimum rental payments, by year, required under leases with related entities with initial terms greater than one year, as of September 30, 2011 (in thousands):

 

Twelve months ending September 30,		Minimum Coal Royalties
2012		$	39,017
2013			52,667
2014			55,667
2015			55,667
2016			55,667
Thereafter			538,252
Total minimum lease payments		$	796,937

During the third quarter of 2011, our parent, Foresight Reserves acquired the IC Railmarine Terminal located in Convent, Louisiana. This terminal facility will give our Companies additional opportunity to ship coal internationally.

8. Asset Retirement Obligations (ARO) and Reclamation

The following is a reconciliation of the Companies’ liability for ARO and reclamation (in thousands):

 

		September  30, 2011				December  31, 2010
Asset retirement obligation liability at beginning of period		$	22,320			$	25,909
Accretion expense			1,279				2,011
Expenditures for reclamation			(568	)			(560	)
Changes in estimate			—				(5,040	)
Asset retirement obligation liability at end of period		$	23,031			$	22,320

 

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Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

9. Variable Interest Entities (VIEs)

As described in note 1, the Companies consolidate VIEs of which they are the primary beneficiary. The liabilities recognized as a result of consolidating these VIEs do not necessarily represent additional claims on the Companies’ general assets; rather, they represent claims against the specific assets of the consolidated VIEs. Conversely, assets recognized as a result of consolidating these VIEs do not represent additional assets that could be used to satisfy claims against the Companies’ general assets.

The total consolidated VIE assets and liabilities reflected in the Companies’ condensed consolidated balance sheets for continuing operations are as follows (in thousands):

 

		September 30, 2011				December 31, 2010
Assets:
Cash		$	2,310			$	672
Other assets			8,842				2,647
Total assets		$	11,152			$	3,319
Liabilities:
Current liabilities		$	12,094			$	4,284

10. Discontinued Operations

As more fully described in note 1, the Foresight Energy Appalachian basin operations, along with several of the holding companies, have been accounted for as discontinued operations. On August 12, 2010, Foresight Energy distributed 100% of its investment in Gatling, Gatling Ohio, Meigs Point, Lower Wilgat, Middle Wilgat, Upper Wilgat, and all of their related subsidiaries and affiliates to Foresight Reserves, the parent of Foresight Energy.

The operating results of the discontinued operations are summarized below for the period in which they are presented in the quarterly condensed consolidated financial statements (in thousands):

 

		Three Months Ended September 30, 2010				Nine months Ended September 30, 2010
Coal sales revenues		$	4,992			$	41,452
Cost of coal sales			5,511				34,322
Net loss from discontinued operations			(14,800	)			(40,893	)

11. Transportation Commitment

Savatran entered into a transportation agreement with Canadian National Railway Company (Canadian National) for the transportation of coal from the origin point to a terminal point which remains in effect until December 31, 2021. Savatran agreed to pay Canadian National a rate per car based on the point of origin as specified in the agreement, and has agreed to transport a minimum of 3 million tons in 2012, 4 million in 2013, and 8 million tons per year from 2014 through 2021. The contract contains a liquidated damages clause for each ton that Savatran is under the minimum.

 

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Foresight Energy LLC, Subsidiaries, and Affiliates

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

12. Subsequent Events

On November 2, 2011, one of our lenders increased their credit commitment under this facility by $20.0 million, resulting in an increase in the total facility size to $305.0 million from $285.0 million. On December 15, 2011, we completed an amendment that increased the total facility size to $400 million. In addition, the amendment eliminated certain covenants related to capital expenditure limitations and modified the net leverage ratio test.

 

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APPENDIX A: FORM OF PARTNERSHIP AGREEMENT

 

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APPENDIX B: CERTAIN DEFINED TERMS—BUSINESS

2010 Reorganization. Simultaneously with the offering of our Senior Notes in August 2010, we underwent a reorganization pursuant to which:

 

•

Foresight Reserves contributed 100% ownership interest of Williamson Track, LLC, Savatran LLC and Sitran LLC (which are transportation subsidiaries) and Adena Resources, LLC (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 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) 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 Venture by Upper Wilgat and Foresight Energy LLC was relieved of any further obligation with respect thereto.

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

Adena Entities. Christopher Cline, Foresight Reserves, L.P., Adena Minerals LLC, and their respective affiliates.

Adena Resources. Adena Resources, LLC, a subsidiary of Foresight Energy 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.

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).

 

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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. A comprehensive set of amendments to the federal law governing the nation’s air quality. 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, other than Foresight Energy Partners LP and its subsidiaries.

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.

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.

 

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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.

GAAP. Generally accepted accounting principles in the U.S.

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.

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 system advances through the coal.

 

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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.

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.

 

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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.

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 two 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 and/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.

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.

 

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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 Notes. Foresight Energy LLC and Foresight Energy Finance Corporation’s $400 million 9.625% senior unsecured notes due 2017.

Senior Secured Credit Facility. Foresight Energy LLC’s amended and restated senior secured credit facility dated as of December 15, 2011, as may be further amended and restated or otherwise modified from time to time.

Severance tax. A tax imposed on the removal of a natural resource, such as crude oil or coal.

Sitran. Sitran LLC, a subsidiary of Foresight Energy 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.

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.

 

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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.

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 in working capital borrowings with respect to that period; and

 

•

the amount of any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; and

 

•

increase operating surplus by:

 

•

the amount of any net decrease in working capital borrowings with respect to that period; and

 

•

the amount of any net increase in cash reserves for operating expenditures with respect to that period 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 with respect to such period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods.

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 available 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 on in excess of operating surplus will be deemed to be capital surplus.

Common units. The common units representing limited partner interests in Foresight Energy Partners LP offered pursuant to this offering. See “Description of Common Units.”

General partner. Foresight Energy GP LLC, our general partner and a wholly-owned subsidiary of Foresight Reserves, L.P.

Interim capital transactions: means the following transactions:

 

•

borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business);

 

•

sales of equity and debt securities; and

 

•

sales or other dispositions of any assets of other than sales or other disposition of inventory, accounts receivables and other assets in the ordinary course of business, and sales or other dispositions of assets as part of normal retirements or replacements.

Maintenance and Replacement Capital Expenditures: Capital expenditures required to maintain our long-term operating capacity (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).

 

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Maintenance and replacement 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 and replacement 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 and replacement 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.

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, which include the following:

 

•

borrowings that are not working capital borrowings,

 

•

sales of equity and debt securities,

 

•

sales or other dispositions of assets outside the ordinary course of business,

 

•

capital contributions received, and

 

•

corporate reorganizations or restructurings;

provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

 

•

working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; 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

 

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improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period 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 loss realized on disposition of an investment capital expenditure.

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 Partners LP and its subsidiaries, giving effect to the IPO Reorganization.

PIK Period. The period beginning on the date of the closing of this offering until the date that is the earliest of: (i) August 15, 2017 (the maturity date of the Senior Notes); or (ii) the date by which we (a) redeem, repurchase, defease or retire the Senior Notes, or otherwise amend the indenture governing the Senior Notes and (b) amend or terminate our Senior Secured Credit Facility, in each case, in a manner that permits us to distribute cash to all unitholders.

Units. Refers to common units, PIK common units and subordinated 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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Common Units

Representing Limited Partner Interests

FORESIGHT ENERGY PARTNERS LP

 

 

 

PRELIMINARY PROSPECTUS

                    , 2012

 

 

 

Dealer Prospectus Delivery Obligation

Until        , 2012 (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		$	11,460
FINRA filing fee		$	10,500
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 Partners LP and our general partner, their officers and directors, and any person who controls Foresight Energy Partners 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 Partners 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, L.P. 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 Formation of Foresight Energy Partners LP
3.2*		Form of Partnership Agreement of Foresight Energy Partners LP (included as Appendix A to the Prospectus)
4.1*		Form of Registration Rights Agreement
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
10.2*		Form of Employment Agreement
10.3*		The Amended and Restated Credit Agreement, dated as of December 15, 2011, by and among Foresight Energy LLC, Citibank, N.A., as administrative agent, each L/C Issuer party thereto, the Lenders party thereto and Citigroup Global Markets Inc., PNC Capital Markets LLC and Crédit Agricole Corporate and Investment Bank, as Joint Lead Arrangers and Joint Book Managers.
10.4*		The Indenture, dated as of August 12, 2010, by and among Foresight Energy LLC, Foresight Energy Corporation, the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.
10.5*		First Supplemental Indenture, dated as of October 20, 2011, by and among Foresight Supply Company LLC and Foresight International Coal Sales Limited (each a “Guaranteeing Subsidiary” and collectively, the “Guaranteeing Subsidiaries”), each a subsidiary of Foresight Energy LLC, Foresight Energy Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee.
10.6*		The $97.8 million equipment financing 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, as Hermes Agent (formerly known as CALYON Deutschland Niederlassung einer französischen Societé Anonyme,) (the “Sugar Camp Credit Agreement”).
10.7*		The 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, as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.8*		The Second Amendment to the Sugar Camp Credit Agreement, dated as of August 4, 2010, by and among Sugar Camp Energy LLC, 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.
10.9*		The 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, as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.10*		The 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, as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.11*		The $89.3 million equipment financing agreement, dated as of May 14, 2010, by and among Hillsboro Energy LLC, as the borrower, Foresight Energy LLC, as a guarantor, Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (the “Hillsboro Credit Agreement”), as Hermes Agent.

 

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Exhibit Number		Description of Documents
10.12*		The 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 Calyon New York Branch), as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.13*		The Second Amendment to the Hillsboro Credit Agreement dated as of August 4, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme as Hermes Agent.
10.14*		The 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 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*		The 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 Calyon New York Branch), as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme as Hermes Agent.
21.1*		List of subsidiaries of Foresight Energy Partners LP
23.1		Consent of Independent Registered Public Accounting Firm for Foresight Energy Partners 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)

 

*	To be filed by amendment.

 

(b)	Financial Statement Schedules.

None.

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.

 

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(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 hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

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.

 

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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 Houston, State of Texas, on February 1, 2012.

 

POWER OF ATTORNEY

KNOW ALL PEOPLE BY THESE PRESENTED, that each person whose signature appears below hereby appoints Michael J. Beyer acting alone, his/her true and lawful attorney-in-fact with full power of substitution or re-substitution, for such person and in such person’s name, place and stead, in any and all capacities, to sign on such person’s behalf, individually and in each capacity stated below, any and all amendments, including post-effective amendments to this Registration Statement, and to sign any and all additional registration statements relating to the same offering of securities of the Registration Statement that are filed pursuant to Rule 462(b) of the Securities Act of 1933, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact, full power and authority to do and perform each and every act and thing requisite or necessary to be done in and about the premises, as fully to all intents and purposes as such person might or could do in person, hereby ratifying and confirming all that said attorney-in-fact, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities, which are with the general partner of the registrant, and on the dates indicated:

 

Name and Signatures		Title		Date
/s/ Michael J. Beyer Michael J. Beyer		Director and Chief Executive Officer and President (Principal Executive Officer)		February 1, 2012
/s/ Oscar A. Martinez Oscar A. Martinez		Senior Vice President—Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)		February 1, 2012
/s/ Christopher Cline Christopher Cline		(Director)		February 1, 2012

 

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INDEX TO EXHIBITS

 

Exhibit Number		Description of Documents
1.1*		Form of Underwriting Agreement
3.1		Certificate of Formation of Foresight Energy Partners LP
3.2*		Form of Partnership Agreement of Foresight Energy Partners LP (included as Appendix A to the Prospectus)
4.1*		Form of Registration Rights Agreement
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
10.2*		Form of Employment Agreement
10.3*		The Amended and Restated Credit Agreement, dated as of December 15, 2011, by and among Foresight Energy LLC, Citibank, N.A., as administrative agent, each L/C Issuer party thereto, the Lenders party thereto and Citigroup Global Markets Inc., PNC Capital Markets LLC and Crédit Agricole Corporate and Investment Bank, as Joint Lead Arrangers and Joint Book Managers.
10.4*		The Indenture, dated as of August 12, 2010, by and among Foresight Energy LLC, Foresight Energy Corporation, the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.
10.5*		First Supplemental Indenture, dated as of October 20, 2011, by and among Foresight Supply Company LLC and Foresight International Coal Sales Limited (each a “Guaranteeing Subsidiary” and collectively, the “Guaranteeing Subsidiaries”), each a subsidiary of Foresight Energy LLC, Foresight Energy Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee.
10.6*		The $97.8 million equipment financing 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, as Hermes Agent (formerly known as CALYON Deutschland Niederlassung einer französischen Societé Anonyme,) (the “Sugar Camp Credit Agreement”).
10.7*		The 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, as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.8*		The Second Amendment to the Sugar Camp Credit Agreement, dated as of August 4, 2010, by and among Sugar Camp Energy LLC, 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.
10.9*		The 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, as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.10*		The 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, as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.11*		The $89.3 million equipment financing 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 Calyon New York Branch), as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme (the “Hillsboro Credit Agreement”).
10.12*		The 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 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
10.13*		The Second Amendment to the Hillsboro Credit Agreement dated as of August 4, 2010, by and among Hillsboro Energy LLC, Foresight Energy LLC, Crédit Agricole Corporate and Investment Bank (formerly Calyon New York Branch), as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
10.14*		The 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 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*		The 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 Calyon New York Branch), as administrative agent, and Crédit Agricole Corporate and Investment Bank Deutschland, Niederlassung Einer Französischen Société Anonyme, as Hermes Agent.
21.1*		List of subsidiaries of Foresight Energy Partners LP
23.1		Consent of Independent Registered Public Accounting Firm for Foresight Energy Partners 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)

 

*	To be filed by amendment.