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EX-21.1 - EX-21.1 - Oxford Resource Partners LPh69756exv21w1.htm
EX-23.2 - EX-23.2 - Oxford Resource Partners LPh69756exv23w2.htm
Table of Contents

As filed with the Securities and Exchange Commission on March 24, 2010
Registration No. 333-      
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Oxford Resource Partners, LP
(Exact Name of Registrant as Specified in Its Charter)
 
         
Delaware   1221   77-10695453
(State or Other Jurisdiction of Incorporation or
Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer Identification Number)
544 Chestnut Street
P.O. Box 427
Coshocton, OH 43812
Phone:                    
(Address, Including Zip Code, and Telephone Number,
Including Area Code, of Registrant’s Principal Executive Offices)
 
Jeffrey M. Gutman
Senior Vice President,
Chief Financial Officer and Treasurer
544 Chestnut Street
P.O. Box 427
Coshocton, OH 43812
Phone:                    
(Name, Address, Including Zip Code, and Telephone Number,
Including Area Code, of Agent for Service)
Copies to:
     
William N. Finnegan IV
Brett E. Braden
Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400
  G. Michael O’Leary
William J. Cooper
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
(713) 220-4200
 
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, check the following box.  o
 
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.  o
 
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.  o
 
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.  o
 
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 o Accelerated filer o Non-accelerated filer þ Smaller reporting company o
(Do not check if a smaller reporting company)
 
CALCULATION OF REGISTRATION FEE
 
                     
      Proposed Maximum
    Amount of
      Aggregate Offering
    Registration
Title of Securities to be Registered     Price(1)(2)     Fee
Common units representing limited partner interests
    $ 250,000,000       $ 17,825  
                     
 
(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
 
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 preliminary prospectus is not complete and may be changed. We may not sell these securities 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 state where the offer or sale is not permitted.
 
 
Subject to Completion, dated March 24, 2010
PROSPECTUS
 
 
Oxford LOGO
 
Oxford Resource Partners, LP
 
Common Units
Representing Limited Partner Interests
 
 
This is the initial public offering of our common units. We are offering          common units in this offering. No public market currently exists for our common units.
 
We intend to apply to list our common units on the New York Stock Exchange under the symbol “OXF.”
 
We anticipate the initial public offering price to be between $      and $      per common unit.
 
Investing in our common units involves risks. See “Risk Factors” beginning on page 19 of this prospectus.
 
These risks include the following:
 
•     We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner.
 
•     Our general partner and its affiliates have conflicts of interest, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders.
 
•     Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.
 
•     New and future regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.
 
•     Existing and future regulatory requirements relating to sulfur dioxide and other air emissions could affect our customers and could reduce the demand for the high-sulfur coal we produce and cause coal prices and sales of our high-sulfur coal to decline materially.
 
•     Competition within the coal industry may materially and adversely affect our ability to sell coal at an acceptable price.
 
•     We depend on a limited number of customers for a significant portion of our revenues, and the loss of, or significant reduction in, purchases by any of them could adversely affect our results of operations and cash available for distribution to our unitholders.
 
•     Our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability and growth.
 
•     Our unitholders 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.
 
•     Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
                 
    Per Common Unit   Total
 
Public Offering Price
  $           $        
Underwriting Discount
  $       $    
Proceeds to us (before expenses)
  $       $  
 
We have granted the underwriters a 30-day option to purchase up to an additional          common units on the same terms and conditions set forth above if the underwriters sell more than        common units in this offering.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.
 
Barclays Capital, on behalf of the underwriters, expects to deliver the common units on or about          , 2010.
 
 
 
Barclays Capital Citi
 
Prospectus dated          , 2010


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[ARTWORK TO COME]


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 EX-3.1
 EX-21.1
 EX-23.1
 EX-23.2
 EX-23.3
 
You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor the sale of common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or the solicitation of an offer to buy the common units in any circumstances under which the offer or solicitation is unlawful.
 
 
 
Until          , 2010 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


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SUMMARY
 
This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements, before purchasing our common units. The information presented in this prospectus assumes that the underwriters’ option to purchase additional common units is not exercised unless otherwise noted. You should read “Risk Factors” beginning on page 19 for information about important risks that you should consider before purchasing our common units.
 
Market and industry data and certain other statistical data used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. In this prospectus, we refer to information regarding the coal industry in the United States and internationally that was obtained from the U.S. Department of Energy’s Energy Information Administration, or the EIA, John T. Boyd Company and the U.S. Mine Safety and Health Administration, or MSHA. These organizations are not affiliated with us.
 
References in this prospectus to “Oxford Resource Partners, LP,” “we,” “our,” “us” or like terms refer to Oxford Resource Partners, LP and its subsidiaries, including our wholly owned subsidiary, Oxford Mining Company, LLC, which is also our accounting predecessor. References to “Oxford Resources GP” or “our general partner” refer to Oxford Resources GP, LLC. We include a glossary of some of the terms used in this prospectus as Appendix B.
 
Oxford Resource Partners, LP
 
We are a low cost producer of high value steam coal, and we are the largest producer of surface mined coal in Ohio. We focus on acquiring steam coal reserves that we can efficiently mine with our modern, large scale equipment. Our reserves and operations are strategically located in Northern Appalachia and the Illinois Basin to serve our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. We market our coal primarily to large utilities with coal-fired, base-load scrubbed power plants under long-term coal sales contracts. We believe that we will experience increased demand for our high-sulfur coal from power plants that have or will install scrubbers. Currently, there is over 54,500 megawatts of scrubbed base-load electric generating capacity in our primary market area and plans have been announced to add over 18,400 megawatts of additional scrubbed capacity by the end of 2017. We also believe that we will experience increased demand for our coal from power plants that use coal from Central Appalachia as production in that region continues to decline.
 
We currently have 19 active surface mines that are managed as eight mining complexes. During the fourth quarter of 2009, our largest mine represented 12.5% of our coal production. This diversity reduces the risk that operational issues at any one mine will have a material impact on our business or our results of operations. Consistent coal quality across many of our mines and the mobility of our equipment fleet allows us to reliably serve our customers from multiple mining complexes while optimizing our mining plan. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky, that further enhance our ability to supply coal to our customers with river access from multiple mines.
 
We produced 5.8 million tons of coal during 2009, including 0.4 million tons produced from the reserves we acquired in western Kentucky from Phoenix Coal on September 30, 2009. As a result of this acquisition, our coal production during the fourth quarter of 2009 was 1.8 million tons, or 7.2 million tons on an annualized basis. During 2009, we sold 6.3 million tons of coal, including 0.5 million tons of purchased coal. We currently have long-term coal sales contracts in place for 2010, 2011, 2012 and 2013 that represent 97.2%, 93.0%, 71.4% and 39.7%, respectively, of our 2010 estimated coal sales of 8.5 million tons. Members of our senior management team have long-standing relationships within our industry, and we believe those relationships will allow us to continue to obtain long-term contracts for our coal production that will continue to provide us with a reliable and stable revenue base.
 
As of December 31, 2009, we controlled 91.6 million tons of proven and probable coal reserves, of which 68.6 million tons were associated with our surface mining operations and the remaining 23.0 million tons


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consisted of underground coal reserves that we have subleased to a third party in exchange for an overriding royalty. Historically, we have been successful at replacing the reserves depleted by our annual production and growing our reserve base by acquiring reserves with low operational, geologic and regulatory risks and that were located near our mining operations or that otherwise had the potential to serve our primary market area. Over the last five years, we have produced 23.6 million tons of coal and acquired 52.9 million tons of proven and probable coal reserves, including 24.6 million tons of coal reserves that we acquired in connection with the Phoenix Coal acquisition. We believe that our existing relationships with owners of large reserve blocks and our position as the largest producer of surface mined coal in Ohio will allow us to continue to acquire reserves in the future.
 
For the year ended December 31, 2009, we generated revenues of approximately $293.8 million, net income attributable to our unitholders of approximately $23.5 million and Adjusted EBITDA of approximately $50.8 million. Please read “Selected Historical and Pro Forma Consolidated Financial and Operating Data” for our definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) attributable to our unitholders. The following table summarizes our mining complexes, our coal production for the year ended December 31, 2009 and our coal reserves as of December 31, 2009:
 
                                     
    Production for the
    As of December 31, 2009
    Year Ended
    Proven &
          Average
    Primary
    December 31,
    Probable
    Average
    Sulfur
    Transportation
Mining Complexes   2009     Reserves(1)     Heat Value     Content     Methods
                (Btu/lb)     (%)      
    (in million tons)                  
 
Surface Mining Operations:
                                   
Northern Appalachia (principally Ohio)
                                   
Cadiz
    1.1       12.4       11,520       3.3     Barge, Rail
Tuscarawas County
    0.9       8.8       11,570       3.7     Truck
Belmont County
    1.3       6.6       11,510       3.7     Barge
Plainfield
    0.5       6.4       11,350       4.4     Truck
New Lexington
    0.6       4.9       11,260       4.0     Rail
Harrison(2)
    0.7       2.8       12,040       1.8     Barge, Rail, Truck
Noble County
    0.3       2.5       11,230       4.7     Barge, Truck
Illinois Basin (Kentucky)
                                   
Muhlenberg County(3)
    0.4       24.2       11,295       3.6     Barge, Truck
                                     
Total Surface Mining Operations
    5.8       68.6                      
                                     
Underground Coal Reserves:
                                   
Northern Appalachia (Ohio)
                                   
Tusky(4)
            23.0       12,900       2.1      
                                     
Total Underground Coal Reserves
            23.0                      
                                     
Total
            91.6                      
                                     
 
 
(1) Reported as recoverable coal reserves, which is the portion of the coal that could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield. For definitions of proven coal reserves, probable coal reserves and recoverable coal reserves, please read “Business — Coal Reserves.”
 
(2) The Harrison mining complex is owned by Harrison Resources, LLC, our joint venture with CONSOL Energy, Inc. We own 51% of Harrison Resources and CONSOL Energy owns the remaining 49% through one of its subsidiaries. Because the results of operations of Harrison Resources are included in our consolidated financial statements for the year ended December 31, 2009 as required by U.S. generally accepted accounting principles, or GAAP, coal production and proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100% of Harrison Resources. Please read “Business — Mining Operations — Northern Appalachia — Harrison Mining Complex.”


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(3) Acquired from Phoenix Coal on September 30, 2009. As a result, production data represents production from the date of acquisition though December 31, 2009.
 
(4) Please read “Business — Coal Reserves — Underground Coal Reserves” for more information about our underground coal reserves at the Tusky mining complex, which we have subleased to a third party mining company in exchange for an overriding royalty. During 2009, we received royalty payments on 0.6 million tons of coal produced from the Tusky mining complex.
 
Business Strategies
 
Our primary business objective is to maintain and, over time, increase our cash available for distribution by executing the following strategies:
 
  •     Increasing coal sales to large utilities with coal-fired, base-load scrubbed power plants in our primary market area.  In 2009, approximately 69% of the total electricity generated in our primary market area was generated by coal-fired power plants, compared to approximately 38% for the rest of the United States. We intend to continue to focus on marketing coal to large utilities with coal-fired, base-load scrubbed power plants in our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia.
 
  •     Maximizing profitability by maintaining highly efficient, diverse and low cost surface mining operations.  We intend to focus on lowering costs and improving the productivity of our operations. We believe our focus on efficient surface mining practices results in our cash costs being among the lowest of our peers in Northern Appalachia, which we believe will allow us to compete effectively, especially during periods of declining coal prices. We are in the process of implementing the same mining practices that we currently use in Ohio at the mines that we recently acquired as a part of the Phoenix Coal acquisition.
 
  •     Generating stable revenue by entering into long-term coal sales contracts.  We intend to continue to enter into long-term coal sales contracts for substantially all of our annual coal production, which will reduce our exposure to fluctuations in market prices.
 
  •     Continuing to grow our reserve base and production capacity.  We intend to continue to grow our reserve base by acquiring reserves with low operational, geologic and regulatory risks that we can mine economically and that are located near our mining operations or otherwise have the potential to serve our primary market area. We intend to continue to grow our production capacity by expanding our fleet of large scale equipment and opening new mines as our sales commitments increase over time.
 
Competitive Strengths
 
We believe the following competitive strengths will enable us to execute our business strategies successfully:
 
  •     We have an attractive portfolio of long-term coal sales contracts.  We believe our long-term coal sales contracts provide us with a reliable and stable revenue base. We currently have long-term coal sales contracts in place for 2010, 2011, 2012 and 2013 that represent 97.2%, 93.0%, 71.4% and 39.7%, respectively, of our 2010 estimated coal sales of 8.5 million tons.
 
  •     We have a successful history of growing our reserve base and production capacity.  Historically, we have been successful at replacing the reserves depleted by our annual production and growing our reserve base by acquiring reserves with low operational, geologic and regulatory risks and that are located near our mining operations or that otherwise have the potential to serve our primary market area. We have also been successful in growing our production capacity by expanding our fleet of large scale equipment and opening new mines to meet our sales commitments. Over the last five years, we have produced 23.6 million tons of coal and acquired 52.9 million tons of proven and probable coal reserves, including 24.6 million tons of coal reserves that we acquired in connection with the Phoenix Coal acquisition.


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  •     Our mining operations are flexible and diverse.  During the fourth quarter of 2009, our largest mine represented 12.5% of our coal production. We currently have 19 active surface mines that are managed as eight mining complexes. Consistent coal quality across many of our mines and the mobility of our equipment fleet allows us to reliably serve our customers from multiple mining complexes while optimizing our mining plan.
 
  •     We are a low cost producer of coal.  We use efficient mining practices that take advantage of economies of scale and reduce our operating costs per ton. Our use of large scale equipment, our good labor relations with our non-union workforce, our employees’ expertise and knowledge of our mining practices, our low level of legacy liabilities and our history of acquiring reserves without large up-front capital investments have positioned us as one of the lowest cash cost coal producers in Northern Appalachia.
 
  •     Both production of, and demand for, the coal we produce are expected to increase in our primary market area.  According to the EIA, production of coal in Northern Appalachia and the Illinois Basin is expected to increase by 29.2% and 33.1% through 2015, respectively. This expected increase is attributable to anticipated increases in demand for high-sulfur coal from scrubbed power plants and from consumers of Central Appalachia coal as production in that region continues to decline.
 
  •     Our senior management team and key operational employees have extensive industry experience.  The members of our senior management team have, on average, 24 years of experience in the coal industry and have a track record of acquiring, building and operating businesses profitably and safely.
 
  •     We have a strong safety and environmental record.  We operate some of the industry’s safest mines. From 2006 through 2009, our MSHA reportable incident rate was on average 14.4% lower than the rate for all surface coal mines in the United States. We have won numerous awards for our strong safety and environmental record.
 
Recent Coal Market Conditions and Trends
 
Coal consumption and production in the United States have been driven in recent periods by several market dynamics and trends. The recent global economic downturn has negatively impacted coal demand in the short-term, but long-term projections for coal demand remain positive.
 
  •     Favorable long-term outlook for U.S. steam coal market.  Although domestic coal consumption declined in 2009 due to the global economic downturn, the EIA forecasts that domestic coal consumption will increase by 14.4% through 2015 and by 32.2% through 2035, primarily due to the projected continued growth in coal-fired electric power generation demand.
 
  •     Increase in coal production in Northern Appalachia and in the Illinois Basin.  According to the EIA, coal production in Northern Appalachia and the Illinois Basin is expected to grow by 29.2% and 33.1%, respectively, through 2015 and by 35.7% and 42.8%, respectively, through 2035.
 
  •     Decline in coal production in Central Appalachia.  The EIA forecasts that coal production in Central Appalachia, the nation’s second largest coal production area, will decline by 34.5% through 2015 and by 54.1% through 2035. This decline will be offset by production from other U.S. regions, including Northern Appalachia and the Illinois Basin.
 
  •     Expected near-term increases in international demand for U.S. coal exports.  Although down from the previous year, U.S. exports began to increase in the second half of 2009, supported by recovering global economies and continued rapid growth in electric power generation and steel production capacity in Asia, particularly in China and India. Also, 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 steam coal, being drawn into the metallurgical coal export market, which further reduces supplies of steam coal from this region for domestic consumption.


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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 32 million tons of annual coal demand in ten years and that amount will more than double to 68 million tons by 2035. In addition, through the American Recovery and Reinstatement Act, or ARRA, the U.S. government has targeted over $1.5 billion to carbon capture and sequestration, or CCS, research and another $800 million for the Clean Coal Power Initiative, a ten-year program supporting commercial application of CCS technology.
 
  •     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 oxide, 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.
 
Our History
 
We are a Delaware limited partnership that was formed in August 2007 by American Infrastructure MLP Fund, L.P. and our founders, Charles C. Ungurean, the President and Chief Executive Officer of our general partner and a member of the board of directors of our general partner, and Thomas T. Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our general partner. Each of our two founders has over 37 years of experience in the coal mining industry. In connection with our formation, our founders contributed all of their interests in Oxford Mining Company to us.
 
Our founders formed Oxford Mining Company in 1985 to provide contract mining services to a mining division of a major oil company. In 1989, our founders transitioned Oxford Mining Company from a contract miner into a producer of its own coal reserves. In January 2007, Oxford Mining Company entered into a joint venture, Harrison Resources, with a subsidiary of CONSOL Energy to mine surface coal reserves purchased from CONSOL Energy.
 
In September 2009, we completed the acquisition of Phoenix Coal’s active surface mining operations. The Phoenix Coal acquisition provided us with an entry into the Illinois Basin in western Kentucky and included one mining complex comprised of four mines as well as the Island river terminal on the Green River in western Kentucky. In connection with this acquisition, we increased our total proven and probable coal reserves by 24.6 million tons.
 
Our Sponsors
 
American Infrastructure MLP Fund, L.P., together with its subsidiaries and affiliates, or AIM, is a private investment firm specializing in natural resources, infrastructure and real property. AIM, along with certain of the funds that AIM advises, indirectly owns all of the ownership interests in AIM Oxford Holdings, LLC, or AIM Oxford. Certain directors of our general partner are principals of AIM and have ownership interests in AIM. After completion of this offering, AIM Oxford will continue to hold 66.3% of the ownership interests in our general partner and will hold     % of our common units and     % of our subordinated units (     % of our total units).
 
C&T Coal, Inc., or C&T Coal, is owned by our founders, Charles C. Ungurean and Thomas T. Ungurean. After completion of this offering, C&T Coal will continue to hold 33.7% of the ownership interests in our general partner and will hold     % of our common units and     % of our subordinated units (     % of our total units).
 
In connection with the contribution of Oxford Mining Company to us in August 2007, C&T Coal, Charles C. Ungurean and Thomas T. Ungurean agreed that they would not compete with us in the coal mining business in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia and Virginia. This non-compete agreement is in effect until August 24, 2014.


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Summary of Risk Factors
 
An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. Please read “Risk Factors” beginning on page 19 carefully for a more thorough description of these and other risks.
 
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 the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner.
 
  •     The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant risks that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units and the market price of our common units may decline materially.
 
  •     Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.
 
  •     Our long-term coal sales contracts subject us to renewal risks.
 
  •     Our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability and growth.
 
  •     Competition within the coal industry may materially and adversely affect our ability to sell coal at an acceptable price.
 
  •     New and future regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.
 
  •     Existing and future regulatory requirements relating to sulfur dioxide and other air emissions could affect our customers and could reduce the demand for the high-sulfur coal we produce and cause coal prices and sales of our high-sulfur coal to decline materially.
 
  •     Our coal mining operations are subject to operating risks, which could result in materially increased operating expenses and decreased production levels and could have a material adverse effect on our business, financial condition or results of operations.
 
  •     We may not receive cash distributions from Harrison Resources in the future.
 
  •     We depend on a limited number of customers for a significant portion of our revenues, and the loss of, or significant reduction in, purchases by any of them could adversely affect our results of operations and cash available for distribution to our unitholders.
 
Risks Inherent in an Investment in Us
 
  •     Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
  •     Our general partner and its affiliates have conflicts of interest, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders.
 
  •     Our unitholders 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.


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  •     Our unitholders will experience immediate and substantial dilution of $      per common unit.
 
  •     The control of our general partner may be transferred to a third party without unitholder consent.
 
Tax Risks
 
  •     Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
 
  •     If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
 
  •     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.
 
  •     Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.
 
  •     Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
The Transactions
 
Immediately prior to the closing of this offering:
 
  •     We will distribute approximately $      million of cash and accounts receivable to our general partner, C&T Coal, AIM Oxford and the participants in the Oxford Resource Partners, LP Long-Term Incentive Plan, or our LTIP, pro rata, in accordance with their respective interests in us.
 
In connection with the closing of this offering, the following will occur:
 
  •     we will enter into a new credit facility;
 
  •     our general partner will convert its 2.0% general partner interest in us, represented by          general partner units, into           general partner units representing a 2.0% general partner interest in us;
 
  •     C&T Coal will convert all of its Class B common units, representing a     % limited partner interest in us, into: (i)          common units, representing a     % limited partner interest in us, and (ii)           subordinated units, representing a     % limited partner interest in us;
 
  •     AIM Oxford will convert all of its Class B common units, representing a     % limited partner interest in us, into: (i)          common units, representing a     % limited partner interest in us, and (ii)          subordinated units, representing a     % limited partner interest in us;
 
  •     the participants in our LTIP will receive a distribution of           common units for each common unit they currently own, resulting in their ownership of an aggregate of           common units, representing an aggregate     % limited partner interest in us;
 
  •     we will issue           common units to the public in this offering, representing an aggregate     % limited partner interest in us; and
 
  •     we will use the net proceeds from this offering and the net proceeds from borrowings under our new credit facility for the purposes set forth in “Use of Proceeds.”


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Organizational Structure
 
The following is a simplified diagram of our ownership structure after giving effect to this offering and the related transactions.
 
         
Public common units
      %
Interests of C&T Coal, AIM Oxford and Oxford Resources GP:
       
Common units held by C&T Coal
      %
Common units held by AIM Oxford
      %
Subordinated units held by C&T Coal
      %
Subordinated units held by AIM Oxford
      %
General partner units held by Oxford Resources GP
    2.0 %
Common units held by participants in our LTIP
      %
         
      100 %
 
(FLOW CHART)


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Management and Ownership
 
We are managed and operated by the board of directors and executive officers of our general partner, Oxford Resources GP. Currently, and upon the consummation of this offering, C&T Coal and AIM Oxford will own all of the ownership interests in our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Charles C. Ungurean, the President and Chief Executive Officer of our general partner and a member of the board of directors of our general partner, and Thomas T. Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our general partner, own all of the equity interests in C&T Coal. In addition, certain directors of our general partner are principals of AIM and have ownership interests in AIM. For information about the executive officers and directors of our general partner, please read “Management.” Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it.
 
In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, Oxford Mining Company and its subsidiaries. However, we, Oxford Mining Company and its subsidiaries do not have any employees. All of the employees that conduct our business are employed by our general partner, but we refer to these individuals in this prospectus as our employees.
 
Following the consummation of this offering, our general partner and its affiliates will not receive any management fee or other compensation in connection with our general partner’s management of our business, but will be reimbursed for expenses incurred on our behalf. These expenses include the costs of officer and director and other employee compensation and benefits properly allocable to us, and all other expenses necessary or appropriate for the conduct of our business and allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
 
Our general partner owns general partner units representing a 2.0% general partner interest in us, which entitles it to receive 2.0% of all the distributions we make. Our general partner also owns all of our incentive distribution rights, which will entitle it to increasing percentages, up to a maximum of 48%, of the cash we distribute in excess of $      per unit per quarter, after the closing of our initial public offering. Please read “Certain Relationships and Related Party Transactions.”
 
Principal Executive Offices
 
Our principal executive offices are located at 544 Chestnut Street, Coshocton, Ohio 43812. Our phone number is               . Following the completion of this offering, our website will be located at http://www.oxfordresources.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.
 
Summary of Conflicts of Interest and Fiduciary Duties
 
General.  Our general partner and its directors and officers have a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates under state law in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is owned by C&T Coal and AIM Oxford, the directors and officers of our general partner also have fiduciary duties to manage the business of our general partner in a manner beneficial to C&T Coal and AIM Oxford. As a result, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”


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Partnership Agreement Modifications of Fiduciary Duties.  Delaware law provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner and the directors and officers of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty by our general partner and its directors and officers. By purchasing a common unit, our unitholders are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner and its directors and officers by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to our unitholders.
 
For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”


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The Offering
 
Common units offered to the public           common units.
 
          common units if the underwriters exercise their option to purchase additional common units in full.
 
Units outstanding after this offering           common units representing a     % limited partner interest in us and           subordinated units representing a     % limited partner interest in us.
 
Our general partner will own           general partner units, representing a 2.0% general partner interest in us.
 
Use of proceeds We intend to use the net proceeds from this offering of approximately $      million (based on the mid-point of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and commissions but before paying offering expenses, to (i) repay in full the outstanding balance under our existing credit facility, (ii) distribute approximately $      million to C&T Coal, (iii) distribute approximately $      million to certain participants in our LTIP, (iv) pay offering expenses of approximately $      million and (v) replenish approximately $      million of our working capital. We will use the proceeds from borrowings of approximately $      million under our new credit facility to (i) distribute approximately $      million to AIM Oxford and (ii) pay fees and expenses relating to our new credit facility of approximately $     .
 
If the underwriters’ option to purchase additional common units is exercised in full, we will use the net proceeds to redeem from C&T Coal and AIM Oxford a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before expenses but after deducting underwriting discounts and commissions.
 
Please read “Use of Proceeds.”
 
Cash distributions We intend to make a minimum quarterly distribution of $           per common unit (or $      per common unit on an annualized basis) to the extent we have sufficient cash after the establishment of cash reserves by our general partner and the payment of our costs and expenses, including reimbursement of expenses to our general partner and its affiliates.
 
Our ability to pay cash distributions at this minimum quarterly distribution rate is subject to various restrictions and other factors described in more detail under “Cash Distribution Policy and Restrictions on Distributions.”
 
We will adjust the minimum quarterly distribution for the period from the closing of this offering through          , 2010 based on the actual length of the period.
 
Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter after the payment of costs and


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expenses, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement, in “How We Make Cash Distributions — Distributions of Available Cash — Definition of Available Cash” and in the glossary of terms attached as Appendix B.
 
In general, we will pay any cash distributions we make each quarter in the following manner:
 
•    first, 98% to the holders of common units and 2.0% to our general partner, until each common unit has received a minimum quarterly distribution of $      plus any arrearages from prior quarters;
 
•    second, 98% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $          ; and
 
•    third, 98% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $       .
 
If cash distributions to our unitholders exceed $      per common and subordinated unit in any quarter, our unitholders and our general partner will receive distributions according to the following percentage allocations:
 
                 
        Marginal Percentage Interest in
Total Quarterly Distribution
  Distributions
Target Amount   Unitholders   General Partner
 
above $     up to $     
  85%   15%
above $     up to $     
  75%   25%
above $     
  50%   50%
 
Please read “How We Make Cash Distribution — General Partner Interest and Incentive Distribution Rights.”
 
Historical cash available for distribution generated during the year ended December 31, 2009 would have been sufficient to allow us to pay     % and     % of the minimum quarterly distribution ($      per quarter, or $      on an annualized basis) on our common units and subordinated units, respectively.
 
Please read “Cash Distribution Policy and Restrictions on Distributions — Historical and Forecasted Results of Operations and Cash Available for Distribution.”
 
We have included a forecast of our cash available for distribution for the twelve months ending June 30, 2011 in “Cash Distribution Policy and Restrictions on Distributions — Historical and Forecasted Results of Operations and Cash Available for Distribution.” We believe, based on our financial forecast and related assumptions, that we will have sufficient available cash to enable us to pay the full minimum quarterly distribution of $      on all of our common units and subordinated units and the related distribution on our general partner’s 2.0% general partner interest for the four quarters ending June 30, 2011. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and


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general partner units to be outstanding immediately after this offering is approximately $      million. Based on our financial forecast and related assumptions, we forecast that our cash available for distribution for the twelve months ending June 30, 2011 will be approximately $      million.
 
Although we do not anticipate any, distributions out of capital surplus, as opposed to operating surplus, will constitute a return of capital to our unitholders and will result in a reduction in the minimum quarterly distribution and target distribution levels. For a further description of this treatment of distributions from capital surplus, please read “How We Make Cash Distributions — Distributions from Capital Surplus — Effect of a Distribution from Capital Surplus.”
 
Subordinated units C&T Coal and AIM Oxford will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that, in any quarter during the subordination period, the subordinated units are not entitled to receive any distributions of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.
 
Conversion of subordinated units The subordination period will end on the first business day after we have earned and paid from operating surplus generated in the applicable period at least (i) $      (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit and the corresponding distribution on our general partner units for each of three consecutive, non-overlapping four quarter periods ending on or after June 30, 2013 or (ii) $      per quarter (150% of the minimum quarterly distribution, which is $      on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner units for each of four consecutive quarters, in each case provided there are no arrearages on our common units at that time.
 
In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.
 
When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Please read “How We Make Cash Distributions — Subordination Period.”
 
General partner’s right to reset the target distribution levels Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum


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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 the same 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 common units and additional general partner units. The number of common units to be issued to our general partner will be equal to the number of common units that would have entitled their holder to an aggregate quarterly cash distribution equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters, assuming a per unit distribution equal to the average of the distribution for the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain its general partner interest in us immediately prior to the reset election. Please read “How We Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”
 
Issuance of additional units Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
 
Limited voting rights Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 80% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of     % of our common and subordinated units. This will give our general partner the ability to prevent its involuntary removal. Please read “The Partnership Agreement — Voting Rights.”
 
Limited call right If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units. Please read “The Partnership Agreement — Limited Call Right.”
 
Estimated ratio of taxable income to distributions We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2013, you 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. For example, if you receive an annual distribution of $      per unit, we estimate that your average allocable federal taxable income per year will be no more than $      per unit. Please read “Material Federal Income Tax Consequences — Tax Consequences


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of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.
 
Material federal income tax consequences For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences.”
 
Exchange listing We intend to apply to list our common units on the New York Stock Exchange under the symbol “OXF.”


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Summary Historical and Pro Forma Consolidated Financial and Operating Data
 
The following table presents our summary historical consolidated financial and operating data, as well as that of our accounting predecessor and wholly owned subsidiary, Oxford Mining Company, as of the dates and for the periods indicated. The following table also presents our summary pro forma consolidated financial and operating data as of the dates and for the periods indicated.
 
The summary historical consolidated financial data presented for the period from January 1, 2007 to August 23, 2007 are derived from the audited historical consolidated financial statements of Oxford Mining Company that are included elsewhere in this prospectus. The summary historical consolidated financial data presented as of December 31, 2007 for the period from August 24, 2007 to December 31, 2007 and as of and for the years ended December 31, 2008 and 2009 are derived from our audited historical consolidated financial statements that are included elsewhere in this prospectus.
 
The summary pro forma consolidated financial data presented as of and for the year ended December 31, 2009 are derived from our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma consolidated financial statements give pro forma effect to (i) the Phoenix Coal acquisition and (ii) this offering and the transactions related to this offering described in “Summary — The Transactions” and the application of the net proceeds from this offering described in “Use of Proceeds.” The unaudited pro forma consolidated balance sheet assumes this offering occurred as of December 31, 2009. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2009 assumes the Phoenix Coal acquisition, this offering and the transactions related to this offering occurred as of January 1, 2009. We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $3.0 million that we expect to incur as a result of being a publicly traded partnership.
 
For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Summary — The Transactions,” “Use of Proceeds,” “Business — Our History,” the historical consolidated financial statements of Oxford Mining Company, the historical combined financial statements for the carved-out surface mining operations of Phoenix Coal and our unaudited pro forma consolidated financial statements and audited consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.
 
The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business as it is an important supplemental measure of our performance. Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, depreciation, depletion and amortization, gain from purchase of a business, amortization of below-market coal sales contracts and non-cash equity compensation expense. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to its most directly comparable financial measure calculated and presented in accordance with GAAP.


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                      Pro Forma
 
      Oxford Mining Company
              Oxford Resource
 
      (Predecessor)       Oxford Resource Partners, LP       Partners, LP  
      Period from January 1,
      Period from August 24,
      Year Ended
      Year Ended
      Year Ended
 
      2007 to August 23,
      2007 to December 31,
      December 31,
      December 31,
      December 31,
 
      2007       2007       2008       2009       2009  
                                      (unaudited)  
      (in thousands, except per ton amounts)  
Statement of Operations Data:
                                                 
Revenues:
                                                 
Coal sales
    $ 96,799       $ 61,324       $ 193,699       $ 254,171       $ 312,490  
Transportation revenue
      18,083         10,204         31,839         32,490         37,221  
Royalty and non-coal revenue
      3,267         1,407         4,951         7,183         7,183  
                                                   
Total revenues
      118,149         72,935         230,489         293,844         356,894  
Costs and expenses:
                                                 
Cost of coal sales (excluding DD&A, shown separately)
      70,415         40,721         151,421         170,698         213,446  
Cost of purchased coal
      17,494         9,468         12,925         19,487         29,792  
Cost of transportation
      18,083         10,204         31,839         32,490         37,221  
Depreciation, depletion, and amortization
      9,025         4,926         16,660         25,902         31,424  
Selling, general and administrative expenses
      3,643         2,114         9,577         13,242         25,735  
                                                   
Total costs and expenses
      118,660         67,433         222,422         261,819         337,618  
                                                   
Income (loss) from operations
      (511 )       5,502         8,067         32,025         19,276  
Interest income
      26         55         62         35         39  
Interest expense
      (2,386 )       (3,498 )       (7,720 )       (6,484 )       (6,341 )
Gain from purchase of business(1)
                              3,823         3,823  
                                                   
Net income (loss)
      (2,871 )       2,059         409         29,399         16,797  
Less: Net income attributable to noncontrolling interest
      (682 )       (537 )       (2,891 )       (5,895 )       (5,895 )
                                                   
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
    $ (3,553 )     $ 1,522       $ (2,482 )     $ 23,504       $ 10,902  
                                                   
Statement of Cash Flows Data:
                                                 
Net cash provided by (used in):
                                                 
Operating activities
    $ 17,634       $ (8,478 )     $ 33,951       $ 35,540            
Investing activities
      (16,619 )       (103,336 )       (23,901 )       (51,115 )          
Financing activities
      (234 )       111,274         4,494         3,762            
Other Financial Data:
                                                 
Adjusted EBITDA(2)
    $ 7,832       $ 9,145       $ 20,349       $ 50,799       $ 39,016  
Maintenance capital expenditures(3)
      13,020         4,841         21,529         27,461         27,461  
Distributions
                        12,503         13,407            
Balance Sheet Data (at period end):
                                                 
Cash and cash equivalents
    $ 1,175       $ 635       $ 15,179       $ 3,366       $ 30,769  
Trade accounts receivable
      18,396         17,547         21,528         24,403         2,000  
Inventory
      4,824         4,655         5,134         8,801         8,801  
PPE, net
      54,510         106,408         112,446         149,461         149,461  
Total assets
      90,893         146,774         171,297         203,363         209,726  
Total debt (current and long-term)
      43,165         75,654         83,977         95,711         98,711  
Operating Data:
                                                 
Tons of coal produced
      2,693         1,634         5,089         5,846         7,221  
Tons of coal purchased
      641         305         434         530         885  
Tons of coal sold
      3,333         1,938         5,528         6,311         8,051  
Average sales price per ton(4)
    $ 29.04       $ 31.64       $ 35.04       $ 40.27       $ 38.81  
Cost of coal sales per ton produced(5)
    $ 26.15       $ 24.92       $ 29.75       $ 29.20       $ 29.56  
Cost of purchased coal per ton(6)
    $ 27.29       $ 31.08       $ 29.81       $ 36.79       $ 33.66  
 
 
(1) On September 30, 2009, we acquired all of the active surfacing mining operations of Phoenix Coal. The purchase price of this acquisition was less than the fair value of the net assets and liabilities we acquired. We recorded this difference as a gain of $3.8 million for the year ending December 31, 2009.
 
(2) See “Selected Historical and Pro Forma Consolidated Financial and Operating Data” for our definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income attributable to our unitholders.


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(3) Maintenance capital expenditures are cash expenditures made to maintain or replace, including over the long term, our operating capacity, asset base or operating income. Examples of maintenance capital expenditures include capital 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 operating capacity, asset base or operating income. Historically, we have not made a distinction between maintenance capital expenditures and other capital expenditures. For purposes of this presentation, however, we have evaluated our historical capital expenditures to estimate which of them would have been maintenance capital expenditures had we classified them as such at the time they were made. The amounts shown reflect our estimates based on that evaluation.
 
(4) Represents our coal sales divided by total tons of coal sold.
 
(5) Represents our cost of coal sales (excluding DD&A) divided by the tons of coal we produce.
 
(6) Represents the cost of purchased coal divided by the tons of coal we purchase.


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RISK FACTORS
 
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 following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
 
If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that 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.
 
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 the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner.
 
We may not have sufficient cash each quarter to pay the minimum quarterly distribution. 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 level of our production and coal sales and the amount of revenue we generate;
 
  •     the level of our operating costs, including reimbursement of expenses to our general partner;
 
  •     changes in governmental regulation of the mining industry or the electric power industry and the increased costs of complying with those changes;
 
  •     our ability to obtain, renew and maintain permits on a timely basis;
 
  •     prevailing economic and market conditions; and
 
  •     difficulties in collecting our receivables because of credit or financial problems of major customers.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, such as:
 
  •     the level of capital expenditures we make;
 
  •     the restrictions contained in our credit agreement and our debt service requirements;
 
  •     the cost of acquisitions;
 
  •     fluctuations in our working capital needs;
 
  •     our ability to borrow funds and access capital markets; 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 make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”
 
The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant risks that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units and the market price of our common units may decline materially.
 
The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations and cash available for distribution for the twelve months ending June 30, 2011. The financial forecast has been prepared by management, and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The


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assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks, including those discussed below, that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units or subordinated units and the market price of our common units may decline materially.
 
The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and general partner units to be outstanding immediately after this offering is approximately $      million. Historical cash available for distribution generated during the year ended December 31, 2009 would have been sufficient to allow us to pay     % and     % of the minimum quarterly distribution ($      per quarter, or $      on an annualized basis) on our common units and subordinated units, respectively. For a calculation of our ability to make distributions to unitholders based on our historical results for the year ended December 31, 2009 and for a forecast of our ability to pay the full minimum quarterly distribution on our common units, subordinated units and general partner units for the twelve months ending June 30, 2011, please read “Cash Distribution Policy and Restrictions on Distributions.”
 
Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.
 
Our business is closely linked to domestic demand for electricity. In 2009 we sold approximately 89% of our coal to domestic electric power generators, and we have long-term contracts in place with these electric power generators for a significant portion of our future production. In addition, because our business is linked to domestic demand for electricity, any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. The amount of coal consumed by electric power generation is affected by, among other things:
 
  •     general economic conditions, particularly those affecting industrial electric power demand;
 
  •     indirect competition from alternative fuel sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources;
 
  •     environmental and other governmental regulations, including those impacting coal-fired power plants; and
 
  •     energy conservation efforts and related governmental policies.
 
Historically, demand for electricity has decreased during periods of economic downturn, such as the recent downturn in the U.S. economy and financial markets. According to the EIA, total electricity consumption in the United States fell by approximately 3.8% during 2009 compared with 2008, primarily because of the effect of the economic downturn on industrial electricity demand, and U.S. electric generation from coal fell by approximately 11.0% in 2009 compared with 2008. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.
 
Changes in the coal industry, such as those caused by decreased electricity demand and increased competition, may also cause some of our customers not to renew, extend or enter into new long-term coal sales contracts with us or to enter into agreements to purchase reduced quantities of coal than in the past or on different terms or prices. Indirect competition from gas-fired generation has the most potential to displace a significant amount of coal-fired generation in the near term, particularly older, less efficient coal-powered generators. We expect that many of the new power plants needed in the future to meet increased demand for electricity will be fired by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain, and may be less prone to challenge, because natural-gas fired generators are viewed as having a lower environmental impact than coal-fired generators. In addition, uncertainty caused by federal and state regulations could cause coal customers to be uncertain of their coal requirements in future years and could deter them from entering into new, or extending or renewing existing, long-term coal sales contracts.


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Our long-term coal sales contracts subject us to renewal risks.
 
We sell most of the coal we produce under long-term coal sales contracts, which we define as contracts with terms greater than one year. As a result, our results of operations are dependent upon the prices we receive for the coal we sell under these contracts. To the extent we are not successful in renewing, extending or renegotiating our long-term contracts on favorable terms, we may have to accept lower prices for the coal we sell or sell reduced quantities of coal in order to secure new sales contracts for our coal. Prices and quantities under our long-term coal sales contracts are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or re-opened. The expectation of future prices for coal depends upon factors beyond our control, including the following:
 
  •     domestic and foreign supply and demand for coal, including demand for U.S. coal exports from eastern U.S. markets;
 
  •     domestic demand for electricity, which tends to follow changes in general economic activity;
 
  •     domestic and foreign economic conditions;
 
  •     the price, quantity and quality of other coal available to our customers;
 
  •     competition for production of electricity from non-coal sources, including the price and availability of alternative fuels and other sources, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the effects of technological developments related to these non-coal energy sources;
 
  •     domestic air emission standards for coal-fired power plants, and the ability of coal-fired power plants to meet these standards by installing scrubbers, purchasing emissions allowances or other means; and
 
  •     legislative and judicial developments, regulatory changes, or changes in energy policy and energy conservation measures that would adversely affect the coal industry.
 
Two of our long-term coal sales contracts contain market-based “re-opener” provisions that permit the sales price terms to be adjusted every three years. For 2011, 2012 and 2013, 0.4 million tons, 0.4 million tons and 0.6 million tons of coal, respectively, that we have committed to deliver under our long-term coal sales contracts are subject to price re-openers. Under these re-openers, the failure of the parties to agree on a new market-based price gives either party the right to terminate the contract. While these re-openers can benefit us during periods of rising coal prices, they have the potential to adversely affect us during periods of declining coal prices.
 
Our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability and growth.
 
Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics our customers desire. Because our reserves decline as we mine our coal, our future profitability and growth depend upon our ability to acquire additional coal reserves that are economically recoverable to replace the reserves we produce. If we fail to acquire or develop sufficient additional reserves to replace the reserves depleted by our production, our existing reserves will eventually be depleted. Please read “Business — Coal Reserves.”
 
Competition within the coal industry may materially and adversely affect our ability to sell coal at an acceptable price.
 
We compete for domestic sales with numerous other coal producers in Northern Appalachia and the Illinois Basin and in other coal producing regions of the United States, primarily Central Appalachia and the Powder River Basin, or the PRB. The most important factors on which we compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics (primarily heat, sulfur, ash and moisture content) and reliability of supply. For example, even though PRB coal must be transported by rail over long distances at substantial transportation cost to reach our primary market area, its delivered cost can be competitive with coal from other domestic coal-producing regions. Our competitors may have, among other


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things, greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures, partnerships with transportation companies or more effective risk management policies and procedures. In addition, competition within the U.S. coal industry will increase in periods of reduced foreign demand for domestic coal, as more domestic coal production is marketed in the United States. Our failure to compete successfully with our competitors could have a material adverse effect on our business, financial condition or results of operations.
 
New and future regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.
 
One major by-product of burning coal is carbon dioxide, which is a greenhouse gas and is a major source of concern with respect to global warming, also known as climate change. Climate change continues to attract public and scientific attention, and increasing government attention is being paid to reducing greenhouse gas emissions, including from coal-fired power plants. There are several regulatory proposals under consideration at the international, federal, state and local levels to limit emissions of greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may establish a cap-and-trade, and regulation under existing environmental laws by the U.S. Environmental Protection Agency, or the EPA. If enacted, these regulatory proposals and other efforts to reduce greenhouse gas emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers, may cause some users of coal to switch from coal to a lower-carbon fuel, and may result in the construction of fewer new coal-fired power plants. For a more detailed discussion of these regulatory proposals, please read “Business — Regulation and Laws.”
 
The permitting of new coal-fired power plants has also recently been contested, at times successfully, by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions from the new plants. Additionally, two U.S. federal appeals courts have allowed lawsuits to proceed by individuals, state attorneys general and others to pursue federal common law claims against major utility, coal, oil and chemical companies on the basis that those companies may have created a public nuisance due to their emissions of carbon dioxide.
 
The enactment of comprehensive laws to limit greenhouse gas emissions or the potential for liability or permitting issues based on greenhouse gas emissions may adversely affect the use of and demand for fossil fuels, particularly coal, which could have a material adverse effect on our business, financial condition or results of operations.
 
Existing and future regulatory requirements relating to sulfur dioxide and other air emissions could affect our customers and could reduce the demand for the high-sulfur coal we produce and cause coal prices and sales of our high-sulfur coal to decline materially.
 
Coal-fired power plants are subject to extensive environmental regulation, particularly with respect to air emissions. For example, the Clean Air Act Amendments of 1990, or the CAAA, and similar state and local laws place annual limits on the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds that can be emitted into the air by electric power generators, which are the largest end-users of our coal. The ability of coal-fired power plants to burn the high-sulfur coal we produce may be limited unless they:
 
  •     have already installed or will install costly pollution control devices such as scrubbers;
 
  •     can purchase and use emission allowances; or
 
  •     blend our high-sulfur coal with low-sulfur coal.
 
Projected demand growth for high-sulfur coal in our primary market area is largely dependent on planned installations of scrubbers at new and existing coal-fired power plants that use or plan to use high-sulfur coal as a fuel. The timing and amount of these scrubber installations may be affected by, among other things, anticipated changes in air quality regulations and the price and availability of sulfur dioxide emissions allowances. To the extent that these scrubber installations do not occur or are substantially delayed and


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sufficient sulfur dioxide allowances are unavailable or are prohibitively expensive, demand for our high-sulfur coal could materially decrease, which could have a material adverse effect on our business, financial condition or results of operations.
 
Our coal mining operations are subject to operating risks, which could result in materially increased operating expenses and decreased production levels and could have a material adverse effect on our business, financial condition or results of operations.
 
Our coal mining operations are subject to a number of operating risks beyond our control. Because we maintain very limited produced coal inventory, various conditions or events could disrupt operations, adversely affect production and shipments and increase the cost of mining at particular mines for varying lengths of time, which could have a material adverse effect on our business, financial condition or results of operations. These conditions and events include, among others:
 
  •     poor mining conditions resulting from geologic, hydrologic or other conditions, which may cause instability of highwalls or spoil-piles or cause damage to nearby infrastructure;
 
  •     adverse weather and natural disasters, such as heavy rains, flooding and other natural events affecting operations or transportation;
 
  •     the unavailability of qualified labor and contractors;
 
  •     the unavailability or increased prices of equipment (including heavy mobile equipment) or other critical supplies such as tires and explosives, fuel, lubricants and other consumables of the type, quantity or size needed to meet production expectations;
 
  •     fluctuations in transportation costs and transportation delays or interruptions, including those caused by river flooding and lock closures for repairs;
 
  •     delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits, including environmental permits, or mineral and surface rights;
 
  •     changes in or enhanced enforcement of current and future health, safety and environmental regulations or changes in interpretations of current regulations, including the classification of plant and animal species near our mines as endangered or threatened species;
 
  •     mine accidents or other unforeseen casualty events;
 
  •     employee injuries or fatalities;
 
  •     increased or unexpected reclamation costs; and
 
  •     the inability to monitor our mining operations due to disruptions or failures of our information technology systems.
 
These changes, conditions and events may materially increase our cost of mining and delay or halt production at particular mines either permanently or for varying lengths of time.
 
We maintain insurance coverage against some but not all potential losses to protect against the risks we face. We generally do not carry business interruption insurance and we may elect not to carry other types of insurance in the future if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to ensure fully against pollution and environmental risks. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could have a material adverse effect on our business, financial condition or results of operations.
 
We may not receive cash distributions from Harrison Resources in the future.
 
In January 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy to mine surface coal reserves purchased from CONSOL Energy. Since its inception, Harrison Resources has acquired 3.5 million tons of proven and probable coal reserves from CONSOL Energy. Pursuant to its operating agreement, all members of Harrison Resources must approve cash distributions, other than tax distributions to


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its members. The members of Harrison Resources have consistently approved cash distributions from Harrison Resources on a quarterly basis, including the $6.3 million that we received in 2009. In the future, however, there can be no assurance that we will receive regular cash distributions, as its members may prefer to keep cash in Harrison Resources instead of approving distributions. As a result, our ability to receive future distributions from Harrison Resources may be limited, which could have a material adverse effect on our ability to make cash distributions to our unitholders.
 
A significant portion of the cash available for distribution to our unitholders is derived from royalty payments we receive on our underground coal reserves, which we do not operate.
 
In June 2005, we sold our underground mining operations at the Tusky mining complex to an independent coal producer in Northern Appalachia. As part of the transaction, we subleased our underground coal reserves to this producer in exchange for an overriding royalty. Our overriding royalty is equal to a percentage of the sales price that our sublessee receives for the coal it produces and sells from our underground reserves. Our sublessee is also obligated to pay directly to our lessor a tonnage-based royalty on the production from these reserves. For the year ended December 31, 2009, we received royalty payments on our underground coal reserves from our sublessee of approximately $4.5 million, or approximately 8.9% of our Adjusted EBITDA for the year ended December 31, 2009. The royalty payments that we receive from our sublessee could be adversely affected by any of the following:
 
  •     a substantial and extended decline in the sales price our sublessee receives for the coal it produces;
 
  •     any decisions by our sublessee to reduce or discontinue production or sales of coal produced from our underground coal reserves;
 
  •     any failure by our sublessee to properly manage its operations;
 
  •     our sublessee’s operational risks relating to our underground coal reserves, which expose our sublessee to operating conditions and events beyond its control, including the inability to acquire necessary permits, changes or variations in geologic conditions, changes in governmental regulation of the coal industry or the electric power industry, mining and processing equipment failures and unexpected maintenance problems, interruptions due to transportation delays, adverse weather and natural disasters, labor-related interruptions and fires and explosions; and
 
  •     a material decline in the creditworthiness of our sublessee, including as a result of the current economic downturn.
 
As we do not operate the Tusky mining complex, our ability to address the risks discussed above will be limited. If the royalty payments we receive from our sublessee are reduced, our ability to make cash distributions to our unitholders could be adversely affected. In addition, we could lose our lease rights with our lessor if our sublessee fails to pay the tonnage-based royalty owed to our lessor and we fail to timely make our lessor whole for those unpaid royalties.
 
The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter is based on our current estimates and could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.
 
Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or major refurbishment or replacement of mining equipment. Our initial annual estimated maintenance capital expenditures for purposes of calculating operating surplus will be $32.3 million. This amount is based on our current estimates of the amounts of expenditures we will be required to make in future years to maintain our depleting capital asset base, which we believe to be reasonable. This amount has been taken into consideration in calculating our forecast of cash available for distribution in “Cash Distribution Policy and Restrictions on Distributions.” The initial amount of our estimated annual maintenance capital expenditures may be more than our initial actual maintenance capital expenditures, which will reduce the


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amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year.
 
Increases in the cost of diesel fuel and explosives, or the inability to obtain a sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and have a material adverse effect on our profitability.
 
We use considerable quantities of diesel fuel in our mining operations. We typically hedge a large portion of our diesel fuel needs each year through fixed price forward contracts that provide for physical delivery (during 2009, we hedged 54.4% of our diesel fuel needs). We also recover a portion of our total fuel costs through full or partial cost pass through and inflation adjustment provisions in our long-term coal sales contracts. If the price of diesel fuel increases significantly and we are unable to recover all or a portion of those increases through these cost pass through or inflation adjustment provisions, our operating expenses will increase relative to our revenue, which could have a material adverse effect on our profitability. A significant amount of explosives are used in our mining operations. We use third party contractors to provide blasting services, and they generally pass through to us the cost of explosives, which are subject to fluctuations. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other buyers. Shortages in raw materials used in the manufacturing of explosives, which, in some cases, do not have ready substitutes, or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of our contractors to obtain these supplies.
 
Extensive environmental laws and regulations impose significant costs on our mining operations, and future laws and regulations could materially increase those costs or limit our ability to produce and sell coal.
 
The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to environmental matters such as:
 
  •     limitations on land use;
 
  •     mine permitting and licensing requirements;
 
  •     reclamation and restoration of mining properties after mining is completed;
 
  •     management of materials generated by mining operations;
 
  •     storage, treatment and disposal of wastes;
 
  •     air quality standards;
 
  •     water pollution;
 
  •     protection of human health and the preservation of plants and animals, including endangered or threatened species;
 
  •     protection of wetlands;
 
  •     discharge of materials into the environment; and
 
  •     effects of mining on surface water and groundwater quality and availability.
 
The costs of complying with these laws and regulations are significant. Although we believe that we are in substantial compliance, we may, in the future, experience violations that would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. We may incur significant costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations.
 
The enforcement of laws and regulations governing the coal mining industry has increased substantially for a number of reasons, including the recent occurrence of mining accidents at certain mines. Moreover, the trend is towards more stringent regulations and more vigorous enforcement of those laws and regulations particularly in light of the renewed focus by governmental agencies on the mining industry. Thus, the costs of


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compliance with those laws and regulations may become more costly and the consequences for any non-compliance may become more significant in the future.
 
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 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 business, financial condition or results of operations. Please read “Business — Regulation and Laws.”
 
We may be unable to obtain, maintain or renew permits necessary for our operations, which would materially reduce our production, cash flows and profitability.
 
As is typical in the coal industry, our coal production is dependent on our ability to obtain the permits and approvals from federal and state regulatory authorities needed to mine our coal reserves within the timeline specified in our surface mining plan. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted expected production in certain regions, primarily in Central Appalachia, but could also affect Northern Appalachia, the Illinois Basin and other regions in the future.
 
Based on our current surface mining plan, we have proven and probable coal reserves with active permits that will allow us to mine for approximately three years. Typically, we submit the necessary permit applications 12 to 30 months before we plan to mine a new area. Some of our required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all, and in some instances we have had to abandon or substantially delay the mining of coal in certain areas covered by the application in order to obtain required permits and approvals.
 
The Army Corps of Engineers, or the Corps, the EPA and the Department of the Interior recently announced an interagency action plan for an “enhanced review” of any project that requires a permit under both the Surface Mining Control and Reclamation Act of 1977, or SMCRA, and the federal Clean Water Act, or CWA, designed to reduce the harmful environmental consequences of mountain-top mining in the Appalachian region. As part of the June 2009 interagency memorandum of understanding, the Corps proposed to suspend and modify Nationwide Permit 21, or NWP 21, in the Appalachian region of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia to prohibit its use to authorize discharges of fill material into waters of the United States for mountain-top mining. Two of our permit applications that cover 1.1 million tons of our coal reserves are currently being reviewed by the EPA under its enhanced review procedures even though the mining activities in question do not utilize mountain-top mining, a method of mining we do not employ. As of March 19, 2010, the two permits have not been issued. Additional permits could be delayed in the future if the EPA continues to apply these enhanced review procedures to applications for these permits in connection with coal mining in Appalachia. If the required permits are not issued or renewed in a timely fashion or at all, or if permits issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production, and our operations and there could be a material adverse effect on our ability to make cash distributions to our unitholders.


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We depend on a limited number of customers for a significant portion of our revenues, and the loss of, or significant reduction in, purchases by any of them could adversely affect our results of operations and cash available for distribution to our unitholders.
 
We derived 77% of our revenues from coal sales to our five largest customers for the year ended December 31, 2009, and as of March 19, 2010, we had long-term coal sales contracts in place with these same customers for 75% of our estimated coal production from operations for the year ending December 31, 2010. We expect to continue to derive a substantial amount of our total revenues from a small number of customers in the future. However, we may be unsuccessful in renewing long-term coal sales contracts with our largest customers, and those customers may discontinue or reduce purchasing coal from us. If any of our largest customers significantly reduces the quantities of coal it purchases from us and if we are unable to sell such excess coal to our other customers on terms substantially similar to the terms under our current long-term coal sales contracts, our business, our results of operations and our ability to make distributions to our unitholders could be adversely affected.
 
If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated.
 
All of the mines we operate are surface mining operations. The SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining. We estimate our total reclamation and mine-closing liabilities based on permit requirements, engineering studies, including the estimated life of our mines, and our engineering expertise related to the permit requirements. As of December 31, 2009, we had accrued a reserve of approximately $13.3 million for future reclamation and mine-closure liabilities. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers. The estimated liability can change significantly if actual costs vary from our original assumptions or if governmental regulations change significantly. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates and a third-party profit, as necessary. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on behalf of us. The resulting estimated reclamation and mine closure obligations could change significantly if actual results change significantly from our assumptions, which could have a material adverse effect on our financial condition or results of operations. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Off-Balance Sheet Arrangements” for a description of these liabilities.
 
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
 
Our future level of debt could have important consequences to us, including the following:
 
  •     our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
 
  •     our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
 
  •     we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
 
  •     our flexibility in responding to changing business and economic conditions may be limited.
 
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our


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business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
 
Restrictions in our new credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.
 
We expect to enter into a new credit facility concurrently with the closing of the offering. Our new credit facility is likely to limit our ability to, among other things:
 
  •     incur additional debt;
 
  •     make distributions on or redeem or repurchase units;
 
  •     make certain investments and acquisitions;
 
  •     incur certain liens or permit them to exist;
 
  •     enter into certain types of transactions with affiliates;
 
  •     merge or consolidate with another company; and
 
  •     transfer or otherwise dispose of assets.
 
Our new credit facility also will likely contain covenants requiring us to maintain certain financial ratios.
 
The provisions of our new credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
 
The availability and reliability of transportation could impair our ability to supply coal to our customers.
 
Our coal is transported to customers by barge, truck and rail. Disruption of these transportation services because of weather-related problems (such as river flooding), mechanical difficulties, train derailment, bridge or structural concerns, infrastructure damage, whether caused by ground instability, accidents or otherwise, strikes, lock-outs, lack of fuel or maintenance items, fuel costs, transportation delays, accidents, terrorism or domestic catastrophe or other events could temporarily or over the long term impair our ability to supply coal to our customers and our customers’ ability to take delivery of our coal and, therefore, could have a material adverse effect on our business, financial condition or results of operations.
 
Our operations may impact the environment or cause environmental contamination, which could result in material liabilities to us.
 
Our operations use hazardous materials, generate limited quantities of hazardous wastes and may affect runoff or drainage water. In the event of environmental contamination or a release of hazardous materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and clean up of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.
 
We maintain coal refuse areas and slurry impoundments at our Tuscarawas County and Muhlenberg County mining complexes. Such areas and impoundments are subject to extensive regulation. One of those impoundments overlies a mined out area, which can pose a heightened risk of structural failure and of damages arising out of such failure. When a slurry impoundment experiences a structural failure, it could


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release large volumes of coal slurry into the surrounding environment, which in turn can result in extensive damage to the environment and natural resources, such as bodies of water. A failure may also result in civil or criminal fines, penalties, personal injuries and property damages, and damage to wildlife or natural resources.
 
Surface or groundwater that comes in contact with materials resulting from mining activities can become acidic and contain elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” or AMD. We have seven mining permits that are identified on Ohio’s Inventory of Long-Term AMD sites. Only one of these sites, associated with the Strasburg Wash Plant, requires continuous AMD treatment, for which we have estimated the present value of the projected annual treatment cost at less than $10,000 per year. While we anticipate that AMD treatment will not be required once reclamation is completed, it is possible that AMD treatment will be required for some time and current AMD treatment costs could escalate due to changes in flow or water quality. These and other similar impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on us.
 
If the third-party sources from which we purchase coal are unable to fulfill the delivery terms of their contracts, our results of operations could be adversely affected.
 
Based on our expected production for 2010, we will need to purchase coal from third-party sources to fulfill a portion of our committed coal deliveries for 2010 under our coal sales contracts. We have entered into a long-term coal purchase contract that will cover most of our expected coal purchases for 2010 and a portion of our expected coal purchases for at least three years thereafter. The price we pay for the coal purchased under this contract is based on a minimum price and the price we receive under our long-term coal sales contracts for such coal. From time to time, we also purchase coal from other producers at spot prices. Our profitability and exposure to loss on our coal purchases are dependent upon the price of the coal we purchase and the reliability, including the financial viability, of the third-party coal producers from whom we purchase. Operational difficulties, changes in demand and other factors could affect the availability, pricing and quality of the coal we purchase and the price(s) at which we resell such purchased coal. Disruptions in the quantities or qualities of the coal we purchase could affect our ability to fill our customer orders or require us to purchase coal at higher prices from other sources in order to satisfy those orders. If we are unable to fill a customer order due to our inability to purchase coal from third parties in sufficient quantities, qualities or at attractive prices, our results of operations could be adversely affected.
 
Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.
 
Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of Charles C. Ungurean and our other executive officers and key employees. In particular, we depend significantly on Mr. Ungurean’s long-standing relationships within our industry. The loss of any of our senior executives could have a material adverse effect on our business unless and until we find a qualified 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 management 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 publicly traded partnership, our future success will also depend on our ability to hire and retain management with relevant experience. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.
 
A shortage of skilled labor in the mining industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
 
Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time


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encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If coal prices decrease in the future or our labor prices increase, or if we experience materially increased health and benefit costs with respect to our employees, our results of operations could be materially and adversely affected.
 
Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.
 
All of our mines are operated by non-union employees. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our production and materially reduce our profitability.
 
Inaccuracies in our estimates of our coal reserves could result in lower than expected revenues or higher than expected costs.
 
Our future performance depends on, among other things, the accuracy of the estimates of our proven and probable coal reserves. The estimates of our proven and probable reserves associated with our surface mining operations in Ohio are derived from our internal estimates, which estimates were audited by John T. Boyd Company, an independent mining and geological consulting firm. The estimates of our proven and probable reserves associated with our surface mining operations in the Illinois Basin and our proven and probable underground coal reserves are derived from reserve reports prepared by John T. Boyd Company. These estimates are based on geologic data, economic data such as cost of production and projected sale prices and assumptions concerning permitability and advances in mining technology. The estimates of our proven and probable coal reserves as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, coal reserves recently purchased or otherwise acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, any one of which may vary considerably from actual results. These factors and assumptions include:
 
  •     quality of the coal;
 
  •     geologic and mining conditions, which may not be fully identified by available exploration data or may differ from our experiences in areas where we currently mine;
 
  •     the percentage of coal ultimately recoverable;
 
  •     the assumed effects of regulation, including the issuance of required permits, and taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
 
  •     assumptions concerning the timing for the development of reserves; and
 
  •     assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.
 
As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers and accounting personnel, or by the same engineers and accounting personnel at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in the estimates related to our reserves could have a material adverse effect on our ability to make cash distributions.
 
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. The current economic volatility and tightening credit markets increase the risk that we may not


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be able to collect payments from our customers or be required to continue to deliver coal even if the customer’s creditworthiness deteriorates. A continuation or worsening of current economic conditions or other prolonged global or U.S. recessions could also impact the creditworthiness of our customers.
 
Approximately 12% of our 2009 sales were to coal brokers, who resell our coal to end users, including utilities. Under some of these arrangements, we have contractual privity only with the broker and may not be able to pursue claims against the end users in connection with these sales if we do not receive payment from the broker, who may only have limited assets. We expect our sales through brokers to increase in 2010.
 
If the creditworthiness of a customer 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 that customer. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If we are able to withhold shipments, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could have a material adverse effect on our financial position. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default.
 
Failure to obtain, maintain or renew our security arrangements, such as surety bonds or letters of credit, in a timely manner and on acceptable terms could have an adverse effect on our cash available for distribution to our unitholders.
 
Federal and state laws require us to secure the performance of certain long-term obligations, such as mine closure or reclamation costs. The amount of these security arrangements is substantial, with total amounts of surety bonds at December 31, 2009 of approximately $31.3 million, which were supported by letters of credit of $6.9 million. Federal and state governments could increase bonding requirements in the future. Certain business transactions, such as coal leases and other obligations, may also require bonding. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including putting up letters of credit or posting cash collateral, or other terms less favorable to us upon those renewals. Our ability to obtain or renew our surety bonds could be impacted by a variety of other factors including lack of availability, unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place. Surety bond issuers may demand terms that are less favorable to us than the terms we currently receive and there may be fewer companies willing to issue these bonds. Due to current economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds and we may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.
 
Our management team does not have experience managing our business as a stand-alone publicly traded partnership, and if they are unable to manage our business as a publicly traded partnership our business may be affected.
 
Our management team does not have experience managing our business as a publicly traded partnership. If we are unable to manage and operate our partnership as a publicly traded partnership, our business and results of operations will be adversely affected.
 
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 establish and maintain effective internal controls, our financial condition and operating results could be adversely affected.
 
We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We are also in the process of performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We will be required to comply with Section 404 for the year ending December 31, 2011.


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However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. In connection with the audit of our financial statements, a significant deficiency in our internal controls was identified that related to 2008. This significant deficiency related to the timeliness and thoroughness of our account reconciliation and review procedures. Management has taken steps to remediate this significant deficiency by restructuring and refining its account reconciliation process and tracking. While we believe that this significant deficiency has been remediated, we may have additional significant deficiencies in the future.
 
If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our consolidated financial statements, and as a result our unit price may be adversely affected. If we fail to remedy any material weakness, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our unit price may be adversely affected.
 
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.
 
Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
 
Risks Inherent in an Investment in Us
 
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Fiduciary duties owed to our unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
 
  •     limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
 
  •     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


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  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 limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;
 
  •     provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of the partnership;
 
  •     generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner, or the Conflicts Committee, and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
 
  •     provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees 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 engaged in fraud or willful misconduct.
 
By purchasing a common unit, a common unitholder will become bound by the provisions of the partnership agreement, including the provisions described above. Please read “Description of the Common Units — Transfer of Common Units.”
 
Our general partner and its affiliates have conflicts of interest, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders.
 
Following the offering, C&T Coal will own a     % limited partner interest in us (or a     % limited partner interest in us if the underwriters exercise their option to purchase additional common units in full), AIM Oxford will own a     % limited partner interest in us (or a     % limited partner interest in us if the underwriters exercise their option to purchase additional common units in full), and C&T Coal and AIM Oxford will own and control our general partner. Although our general partner has certain fiduciary duties 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 its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between C&T Coal and AIM Oxford and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Please read “— Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” The risk to our unitholders due to such conflicts may arise because of the following factors, among others:
 
  •     our general partner is allowed to take into account the interests of parties other than us, such as C&T Coal and AIM Oxford, 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 owners of our general partner to pursue a business strategy that favors us. Executive officers and directors of our general partner’s owners have a fiduciary duty to make these decisions in the best interest of their owners, which may be contrary to our interests;
 
  •     our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;


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  •     our general partner determines our estimated maintenance capital expenditures, which reduce operating surplus, and that determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;
 
  •     in some instances, 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 periods;
 
  •     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 on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
  •     our general partner intends to limit its liability regarding our contractual and other obligations;
 
  •     our general partner may exercise its limited 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 owed to us by it and its affiliates; and
 
  •     our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
In addition, AIM currently holds substantial interests in other companies in the energy and natural resource sectors. 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. However, AIM and AIM Oxford are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us. Please read “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest — AIM Oxford and AIM, affiliates of our general partner, may compete with us.”
 
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. 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 unitholders 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.
 
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner.
 
Our unitholders will be unable initially to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon the consummation of this offering to be able to prevent removal of our general partner. The vote of the holders of at least 80% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner.


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Following the closing of this offering, affiliates of our general partner will own     % of our common units and subordinated units (or     % of our common units and subordinated units, 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 units held by our general partner and its affiliates are not 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. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.
 
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 misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner during the subordination period because of our unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period. 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.
 
Our 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. As a result, our 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 and not their fair value. Please read “Dilution.”
 
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 in us 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, there is no restriction in our partnership agreement on 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 choices and to control the decisions and actions of the board of directors and executive officers of our general partner.
 
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
 
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
 
Upon consummation of this offering, C&T Coal and AIM Oxford will own an aggregate of     % of our common units and subordinated units (or     % of our common units and subordinated units, if the underwriters exercise their option to purchase additional common units in full). 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 not less than the then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common 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


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partnership agreement that prevents our general partner from issuing additional common units and exercising its limited call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the common 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. For additional information about the limited call right, please read “The Partnership Agreement — Limited Call Right.”
 
We may issue additional units without unitholder approval, which would dilute unitholder interests.
 
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, our partnership agreement does not prohibit the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •     our 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 relative voting strength of each previously outstanding unit may be diminished; and
 
  •     the market price of the common units may decline.
 
Our general partner may, without unitholder approval, 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. This could result in lower distributions to holders of our common units.
 
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48%) 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 and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, 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 distributions on its incentive distribution rights based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels. Please read “How We Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”
 
Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to our unitholders.
 
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole


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discretion in accordance with the terms of our partnership agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. Please read “Cash Distribution Policy and Restrictions on Distributions,” “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.” The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates could reduce the amount of available cash for distribution 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 our unitholders could lose all or part of their investment.
 
Prior to the offering, there has been no public market for the common units. After the offering, there will be only           publicly traded common units (or           publicly traded common units, if the underwriters exercise their option to purchase additional common units in full). 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. Our 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 the common units has been 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;
 
  •     loss of a large customer;
 
  •     announcements by us or our competitors of significant contracts or acquisitions;
 
  •     changes in accounting standards, policies, guidance, interpretations or principles;
 
  •     changes in interest rates;
 
  •     general economic conditions;
 
  •     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.”
 
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 as a private company. We expect that complying with the rules and regulations implemented by the SEC and the New York Stock Exchange will increase our legal and financial compliance costs and make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have three independent directors, create additional board committees 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 publicly traded partnership reporting requirements.
 
Our unitholders who fail to furnish certain information requested by our general partner or who our general partner, upon receipt of such information, determines are not eligible citizens will not be entitled to


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receive distributions or allocations of income or loss on their common units and their common units will be subject to redemption.
 
Our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units and subordinated units of any holder that is not an eligible citizen or fails to furnish the requested information. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement — Non-Citizen Assignees; Redemption.”
 
Our unitholders may have liability to repay distributions.
 
Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. 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.
 
Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders.
 
Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders. If our general partner secures our obligations or indebtedness by all or substantially all of our assets and if we are unable to satisfy such obligations or repay such indebtedness, the lenders could seek to foreclose on our assets. The lenders may also sell all or substantially all of our assets under such foreclosure or other realization upon those encumbrances without prior approval of our unitholders, which could adversely affect the price of our common units.
 
Tax Risks
 
In addition to reading the following risk factors, please read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
 
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or 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.


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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 and local income tax at varying rates. Distributions would generally be taxed again as corporate distributions (to the extent of our current and accumulated earnings and profits), 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, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our 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.
 
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
 
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Recently, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships, which, if enacted, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.
 
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.
 
Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2011, or the Budget Proposal, is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would (i) eliminate current deductions and the 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties, and (iv) 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 common units.
 
Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they


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receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
 
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 our unitholders.
 
We have not requested a ruling from the Internal Revenue Service, or the IRS, with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
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 for federal income tax purposes 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 decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Federal Income Tax Consequences — Disposition of Common 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 our common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
 
We will treat each purchaser of 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 and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.


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We 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 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 use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”
 
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 federal income 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 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 common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan 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. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
 
We will adopt certain valuation methodologies and monthly conventions that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
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 technically terminated our 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the


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same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for 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. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.
 
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including 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 control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders 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, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Indiana, Kentucky, Michigan, Ohio and Pennsylvania. Each of these states currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.


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USE OF PROCEEDS
 
We expect to receive net proceeds of approximately $      million, after deducting underwriting discounts and commissions but before paying offering expenses, from the issuance and sale of common units offered by this prospectus. We will use the net proceeds from this offering to:
 
  •     repay in full the outstanding balance under our existing credit facility, which was approximately $93.7 million at March 19, 2010;
 
  •     distribute approximately $      million to C&T Coal in respect of its limited partner interest in us;
 
  •     distribute approximately $      million to certain participants in our LTIP in respect of their limited partner interests in us; and
 
  •     pay offering expenses of approximately $      million.
 
We will retain the remaining net proceeds from this offering to replenish approximately $      million of our working capital.
 
Immediately following the repayment of the outstanding balance under our existing credit facility with the net proceeds of this offering, we will enter into a new credit facility and borrow approximately $      under that credit facility. We will use the proceeds from that borrowing to:
 
  •     distribute approximately $      million to AIM Oxford in respect of its limited partner interest in us; and
 
  •     pay fees and expenses relating to our new credit facility of approximately $           million.
 
A portion of the amounts to be repaid under our existing credit facility with the net proceeds of this offering were used to finance our acquisition of the surface mining operations of Phoenix Coal in September 2009. As of March 19, 2010, we had approximately $93.7 million of indebtedness outstanding under our existing credit facility. This indebtedness had a weighted average interest rate of 6.55% as of March 19, 2010. Our existing credit facility matures in August 2012.
 
Our estimates assume an initial public offering price of $      per common unit (based upon the mid-point of the price range set forth on the cover page of this prospectus) and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, to increase or decrease by $      million. If the proceeds increase due to a higher initial public offering price, we will use the additional proceeds for general partnership purposes. If the proceeds decrease due to a lower initial public offering price, the amount that we have available for general partnership purposes will decrease by a corresponding amount.
 
The proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem from C&T Coal and AIM Oxford that number of common units that corresponds to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts.
 
Affiliates of Citigroup Global Markets Inc. are lenders under our existing credit facility and will receive their proportionate share of the repayment of the outstanding balance under our existing credit facility by us in connection with this offering.


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CAPITALIZATION
 
The following table shows:
 
  •     our historical capitalization, as of December 31, 2009; and
 
  •     our pro forma, as adjusted capitalization as of December 31, 2009, giving effect to:
 
  •     our entry into our new credit facility and the repayment of all outstanding indebtedness under our existing credit facility;
 
  •     our receipt of net proceeds of $      million from the issuance and sale of           common units to the public at an assumed initial offering price of $      per unit;
 
  •     the application of the net proceeds from this offering of approximately $      million (based on the mid-point of the price range set forth on the cover page of this prospectus) in the manner described in “Use of Proceeds”; and
 
  •     the other transactions described in “Summary — The Transactions.”
 
We derived this table from and it should be read in conjunction with and is qualified in its entirety by reference to the historical and pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                 
    As of December 31, 2009  
          Pro Forma,
 
    Actual     As Adjusted  
    (in thousands)  
 
Cash and cash equivalents
  $ 3,366          
                 
Long-term debt (including current maturities):
               
Existing credit facility(1)
    90,729          
New credit facility(2)
             
Other debt
    4,982          
                 
Total long-term debt (including current maturities)
  $ 95,711          
                 
Partners’ capital:
               
Limited partners:
               
Common unitholders — public
             
Common unitholders — LTIP
    787          
Common unitholders — sponsors
    53,173          
Subordinated unitholders — sponsors
             
General partner
    1,085          
                 
Total Oxford Resource Partners, LP partners’ capital
    55,045          
Noncontrolling interest
    2,067          
                 
Total partners’ capital
    57,112          
                 
Total capitalization
  $ 152,823          
                 
 
 
(1) As of March 19, 2010, we had $93.7 million of borrowings under our existing credit facility. This amount does not include $8.8 million of letters of credit that were outstanding under our existing credit facility as of March 19, 2010.
 
(2) Does not include $           million in outstanding letters of credit that will be issued under our new credit facility.


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DILUTION
 
Dilution is the amount by which the offering price will exceed the net tangible book value per unit after the offering. Assuming an initial public offering price of $      per common unit, on a pro forma basis as of December 31, 2009, after giving effect to our entry into our new credit facility and repayment of all outstanding indebtedness under our existing credit facility, the issuance and sale of           common units, the other transactions described in “Summary — The Transactions” and the application of the net proceeds from this offering in the manner described in “Use of Proceeds,” our net tangible book value was approximately $      million, or $      per common unit. The pro forma tangible net book value excludes $      million of deferred financing costs. Purchasers of common units in this offering will experience substantial and immediate 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
      $     
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 net tangible book value per common unit to purchasers in the offering(3)
      $
         
 
 
(1) Determined by dividing the net tangible book value of the contributed assets and liabilities by the number of units (          common units,          subordinated units and the 2.0% general partner interest represented by           general partner units) held by our general partner and its affiliates and the participants under our LTIP.
 
(2) Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds from this offering, by the total number of units (          common units,          subordinated units and the 2.0% general partner interest represented by          general partner units) to be outstanding after this offering.
 
(3) If the initial public offering price were to increase or decrease by $1.00 per common unit, immediate dilution in net tangible book value per common unit would increase or decrease by $1.00.
 
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 the participants under our LTIP in respect of their units 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 millions)  
 
General Partner and its affiliates(1)
  $                   %   $                   %
New Investors
            %             %
                                 
Total
  $         100.0 %   $         100.0 %
                                 
 
 
(1) Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates, and the participants under our LTIP, will own           common units,          subordinated units and a 2.0% general partner interest represented by          general partner units.


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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
 
You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and regarding certain risks inherent in our business.
 
For additional information regarding our historical results of operations, you should refer to our historical audited consolidated financial statements as of and for the years ended December 31, 2007, 2008 and 2009 included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy
 
Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is generally defined to mean, for each quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax.
 
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
 
There is no guarantee that we will distribute quarterly cash distributions to our unitholders. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:
 
  •     Our cash distribution policy will be subject to restrictions on cash distributions under our new credit facility. Specifically, we expect our new credit facility to contain financial tests and covenants that we must satisfy before quarterly cash distributions can be paid. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility.” Should we be unable to satisfy these restrictions included in our new credit facility or if we are otherwise in default under our new credit facility, we would be prohibited from making cash distributions 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.
 
  •     While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, after the subordination period has ended our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by C&T Coal and AIM Oxford). At the closing of this offering, C&T Coal and AIM Oxford will own our general partner, approximately     % of our outstanding common units and all of our outstanding subordinated units. Please read “The Partnership Agreement — Amendment of Our Partnership Agreement.”


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  •     Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
 
  •     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 reduced revenues from sales of our products and services or increases in our operating costs, SG&A expenses, principal and interest payments on our outstanding debt and working capital requirements.
 
  •     If we make distributions out of capital surplus, as opposed to operating surplus, such distributions will constitute a return of capital and will result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read “How We Make Cash Distributions — Distributions from Capital Surplus.” 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, including cash distributions from Harrison Resources, which requires the approval of the noncontrolling interest holder. 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.
 
While we believe, based on our financial forecast and related assumptions, that we will have sufficient cash to enable us to pay the full minimum quarterly distribution on all of our common units and subordinated units for the twelve months ending June 30, 2011, our cash available for distribution generated during the year ended December 31, 2009 would have been sufficient to allow us to pay     % and     % of the minimum quarterly distribution ($      per unit per quarter, or $      on an annualized basis) on our common units and subordinated units, respectively. This represents     % of the total distributions payable to all of our unitholders and our general partner.
 
Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital
 
We will distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any future expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow our asset base. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. To the extent we issue additional units, 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, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement, and we do not anticipate there being any limitations in our new credit facility, 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.
 
Minimum Quarterly Distribution Rate
 
Upon the consummation of this offering, the board of directors of our general partner intends to establish a minimum quarterly distribution of $      per unit for each complete quarter, or $      per unit on an annualized basis, to be paid within 45 days after the end of each quarter. We will adjust our first distribution for the period from the closing of this offering through          , 2010 based on the actual length of the period. Our ability to make cash distributions at the established minimum quarterly distribution rate pursuant to our cash distribution policy will be subject to the factors described above under “— General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” The amount of available cash


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needed to pay the minimum quarterly distribution on all of the common units, subordinated units and general partner units to be outstanding immediately after this offering for one quarter and for four quarters is summarized in the table below:
 
                         
    Number of Units     One Quarter     Four Quarters  
 
Common units
                                   
Subordinated units
                       
General partner units
                       
                         
Total
                       
                         
 
As of the date of this offering, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48%, of the cash we distribute in excess of $      per unit per quarter.
 
During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “How We Make Cash Distributions — Subordination Period.” We cannot guarantee, however, that we will pay the minimum quarterly distribution on the common units in any quarter.
 
We do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is generally defined to mean, for each quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters.
 
Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interest. Please read “Conflicts of Interest and Fiduciary Duties.”
 
Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.
 
We will pay our distributions on or about the 15th day of each of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through          , 2010 based on the actual length of the period.
 
Historical and Forecasted Results of Operations and Cash Available for Distribution
 
In this section, we present in detail the basis for our belief that we will be able to pay the minimum quarterly distribution on all of our common units and subordinated units and make the related distribution on our general partner’s 2.0% general partner interest for the twelve months ending June 30, 2011. We present a


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table below, consisting of historical and forecasted results of operations and cash available for distribution for the year ended December 31, 2009 and the twelve months ending June 30, 2011, respectively. In the table, we show our historical results of operations and the amount of cash available for distribution we would have had for the year ended December 31, 2009 based on our historical consolidated statement of operations included elsewhere in this prospectus and our forecasted results of operations and the forecasted amount of cash available for distribution for the twelve months ending June 30, 2011 and the significant assumptions upon which this forecast is based.
 
Our historical consolidated financial statements and the notes to those statements included elsewhere in this prospectus should be read together with “Selected Historical and Pro Forma Consolidated Financial and Operating Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.
 
Historical cash available for distribution generated during the year ended December 31, 2009 would have been approximately $      million. This amount would have been sufficient to pay     % and     % of the minimum quarterly distribution ($      per quarter, or $      on an annualized basis) on our common units and subordinated units, respectively. This represents     % of the total distributions payable to all of our unitholders and our general partner.
 
The following table also sets forth our calculation of forecasted cash available for distribution to our unitholders and our general partner for the twelve months ending June 30, 2011. We forecast that our cash available for distribution generated during the twelve months ending June 30, 2011 will be approximately $      million. This amount would be sufficient to pay the full minimum quarterly distribution of $      per unit on all of our common units and subordinated units and the related distribution on our general partner’s 2.0% general partner interest for each quarter in the twelve months ending June 30, 2011.
 
We are providing the financial forecast to supplement our historical consolidated financial statements in support of our belief that we will have sufficient cash available to allow us to pay cash distributions on all of our outstanding common units and subordinated units and the related distributions on our general partner’s 2.0% general partner interest for the twelve months ending June 30, 2011 at the minimum quarterly distribution rate. Please read “— Significant Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” for information as to the accounting policies we have followed for the financial forecast.
 
Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2011. 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 quarterly distributions on our common units and subordinated units at the minimum quarterly distribution rate of $      per unit (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 forecast set forth below to present the estimated 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


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action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the forecast.
 
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 intend to update or otherwise revise the forecast to reflect circumstances existing since its preparation or to reflect the occurrence of unanticipated events, even if any or all of the underlying assumptions are shown to be in error. Furthermore, we do not intend to update or revise the forecast to reflect changes in general economic or industry conditions.


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Oxford Resource Partners, LP
Cash Available for Distribution
 
                 
    Historical     Forecasted(1)  
    Year Ended
    Twelve Months
 
    December 31, 2009     Ending June 30, 2011  
    (in thousands, except per unit and
 
    per ton amounts)  
 
Operating data:
               
Coal produced in tons
    5,846       8,079  
Coal purchased in tons
    530       730  
                 
Coal available for sale in tons
    6,376       8,809  
                 
Coal sold in tons
    6,311       8,789  
Increase in coal inventory in tons
    65       20  
Coal sales in tons — sold/committed(2)
    6,311       8,121  
Coal sales in tons — uncommitted
    n/a       668  
Average sales price per ton — sold/committed(2)
  $ 40.27     $ 37.87  
Average sales price per ton — uncommitted
    n/a     $ 40.32  
Selected financial data:
               
Coal sales revenue — sold/committed(2)
  $ 254,171     $ 307,638  
Coal sales revenue — uncommitted
    n/a       26,934  
Transportation revenue
    32,490       44,894  
Royalty and non-coal revenue(3)
    7,183       9,478  
                 
Total revenues
    293,844       388,944  
Costs and expenses:
               
Cost of coal sales (excluding DD&A, shown separately)
    170,698       226,382  
Cost of purchased coal
    19,487       23,379  
Cost of transportation
    32,490       44,894  
Depreciation, depletion and amortization
    25,902       37,365  
Selling, general and administrative expenses(4)
    13,242       14,703  
                 
Total costs and expenses
    261,819       346,723  
                 
Income from operations
    32,025       42,221  
Interest income
    35       15  
Interest expense
    (6,484 )     (7,093 )
Gain from purchase of business(5)
    3,823        
                 
Net income
    29,399       35,143  
Less: income attributable to noncontrolling interest
    (5,895 )     (7,531 )
                 
Net income attributable to Oxford Resource Partners, LP unitholders
  $ 23,504     $ 27,612  
                 
Plus:
               
Depreciation, depletion and amortization
    25,902       37,365  
Interest expense
    6,484       7,093  
Non-cash equity compensation expense
    472       433  
Less:
               
Interest Income
    35       15  
Gain from purchase of business(5)
    3,823        
Amortization of below-market coal sales contracts
    1,705       2,132  
                 
Adjusted EBITDA(6)
  $ 50,799     $ 70,356  
Less:
               
Cash interest expense, net of interest income
    5,970       6,221  
Maintenance capital expenditures(7)
    27,461       32,269  
                 
Cash available for distribution
  $ 17,368     $ 31,866  
                 
Implied cash distributions at the minimum quarterly distribution rate:
               
Annualized minimum quarterly distribution per unit
               
Distributions to public common unitholders
               
Distributions to participants in LTIP
               
Distributions to C&T Coal and AIM Oxford — common units
               
Distributions to C&T Coal and AIM Oxford — subordinated units
               
Distributions to general partner
               
                 
Total distributions to unitholders and general partner(8)
               
                 
Excess (shortfall)
               
                 
 
 
(1) The forecasted column is based on the assumptions set forth in “— Significant Forecast Assumptions” below.


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(2) Represents coal sold for 2009 on a historical basis and coal committed for sale for the twelve months ending June 30, 2011. The forecast period amount includes 0.2 million tons that are subject to a price re-opener under a long-term coal sales contract.
 
(3) Consists of royalty payments we receive on our underground coal reserves as well as limestone sales, barge loading fees and other revenue.
 
(4) Historical SG&A expenses for the year ended December 31, 2009 include one-time expenses of $1.6 million associated with the Phoenix Coal acquisition and $1.0 million of legal fees incurred in renegotiating our existing credit facility, but do not include incremental SG&A expenses of approximately $3.0 million that we expect to incur as a result of being a publicly traded partnership. However, forecasted SG&A expenses for the twelve months ended June 30, 2011 include such incremental SG&A expenses.
 
(5) On September 30, 2009, we acquired all of the active surfacing mining operations of Phoenix Coal. The purchase price of this acquisition was less than the fair value of the net assets and liabilities we acquired. We recorded this difference as a gain of $3.8 million for the year ending December 31, 2009.
 
(6) This table presents a reconciliation of Adjusted EBITDA to net income (loss) attributable to our unitholders for each of the periods indicated. Adjusted EBITDA is a non-GAAP financial measure, which we use in our business as it is an important supplemental measure of our performance. Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, depreciation, depletion and amortization, gain from purchase of a business, amortization of below-market coal sales contracts and non-cash equity compensation expense. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.
 
Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and lenders, to assess:
 
  •     our financial performance without regard to financing methods, capital structure or income taxes;
 
  •     our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our unitholders and our general partner;
 
  •     our compliance with certain financial covenants applicable to our credit facility; and
 
  •     our ability to fund capital expenditure projects from operating cash flows.
 
Adjusted EBITDA should not be considered an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income (loss) attributable to our unitholders, income from operations and cash flows, and these measures may vary among other companies. Therefore, Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.
 
(7) Historically we have not made a distinction between maintenance capital expenditures and other capital expenditures. For purposes of this presentation, however, we have evaluated our 2009 capital expenditures to determine which of them would have been classified as maintenance capital expenditures in accordance with our partnership agreement at the time they were made. Based on this evaluation, we estimate that our maintenance capital expenditures for the year ended December 31, 2009 would have been $27.5 million. The amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders, if we subtracted actual maintenance capital expenditures from operating surplus. To eliminate these fluctuations, our partnership agreement will require that an estimate of the maintenance capital expenditures necessary to maintain our asset base be subtracted from operating surplus each quarter as opposed to amounts actually spent on maintenance capital expenditures. The $32.3 million of maintenance capital expenditures for the forecasted twelve months ending June 30, 2011 represents estimated maintenance capital expenditures as defined in our partnership agreement. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change must be approved by the Conflicts Committee. We expect our actual maintenance capital expenditures during the forecast period to be consistent with our estimated maintenance capital expenditures for that period. We have not included any expansion capital expenditures in the forecast period. To the extent we incur such expenditures during the forecast period, we expect to fund those with borrowings under our new credit facility, issuance of debt and equity securities or other external sources of financings. Please read “How We Make Cash Distributions — Operating Surplus and Capital Surplus — Definition of Operating Surplus” for a further discussion of the effects of our use of estimated maintenance capital expenditures.
 
(8) Represents the amount that would be required to pay distributions for four quarters at our minimum quarterly distribution rate of $      per unit on all of the common and subordinated units that will be outstanding immediately following this offering and the related distributions on our general partner’s 2.0% general partner interest.


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Significant Forecast Assumptions
 
The forecast has been prepared by and is the responsibility of management. Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2011. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed below are those that we believe are significant to our forecasted results of operations. We believe we have a reasonable objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and the actual results and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the minimum quarterly distribution rate or at all.
 
Production and Revenues.  We forecast that our total revenues for the twelve months ending June 30, 2011 will be approximately $389.0 million, as compared to approximately $293.8 million for 2009. Our forecast of total revenues is based primarily on the following assumptions:
 
  •     We estimate that we will produce approximately 8.1 million tons of coal during the twelve months ending June 30, 2011, as compared to approximately 5.8 million tons we produced in 2009. This estimated volume increase is primarily due to additional coal production from our Muhlenberg County mining complex that we acquired in the Phoenix Coal acquisition, as a result of a full year of production from these properties being reflected in the forecast period as well as our deployment of larger equipment and implementation of more efficient mining practices at that complex. We expect to produce an aggregate of approximately 2.1 million tons of coal from our Muhlenberg County mining complex in the forecast period compared to 0.4 million tons of coal during the fourth quarter of 2009 (or 1.6 million tons on an annualized basis). We expect that our coal production during the forecast period from our other mining complexes will increase slightly compared to 2009.
 
  •     We estimate that we will sell approximately 8.8 million tons of coal during the twelve months ending June 30, 2011, as compared to approximately 6.3 million tons we sold in 2009. We have committed to sell approximately 8.1 million tons, of which 7.9 million tons are priced and 0.2 million tons are subject to price re-openers under a long-term coal sales contract. As described below, we expect to purchase approximately 0.7 million tons to balance our estimated sales volumes. Our estimates assume that we will be successful in repricing these 0.2 million tons at slightly higher prices. Our estimates also assume that our customers with options to take delivery of additional tons during the forecast period will not exercise their options.
 
  •     We estimate that the average sales price per ton for committed tons will be $37.87 for the twelve months ending June 30, 2011, as compared to $40.27 for 2009. This estimate takes into account prices in our long-term contracts, including our estimate of the amount of applicable cost pass through or inflation adjustment provisions, and gives effect to the full year impact of the lower priced coal sales contracts that we assumed in connection with the Phoenix Coal acquisition, and the expiration of a short-term supplemental price increase that took effect in 2009 in connection with the amendment of a long-term coal sales contract.
 
  •     We estimate that the average sales price per ton for uncommitted tons will be $40.32 for the twelve months ending June 30, 2011. Our estimated average sales price for these tons assumes that we will be successful in selling those uncommitted tons at prices that reflect management’s current estimates of market conditions and pricing trends.
 
  •     We estimate that our royalty and non-coal revenue, which consists of royalty payments received on our underground coal reserves as well as limestone sales, barge loading fees and other sources of revenue, will be $9.5 million for the twelve months ending June 30, 2011, as compared to $7.2 million for 2009. This increase is primarily due to increased barge-loading fees under a new contract at our Island river terminal in western Kentucky. We have assumed that the overriding royalty payments on our underground coal reserves and all other non-coal revenues during the forecast period will slightly increase compared to the amounts we received in 2009.


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Purchased Coal.  We estimate that we will purchase approximately 0.7 million tons of coal from third parties for the twelve months ending June 30, 2011, as compared to approximately 0.5 million tons we purchased in 2009. This increase is primarily due to the full year impact of a long-term coal purchase contract that we assumed in connection with the Phoenix Coal acquisition under which we purchase approximately 0.4 million tons annually.
 
Cost of Coal Sales.  We estimate that our cost of coal sales will be $226.4 million for the twelve months ending June 30, 2011, as compared to $170.7 million for 2009. The increase in cost of coal sales for the forecast period as compared to 2009 is primarily attributable to increased coal production, partially offset by a decrease in our cost of coal sales per ton. We estimate that our cost of coal sales per ton for the twelve months ending June 30, 2011 will be $28.02, as compared to $29.20 for 2009. This decrease is attributable to a projected decrease in diesel fuel and explosives costs on a per ton basis, partially offset by higher non-commodity-related operating costs on a per ton basis due to the Phoenix Coal acquisition.
 
Cost of Purchased Coal.  We forecast our cost of purchased coal will be $23.4 million for the twelve months ending June 30, 2011, as compared to $19.5 million for 2009. This increase is primarily attributable to more tons of coal being purchased in the forecast period as compared to 2009, partially offset by a decrease in the cost per ton of purchased coal. We estimate that the cost per ton of purchased coal will be $32.02 for the twelve months ending June 30, 2011, as compared to $36.79 for 2009. During the first quarter of 2009, we bought a higher percentage of our purchased coal on the spot market in order to meet our coal sales obligations. Since that time, due to a long-term coal purchase contract under which we purchase approximately 0.4 million tons annually, our need for spot market purchases has declined.
 
Depreciation, Depletion and Amortization.  We forecast depreciation, depletion and amortization expense to be approximately $37.4 million for the twelve months ending June 30, 2011, as compared to approximately $25.9 million for 2009. This increase is primarily due to the full year impact of the Phoenix Coal acquisition.
 
Selling, General and Administrative Expenses.  We forecast SG&A expenses to be approximately $14.7 million for the twelve months ending June 30, 2011, as compared to approximately $13.2 million for 2009. This increase is primarily attributable to $3.0 million in incremental SG&A expenses that we expect to incur as a result of being a publicly traded partnership, partially offset by a decrease in acquisition costs and legal fees, which were higher in 2009 due to the one-time costs of the Phoenix Coal acquisition and fees incurred in renegotiating our existing credit facility.
 
Harrison Resources Distributions.  We estimate that the aggregate cash distributions we will receive from Harrison Resources for the twelve months ending June 30, 2011 will be $7.5 million as compared to $6.3 million in 2009. In the forecast period, we have assumed that the cash distributions we will receive from Harrison Resources will constitute substantially all of our Adjusted EBITDA attributable to Harrison Resources. This assumption is consistent with the distributions we received from, and the portion of our Adjusted EBITDA attributable to, Harrison Resources in 2009.
 
Financing.  We forecast interest expense of approximately $7.1 million for the twelve months ending June 30, 2011, as compared to approximately $6.5 million for 2009. Our interest expense for the twelve months ending June 30, 2011 is based on the following assumptions:
 
  •     we will repay in full the outstanding borrowings of $      under our existing credit facility with a portion of the proceeds from the offering;
 
  •     we will borrow approximately $      million under our new credit facility;
 
  •     for calculating our interest expense, we have assumed a weighted average interest rate over the forecast period of 5.0% under our new credit facility, which is lower than the weighted average interest rate for 2009 under our existing credit facility; and
 
  •     we will maintain a low cash balance.


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Capital Expenditures.  We forecast capital expenditures for the twelve months ending June 30, 2011 based on the following assumptions:
 
  •     Our estimated maintenance capital expenditures for the forecast period are $32.3 million for the twelve months ending June 30, 2011, as compared to approximately $27.5 million of actual maintenance capital expenditures for 2009. This increase is primarily due to a larger asset base, including replacement of reserves, following the Phoenix Coal acquisition. We expect to fund maintenance capital expenditures from cash generated by our operations and from borrowings under our new credit facility.
 
  •     We have not included any expansion capital expenditures in our forecast for the twelve months ending June 30, 2011. Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements, which are (i) any addition or improvement to our capital assets, (ii) the acquisition of existing, or the construction of new, capital assets (including coal mines and related assets), or (iii) capital contributions to an entity in which we own an equity interest for our pro rata share of the cost of acquisitions of existing, or the construction of new, capital assets by such entity, in each case if such addition, improvement, acquisition or construction is made to increase our long-term operating capacity, asset base or operating income. 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 expenditures are expected to expand our long-term operating capacity, asset base or operating income. We had approximately $23.7 million of actual capital expenditures for 2009 that we would have classified as expansion capital expenditures if we had distinguished between expansion capital expenditures and other capital expenditures during that period. Of the $23.7 million, approximately $18.3 million was attributable to the Phoenix Coal acquisition and approximately $5.4 million was attributable to the purchase of other additional coal reserves.
 
Regulatory, Industry and Economic Factors.  We forecast for the twelve months ending June 30, 2011 based on the following assumptions related to regulatory, industry and economic factors:
 
  •     no material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor;
 
  •     all supplies and commodities necessary for production and sufficient transportation will be readily available;
 
  •     no new federal, state or local regulation of the portions of the mining industry in which we operate or any interpretation of existing regulation that in either case will be materially adverse to our business;
 
  •     no material unforeseen geologic conditions or equipment problems at our mining locations;
 
  •     no material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events;
 
  •     no major adverse change in the coal markets in which we operate resulting from supply or production disruptions, reduced demand for our coal or significant changes in the market prices of coal; and
 
  •     no material changes in market, regulatory or overall economic conditions.


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HOW WE MAKE CASH DISTRIBUTIONS
 
Distributions of Available Cash
 
General
 
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through          , 2010 based on the actual length of the period.
 
Definition of Available Cash
 
Available cash generally means, for any quarter, all cash on hand at the end of the quarter:
 
  •     less the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:
 
  •     provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future credit needs subsequent to that quarter);
 
  •     comply with applicable law, any of our debt instruments or other agreements; and
 
  •     provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
 
  •     plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter.
 
Intent to Distribute the Minimum Quarterly Distribution
 
We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $      per unit, or $      on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility” for a discussion of the restrictions to be included in our new credit facility that may restrict Oxford Mining Company’s ability to make distributions to us.
 
General Partner Interest and Incentive Distribution Rights
 
As of the date of this offering, our general partner is entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. This general partner interest will be represented by           general partner units upon the completion of this offering. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner’s initial 2.0% interest in our distributions may be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.
 
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $      per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our


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general partner may receive on common units or subordinated units that it owns. Please read “— General Partner Interest and Incentive Distribution Rights” for additional information.
 
Operating Surplus and Capital Surplus
 
Overview
 
All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.
 
Definition of 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); 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 prior to the date of determination of available cash to provide funds for future operating expenditures.
 
As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $      million of 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.
 
We define interim capital transactions as (i) borrowings, (ii) sales of equity and debt securities, (iii) sales or other dispositions of assets outside the ordinary course of business, (iv) capital contributions received, (v) corporate reorganizations or restructurings and (vi) the termination of interest rate hedge contracts or commodity hedge contracts prior to the termination date specified therein (provided that cash receipts from any such termination will be included in operating surplus in equal quarterly installments over the remaining scheduled life of such contract).
 
We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses to our general partner, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts, estimated maintenance capital expenditures (as discussed in further detail below) and non-pro rata repurchases of units (other than those made with the proceeds of an interim capital transaction), provided that operating expenditures will not include:
 
  •     payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness;
 
  •     expansion capital expenditures;
 
  •     actual maintenance capital expenditures;
 
  •     payment of transaction expenses (including taxes) relating to interim capital transactions; or
 
  •     distributions to partners.
 
Capital Expenditures
 
Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to our capital assets) made to maintain or replace, including over the long term, our operating capacity, asset base or operating income. Examples of maintenance capital expenditures include capital


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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 operating capacity, asset base or operating income. Maintenance capital expenditures will also include reclamation expenses.
 
Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus.
 
Our partnership agreement requires that an estimate of the average quarterly maintenance capital expenditures necessary over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and change by our general partner at least once a year. The estimate will be made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures on a long-term basis, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus (other than when used to determine whether the subordination period has ended), any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash Distribution Policy and Restrictions on Distributions.”
 
The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:
 
  •     it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the initial quarterly distribution to be paid on all the units for the quarter and subsequent quarters;
 
  •     it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;
 
  •     it will 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; and
 
  •     it will reduce the likelihood that a large maintenance capital expenditure in a period will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.
 
Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements, which are (i) any addition or improvement to our capital assets, (ii) the acquisition of existing, or the construction of new, capital assets (including coal mines and related assets), or (iii) capital contributions to an entity in which we own an equity interest for our pro rata share of the cost of acquisitions of existing, or the construction of new, capital assets by such entity, in each case if such addition, improvement, acquisition or construction is made to increase our long-term operating capacity, asset base or operating income. 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, asset base or operating income. Expansion capital expenditures are not subtracted from operating surplus.
 
Subordination Period
 
General
 
Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash 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 of available cash from operating surplus may


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be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
 
Definition of Subordination Period
 
The subordination period will begin upon the date of this offering and will extend until the first business day of any quarter beginning after June 30, 2013 that each of the following tests are met:
 
  •     distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •     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 distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis during those periods; and
 
  •     there are no arrearages in payment of the minimum quarterly distribution on the common units.
 
For purposes of determining whether sufficient adjusted operating surplus has been generated under the above conversion test, the Conflicts Committee may adjust operating surplus upwards or downwards if it determines in good faith that the amount of estimated maintenance capital expenditures used in the determination of adjusted operating surplus was materially incorrect, based on the circumstances prevailing at the time of the original estimate, for any one or more of the preceding two four-quarter periods.
 
Early Termination of Subordination Period
 
Notwithstanding the foregoing, the subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs:
 
  •     distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $      per quarter (150.0% of the minimum quarterly distribution) for each calendar quarter in the immediately preceding four-quarter period;
 
  •     the “adjusted operating surplus” (as defined below) generated during each calendar quarter in the immediately preceding four-quarter period equaled or exceeded the sum of $      (150.0% of the minimum quarterly distribution) on each of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis; and
 
  •     there are no arrearages in payment of the minimum quarterly distributions on the common units.
 
Expiration of the Subordination Period
 
When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will participate pro-rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:
 
  •     the subordination period will end and each subordinated unit will immediately convert into one common unit;
 
  •     any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and


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  •     our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
 
Definition of Adjusted Operating Surplus
 
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:
 
  •     operating surplus generated 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 made in subsequent periods to 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; 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.
 
Distributions of Available Cash from Operating Surplus during the Subordination Period
 
We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
 
  •     first, 98% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
  •     second, 98% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
 
  •     third, 98% to the subordinated unitholders, pro rata, and 2.0% to our general partner, 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.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
Distributions of Available Cash from Operating Surplus after the Subordination Period
 
We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
 
  •     first, 98% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding 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.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.


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General Partner Interest and Incentive Distribution Rights
 
Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.
 
Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.
 
The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.
 
If for any quarter:
 
  •     we have distributed available cash from operating surplus to the unitholders in an amount equal to the minimum quarterly distribution; and
 
  •     we have distributed available cash from operating surplus on outstanding common units and the general partner interest in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution to the common unitholders;
 
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:
 
  •     first, 98% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $      per unit for that quarter (the “first target distribution”);
 
  •     second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $      per unit for that quarter (the “second target distribution”);
 
  •     third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $      per unit for that quarter (the “third target distribution”); and
 
  •     thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
 
Percentage Allocations of Available Cash from Operating Surplus
 
The following table illustrates the percentage allocations of available cash 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 available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” 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. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that there are no arrearages on common units, our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and our general partner has not transferred its incentive distribution rights.
 


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              Marginal Percentage Interest
 
    Total Quarterly Distribution
  in Distributions  
    Per Unit Target Amount   Unitholders     General Partner  
 
Minimum Quarterly Distribution
                 $          98 %     2 %
First Target Distribution
          up to $          98 %     2 %
Second Target Distribution
  above $       up to $          85 %     15 %
Third Target Distribution
  above $     up to $          75 %     25 %
Thereafter
          above $          50 %     50 %
 
General Partner’s Right to Reset Incentive Distribution Levels
 
Our general partner, as the 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 cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions 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 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 minimum quarterly distribution amount and 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 and general partner units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.
 
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 average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of that two-quarter period.
 
Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters 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 distribute all of our available cash from operating surplus for each quarter thereafter as follows:
 
  •     first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;

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  •     second, 85.0% to all 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 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 unitholders, pro rata, and 50.0% to our general partner.
 
The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $     .
 
                                                 
            Marginal Percentage
           
    Quarterly Distribution
  Interest in Distributions   Quarterly Distribution Per Unit
    Per Unit Prior to Reset   Unitholders   General Partner   Following Hypothetical Reset
 
Minimum Quarterly Distribution
            $        98%     2 %                  $          
First Target Distribution
          up to $        98%     2 %             up to     $       (1 )
Second Target Distribution
  above $           up to $        85%     15 %   above $             (1) up to     $       (2 )
Third Target Distribution
  above $           up to $        75%     25 %   above $             (2) up to     $       (3 )
Thereafter
          above $        50%     50 %             above     $       (3 )
 
 
(1) This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
 
(2) This amount is 125.0% of the hypothetical reset minimum quarterly distribution.
 
(3) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.
 
The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be           common units outstanding, our general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit would be $      for the two quarters prior to the reset.
 
                                                             
          Cash
    Cash Distributions to General Partner Prior to Reset  
          Distributions to
          2.0%
                   
    Quarterly
    Common
          General
    Incentive
             
    Distribution Per
    Unitholders
    Class C
    Partner
    Distribution
          Total
 
    Unit Prior to Reset     Prior to Reset     Units     Interest     Rights     Total     Distributions  
 
Minimum Quarterly Distribution
           $       $           $           $           $           $           $        
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 available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of IDRs, 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, our general partner’s 2.0% interest has been maintained, and the average 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 (i) the average of the amounts received by our general partner in respect of its IDRs for the two quarters prior to the reset as shown in the table above, or $     ; by (ii) the average


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available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $      .
 
                                                             
        Cash
    Cash Distributions to General Partner After Reset  
        Distributions to
          2.0%
                   
        Common
          General
    Incentive
             
    Quarterly Distribution
  Unitholders
    Class C
    Partner
    Distribution
          Total
 
    Per Unit After Reset   After Reset     Units     Interest     Rights     Total     Distributions  
 
Minimum Quarterly Distribution
                 $        $             $           $           $           $           $        
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 minimum quarterly distribution amount and 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
 
We will make distributions of available cash from capital surplus, if any, in the following manner:
 
  •     first, 98% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;
 
  •     second, 98% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the outstanding common units; and
 
  •     thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
Effect of a Distribution from Capital Surplus
 
Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, 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 unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
 
Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the unitholders, pro rata, and 50% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.


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Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
 
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:
 
  •     the minimum quarterly distribution;
 
  •     the number of common units into which a subordinated unit is convertible;
 
  •     target distribution levels; and
 
  •     the unrecovered initial unit price.
 
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% of its initial level, and each subordinated unit would be convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.
 
In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.
 
Distributions of Cash Upon Liquidation
 
General
 
If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, 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 outstanding common units to a preference over the holders of outstanding 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 holders of common units 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 our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:
 
  •     first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;


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  •     second, 98% to the common unitholders, pro rata, and 2.0% to our general partner, 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, 98% to the subordinated unitholders, pro rata, and 2.0% to our general partner, 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, 98% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to:
 
(1) the sum of the excess of the 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 available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;
 
  •     fifth, 85% to all unitholders, pro rata, and 15% 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 available cash from operating surplus in excess of the first target distribution per unit that we distributed 96% to the unitholders, pro rata, and 4% to our general partner for each quarter of our existence;
 
  •     sixth, 75% to all unitholders, pro rata, and 25% 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 available cash from operating surplus in excess of the second target distribution per unit that we distributed 94% to the unitholders, pro rata, and 6% to our general partner for each quarter of our existence;
 
  •     thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
 
The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.


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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 unitholders in the following manner:
 
  •     first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
 
  •     second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and
 
  •     thereafter, 100% to our general partner.
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
 
Adjustments to Capital Accounts
 
We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will 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 our general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.


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SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED
FINANCIAL AND OPERATING DATA
 
The following table presents our selected historical consolidated financial and operating data, as well as that of our accounting predecessor and wholly owned subsidiary, Oxford Mining Company, as of the dates and for the periods indicated. The following table also presents our selected pro forma consolidated financial and operating data as of the dates and for the periods indicated.
 
The selected financial data for the year ended December 31, 2005 are derived from the audited historical consolidated balance sheet of Oxford Mining Company that is not included in this prospectus. The selected historical consolidated financial data presented as of and for the year ended December 31, 2006 are derived from the audited historical consolidated financial statements of Oxford Mining Company that are not included in this prospectus. The selected historical consolidated financial data presented for the period from January 1, 2007 to August 23, 2007 are derived from the audited historical consolidated financial statements of Oxford Mining Company that are included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2007 for the period from August 24, 2007 to December 31, 2007 and as of and for the years ended December 31, 2008 and 2009 are derived from our audited historical consolidated financial statements that are included elsewhere in this prospectus.
 
The selected pro forma consolidated financial data presented as of and for the year ended December 31, 2009 are derived from our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma consolidated statement of operations and consolidated balance sheet give pro forma effect to this offering and the transactions related to this offering described in “Summary — The Transactions” and “Use of Proceeds.” The unaudited pro forma consolidated statement of operations also gives pro forma effect to the Phoenix Coal acquisition. The unaudited pro forma consolidated balance sheet assumes this offering and the transactions related to this offering occurred as of December 31, 2009. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2009 assumes the Phoenix Coal acquisition, this offering and the transactions related to this offering occurred as of January 1, 2009. We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $3.0 million that we expect to incur as a result of being a publicly traded partnership.
 
For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Summary — The Transactions,” “Use of Proceeds,” “Business — Our History,” the historical consolidated financial statements of Oxford Mining Company and our unaudited pro forma consolidated financial statements and audited consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.
 
The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business as it is an important supplemental measure of our performance. Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, depreciation, depletion and amortization, gain from purchase of a business, amortization of below-market coal sales contracts and non-cash equity compensation expense. This measure is not calculated or presented in accordance with GAAP. We explain this


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measure below and reconcile it to net income (loss) attributable to our unitholders, its most directly comparable financial measure calculated and presented in accordance with GAAP.
 
                                                                       
      Oxford Mining Company
                 
      (Predecessor)       Oxford Resource Partners, LP       Pro Forma
 
                      Period from
      Period from
                      Oxford Resource
 
                      January 1,
      August 24,
                      Partners, LP  
      Year Ended
      Year Ended
      2007 to
      2007 to
      Year Ended
      Year Ended
      Year Ended
 
      December 31,
      December 31,
      August 23,
      December 31,
      December 31,
      December 
      December 31,
 
      2005       2006       2007       2007       2008       31, 2009       2009  
                                                      (unaudited)  
      (in thousands, except per ton amounts)  
Statement of Operations Data:
                                                                     
Revenues:
                                                                     
Coal sales
              $ 141,440       $ 96,799       $ 61,324       $ 193,699       $ 254,171       $ 312,490  
Transportation revenue
                27,771         18,083         10,204         31,839         32,490         37,221  
Royalty and non-coal revenue
                6,643         3,267         1,407         4,951         7,183         7,183  
                                                                       
Total revenues
                175,854         118,149         72,935         230,489         293,844         356,894  
Costs and expenses:
                                                                     
Cost of coal sales (excluding DD&A, shown separately)
                106,657         70,415         40,721         151,421         170,698         213,446  
Cost of purchased coal
                22,159         17,494         9,468         12,925         19,487         29,792  
Cost of transportation
                27,771         18,083         10,204         31,839         32,490         37,221  
Depreciation, depletion, and amortization
                12,396         9,025         4,926         16,660         25,902         31,424  
Selling, general and administrative expenses
                2,097         3,643         2,114         9,577         13,242         25,735  
                                                                       
Total costs and expenses
                171,080         118,660         67,433         222,422         261,819         337.618  
                                                                       
Income (loss) from operations
                4,774         (511 )       5,502         8,067         32,025         19,276  
Interest income
                30         26         55         62         35         39  
Interest expense
                (3,672 )       (2,386 )       (3,498 )       (7,720 )       (6,484 )       (6,341 )
Gain from purchase of business(1)
                                                3,823         3,823  
                                                                       
Net income (loss)
                1,132         (2,871 )       2,059         409         29,399         16,797  
Less: Net income attributable to noncontrolling interest
                        (682 )       (537 )       (2,891 )       (5,895 )       (5,895 )
                                                                       
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
              $ 1,132       $ (3,553 )     $ 1,522       $ (2,482 )     $ 23,504       $ 10,902  
                                                                       
Statement of Cash Flows Data:
                                                                     
Net cash provided by (used in):
                                                                     
Operating activities
              $ 16,236       $ 17,634       $ (8,478 )     $ 33,951       $ 35,540            
Investing activities
                (13,547 )       (16,619 )       (103,336 )       (23,901 )       (51,115 )          
Financing activities
                (2,548 )       (234 )       111,274         4,494         3,762            
Other Financial Data:
                                                                     
Adjusted EBITDA(2)
              $ 17,170       $ 7,832       $ 9,145       $ 20,349       $ 50,799       $ 39,016  
Maintenance capital expenditures(3)
                11,695         13,020         4,841         21,529         27,461         27,461  
Distributions
                n/a         n/a                 12,503         13,407         n/a  
Balance Sheet Data (at period end):(4)
                                                                     
Cash and cash equivalents
    $ 252       $ 392       $ 1,175       $ 635       $ 15,179       $ 3,366       $ 30,769  
Trade accounts receivable
      21,979         16,826         18,396         17,547         21,528         24,403         2,000  
Inventory
      3,884         3,977         4,824         4,655         5,134         8,801         8,801  
PPE, net
      47,428         48,001         54,510         106,408         112,446         149,461         149,461  
Total assets
      85,099         80,533         90,893         146,774         171,297         203,363         209,726  
Total debt (current and long-term)
      46,091         43,697         43,165         75,654         83,977         95,711         98,711  
Operating Data:
                                                                     
Tons of coal produced
                3,913         2,693         1,634         5,089         5,846         7,221  
Tons of coal purchased
                962         641         305         434         530         885  
Tons of coal sold
                4,872         3,333         1,938         5,528         6,311         8,051  
Average sales price per ton(5)
              $ 29.03       $ 29.04       $ 31.64       $ 35.04       $ 40.27       $ 38.81  
Cost of coal sales per ton produced(6)
              $ 27.26       $ 26.15       $ 24.92       $ 29.75       $ 29.20       $ 29.56  
Cost of purchased coal per ton(7)
              $ 23.03       $ 27.29       $ 31.08       $ 29.81       $ 36.79       $ 33.66  
 
 
(1) On September 30, 2009, we acquired all of the active surfacing mining operations of Phoenix Coal. The purchase price of this acquisition was less than the fair value of the net assets and liabilities we acquired. We recorded this difference as a gain of $3.8 million for the year ending December 31, 2009.


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(2) Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and lenders, to assess:
 
  •  our financial performance without regard to financing methods, capital structure or income taxes;
 
  •  our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our unitholders and our general partner;
 
  •  our compliance with certain financial covenants applicable to our credit facility; and
 
  •  our ability to fund capital expenditure projects from operating cash flow.
 
    Adjusted EBITDA should not be considered an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income (loss) attributable to our unitholders, income from operations and cash flows, and these measures may vary among other companies. Therefore, Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.
 
The following table presents a reconciliation of Adjusted EBITDA to net income (loss) attributable to our unitholders for each of the periods indicated:
 
                                                     
                    Pro Forma
 
                    Oxford Resource
 
    Oxford Mining Company (Predecessor)       Oxford Resource Partners, LP       Partners, LP  
          Period from
      Period from
                     
          January 1,
      August 24,
                     
    Year Ended
    2007 to
      2007 to
    Year Ended
    Year Ended
      Year Ended
 
    December 31,
    August 23,
      December 31,
    December 31,
    December 31,
      December 31,
 
    2006     2007       2007     2008     2009       2009  
                  (in thousands)       (unaudited)  
 Reconciliation of Adjusted EBITDA to net income (loss) attributable to Oxford Resource Partners, LP unitholders:
                                                   
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ 1,132     $ (3,553 )     $ 1,522     $ (2,482 )   $ 23,504       $ 10,902  
PLUS:
                                                   
Depreciation, depletion and amortization
    12,396       9,025         4,926       16,660       25,902         31,424  
Interest expense
    3,672       2,386         3,498       7,720       6,484         6,341  
Non-cash equity compensation expense
                  25       468       472         472  
LESS:
                                                   
Interest income
    30       26         55       62       35         39  
Amortization of below-market coal sales contracts
                  771       1,955       1,705         6,261  
Gain from purchase of business
                              3,823         3,823  
                                                     
Adjusted EBITDA
  $ 17,170     $ 7,832       $ 9,145     $ 20,349     $ 50,799       $ 39,016  
                                                     
 
(3) Maintenance capital expenditures are cash expenditures made to maintain or replace, including over the long term, our operating capacity, asset base or operating income. Examples of maintenance capital expenditures include capital 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 incurred to maintain our operating capacity, asset base or operating income. Historically, we have not made a distinction between maintenance capital expenditures and other capital expenditures. For purposes of this presentation, however, we have evaluated our historical capital expenditures to estimate which of them would have been classified as maintenance capital expenditures in accordance with our partnership agreement at the time they were made. The amounts shown reflect our estimates based on that evaluation.
 
(4) The selected financial data for the year ended December 31, 2005 are derived from the audited historical consolidated balance sheet of our accounting predecessor and wholly owned subsidiary, Oxford Mining Company, that is not included in this prospectus. All other financial data for 2005 that would be comparable to the selected financial data for the years ended December 31, 2006, 2007, 2008 and 2009 is not available because we adopted new accounting


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policies in 2006 after electronic data for 2005 was purged to conserve limited electronic data resources. The manual accounting data that we retained is incomplete and we cannot prepare the comparable selected historical financial data for 2005 without unreasonable time, expense and delay. In addition, significant assumptions would be required to reclassify the operations of certain non-core businesses that we disposed of in 2005. These non-core businesses were a small percentage of our 2005 revenues. Due to the significant assumptions needed to reclassify discontinued operations, the similarity in business operations and the age of this information, we believe that the inclusion of this information would not be materially additive to an investor’s understanding of our current business.
 
(5) Represents our coal sales divided by total tons of coal sold.
 
(6) Represents our cost of coal sales (excluding DD&A) divided by the tons of coal we produce.
 
(7) Represents the cost of purchased coal divided by the tons of coal purchased.


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MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
You should read the following discussion of the financial condition and results of operations of Oxford Resource Partners, LP and its subsidiaries in conjunction with the historical consolidated financial statements of Oxford Resource Partners, LP, the historical consolidated financial statements of our accounting predecessor and wholly owned subsidiary, Oxford Mining Company, and the unaudited pro forma consolidated financial statements of Oxford Resource Partners, LP included elsewhere in this prospectus. Among other things, those historical and pro forma consolidated financial statements and the notes related to those statements include more detailed information regarding the basis of presentation for the following information.
 
Overview
 
We are a low cost producer of high value steam coal, and we are the largest producer of surface mined coal in Ohio. Our reserves and operations are strategically located in Northern Appalachia and the Illinois Basin to serve our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. We market our coal primarily to large utilities with coal-fired, base-load scrubbed power plants under long-term coal sales contracts. We currently have long-term coal sales contracts in place for 2010, 2011, 2012 and 2013 that represent 97.2%, 93.0%, 71.4% and 39.7%, respectively, of our 2010 estimated coal sales of 8.5 million tons.
 
We currently have 19 active surface mines that are managed as eight mining complexes. During the fourth quarter of 2009, our largest mine represented 12.5% of our coal production. This diversity reduces the risk that operational issues at any one mine will have a material impact on our business or our results of operations. Consistent coal quality across many of our mines and the mobility of our equipment fleet allows us to reliably serve our customers from multiple mining complexes while optimizing our mining plan. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky, that further enhance our ability to supply coal to our customers with river access from multiple mines.
 
We produced 5.8 million tons of coal during 2009, including 0.4 million tons produced from the reserves we acquired in western Kentucky from Phoenix Coal on September 30, 2009. As a result of this acquisition, our coal production during the fourth quarter of 2009 was 1.8 million tons, or 7.2 million tons on an annualized basis. During 2009, we sold 6.3 million tons of coal, including 0.5 million tons of purchased coal. We purchase coal in the open market and under contracts to satisfy a portion of our sales commitments.
 
As of December 31, 2009, we controlled 91.6 million tons of proven and probable coal reserves, of which 68.6 million tons were associated with our surface mining operations and the remaining 23.0 million tons consisted of underground coal reserves that we have subleased to a third party in exchange for an overriding royalty. Historically, we have been successful at replacing the reserves depleted by our annual production and growing our reserve base by acquiring reserves with low operational, geologic and regulatory risks and that were located near our mining operations or that otherwise had the potential to serve our primary market area. Over the last five years, we have produced 23.6 million tons of coal and acquired 52.9 million tons of proven and probable coal reserves, including 24.6 million tons of coal reserves that we acquired in connection with the Phoenix Coal acquisition.
 
For the year ended December 31, 2009, we generated revenues of approximately $293.8 million, net income attributable to our unitholders of approximately $23.5 million and Adjusted EBITDA of approximately $50.8 million. Please read “Selected Historical and Pro Forma Consolidated Financial and Operating Data” for our definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) attributable to our unitholders.
 
Evaluating Our Results of Operations
 
We evaluate our results of operations based on several key measures:
 
  •     our coal production, sales volume and average sales prices, which drive our coal sales revenue;


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  •     our cost of coal sales;
 
  •     our cost of purchased coal; and
 
  •     our Adjusted EBITDA, a non-GAAP financial measure.
 
Coal Production, Sales Volume and Sales Prices
 
We evaluate our operations based on the volume of coal we produce, the volume of coal we sell and the prices we receive for our coal. Because we sell substantially all of our coal under long-term coal sales contracts, our coal production, sales volume and sales prices are largely dependent upon the terms of those contracts. The volume of coal we sell is also a function of the productive capacity of our mining complexes, the amount of coal we purchase and changes in inventory levels. Please read “— Cost of Purchased Coal” for more information regarding our purchased coal.
 
Our long-term coal sales contracts typically provide for a fixed price, or a schedule of fixed prices, over the contract term. Two of our long-term coal sales contracts have price re-openers that provide for a market-based adjustment to the initial price every three years. These contracts will terminate if we cannot agree upon a market-based price with the customer. In addition, most of our long-term coal sales contracts have full or partial cost pass through or inflation adjustment provisions. Cost pass through provisions typically provide for increases in our sales prices in rising operating cost environments and for decreases in declining operating cost environments. Inflation adjustment provisions typically provide some protection in rising operating cost environments.
 
We evaluate the price we receive for our coal on an average sales price per ton basis. Our average sales price per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data with respect to our coal production, coal sales volume and average sales prices per ton for the periods indicated:
 
                         
    Non-GAAP
  Year Ended
  Year Ended
    Combined 2007(1)   December 31, 2008   December 31, 2009
    (tons in thousands)
 
Tons of coal produced
    4,327       5,089       5,846  
Tons of coal purchased
    946       434       530  
Tons of coal sold
    5,271       5,528       6,311  
Tons sold under long-term contracts(2)
    98.3 %     93.8 %     97.8 %
Average sales price per ton
  $ 30.00     $ 35.04     $ 40.27  
 
 
(1) Please read “— Results of Operations — Factors Affecting the Comparability of Our Results of Operations” for more information about the “non-GAAP combined 2007” presentation.
 
(2) Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts.
 
Cost of Coal Sales
 
We evaluate our cost of coal sales, which excludes the cost of purchased coal, on a cost per ton basis. Our cost of coal sales per ton produced represents our production costs divided by the tons of coal we produce. Our production costs include labor, fuel, oil, explosives, operating lease expenses, repairs and maintenance and all other costs that are directly related to our mining operations other than the cost of purchased coal, cost of transportation and depreciation, depletion and amortization, or DD&A. Our production costs also exclude any indirect costs, such as SG&A expenses. Our production costs do not take into account the effects of any of the inflation adjustment or cost pass through provisions in our long-term coal sales contracts, as those provisions result in an adjustment to our coal sales price.


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The following table provides summary information for the dates indicated relating to our cost of coal sales per ton produced:
 
                         
    Non-GAAP
  Year Ended
  Year Ended
    Combined 2007(1)   December 31, 2008   December 31, 2009
    (tons in thousands)
 
Average sales price per ton
  $ 30.00     $ 35.04     $ 40.27  
Cost of coal sales per ton
  $ 25.69     $ 29.75     $ 29.20  
Tons of coal produced
    4,327       5,089       5,846  
 
 
(1) Please read “— Results of Operations — Factors Affecting the Comparability of Our Results of Operations” for more information about the “non-GAAP combined 2007” presentation.
 
We use a substantial amount of diesel fuel in our mining operations. To mitigate our exposure to fluctuations in the price for diesel fuel we have entered into fixed price forward contracts for future delivery of diesel fuel for a portion of our requirements. During 2009, 54.4% of the 16.7 million gallons of diesel fuel we purchased was delivered under fixed price forward contracts. In addition, approximately 72.7% of the tons we delivered under our long-term coal sales contracts during 2009 were subject to full or partial cost pass through provisions for diesel fuel which provide additional protection for a portion of the increase in fuel costs.
 
Cost of Purchased Coal
 
We purchase coal from third parties to fulfill a small portion of our obligations under our long-term coal sales contracts and, in certain cases, to meet customer quality specifications. In connection with the Phoenix Coal acquisition, we assumed a long-term coal purchase contract that had favorable pricing terms relative to our production costs. Under this contract we are obligated to purchase 0.6 million tons of coal in 2010 and 0.4 million tons of coal each year thereafter until the coal reserves covered by the contract are depleted. Based on the proven and probable coal reserves in place at December 31, 2009, we expect this contract to continue beyond five years.
 
We evaluate our cost of purchased coal on a per ton basis. For the year ended December 31, 2009, we sold 0.5 million tons of purchased coal. The following table provides summary information for the dates indicated for our cost of purchased coal per ton and the tons of purchased coal:
 
                         
    Non-GAAP
  Year Ended
  Year Ended
    Combined 2007(1)   December 31, 2008   December 31, 2009
    (tons in thousands)
 
Average sales price per ton
  $ 30.00     $ 35.04     $ 40.27  
Cost of purchased coal per ton
  $ 28.51     $ 29.81     $ 36.79  
Tons of coal purchased
    946       434       530  
 
 
(1) Please read “— Results of Operations — Factors Affecting the Comparability of Our Results of Operations” for more information about the “non-GAAP combined 2007” presentation.
 
Adjusted EBITDA
 
Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, DD&A, gain from purchase of a business, amortization of below-market coal sales contracts and non-cash equity compensation expense. Although Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, our management believes that it is useful in evaluating our financial performance and our compliance with our existing credit facility. Because not all companies calculate Adjusted EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read “— Summary” for reconciliations of Adjusted EBITDA to net income (loss) attributable to our unitholders for each of the periods indicated.


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Factors that Impact Our Business
 
For the past three years over 90% of our coal sales were made under long-term coal sales contracts and we intend to continue to enter into long-term coal sales contracts for substantially all of our annual coal production. We believe our long-term coal sales contracts reduce our exposure to fluctuations in the spot price for coal and provide us with a reliable and stable revenue base. Our long-term coal sales contracts also allow us to partially mitigate our exposure to rising costs to the extent those contracts have full or partial cost pass through provisions or inflation adjustment provisions.
 
For 2010, 2011, 2012 and 2013, we currently have long-term coal sales contracts that represent 97.2%, 93.0%, 71.4% and 39.7%, respectively, of our 2010 estimated coal sales of 8.5 million tons. During 2010, 2011, 2012 and 2013, we have committed to deliver 8.2 million tons, 7.9 million tons, 6.1 million tons and 3.4 million tons of coal, respectively, under long-term coal sales contracts. These amounts include contracts with re-openers as described below. In addition, one of our long-term coal sales contracts that ends in 2012 can be extended by the customer for two additional three-year terms. If this customer elects to extend this contract, we will be committed to deliver an additional 2.0 million tons in 2013, and our 2013 coal sales under long-term coal sales contracts, as a percentage of 2010 estimated coal sales, would increase to 63.3%.
 
The terms of our coal sales contracts result from competitive bidding and negotiations with customers. As a result, the terms of these agreements — including price re-openers, coal quality requirements, quantity parameters, permitted sources of supply, effects of future regulatory changes, extension options, force majeure, termination and assignment provisions — vary by customer. However, most of our long-term coal sales contracts have full or partial cost pass through provisions or inflation adjustment provisions. For 2010, 2011, 2012 and 2013, 61%, 72%, 80% and 100% of the coal, respectively, that we have committed to deliver under our long-term coal sales contracts are subject to full or partial cost pass through or inflation adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the cost of fuel, explosives and, in certain cases, labor. Inflation adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various inflation related indices.
 
Two of our long-term coal sales contracts have price re-openers that provide for market-based adjustments to the initial price every three years. These contracts will terminate if we cannot agree upon a market-based price with the customer. For 2011, 2012 and 2013, 0.4 million tons, 0.4 million tons and 0.6 million tons of coal, respectively, that we have committed to deliver under our long-term coal sales contracts are subject to price re-opener provisions.
 
Certain of our long-term coal sales contracts give the customer the option to elect to purchase additional tons in the future at a fixed price. Our long-term coal sales contracts that contain these option tons typically require the customer to provide us with six months advance notice of an election for option tons. For 2010, 2011 and 2012, we have outstanding option tons of 0.7 million, 1.0 million and 0.7 million, respectively. If our customers do elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production.
 
We believe the other key factors that influence our business are: (i) demand for coal, (ii) demand for electricity, (iii) economic conditions, (iv) the quantity and quality of coal available from competitors, (v) competition for production of electricity from non-coal sources, (vi) domestic air emission standards and the ability of coal-fired power plants to meet these standards, (vii) legislative, regulatory and judicial developments, including delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits or mineral or surface rights, (viii) market price fluctuations for sulfur dioxide emission allowances and (ix) our ability to meet governmental financial security requirements associated with mining and reclamation activities.
 
For additional information regarding some of the risks and uncertainties that affect our business and the industry in which we operate, please read “Risk Factors.”


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Recent Trends and Economic Factors Affecting the Coal Industry
 
Coal consumption and production in the United States have been driven in recent periods by several market dynamics and trends. The recent global economic downturn has negatively impacted coal demand in the short-term, but long-term projections for coal demand remain positive. Please read “The Coal Industry — Industry Trends” for the recent trends and economic factors affecting the coal industry.
 
Results of Operations
 
Factors Affecting the Comparability of Our Results of Operations
 
The comparability of our results of operations is impacted by (i) the Phoenix Coal acquisition, (ii) an amendment to a long-term coal sales contract in December 2008 and (iii) the application of purchase accounting to our accounting predecessor’s financial statements in August 2007.
 
We acquired all of Phoenix Coal’s active surface mining operations on September 30, 2009. This acquisition increased our coal production for the fourth quarter of 2009 by 29%, or 0.4 million tons (1.6 million tons on an annualized basis).
 
In December 2008, we and one of our major customers agreed to amend a long-term coal sales contract. As part of this amendment, we agreed to give this customer two additional three-year term extension options with market-based price adjustments for each extension. In exchange, we received a substantial increase in the price per ton of coal under the contract along with inflation adjusters and certain cost pass through provisions for the remainder of the contract term that expires at the end of 2012. The 14.9% increase in our average sales price per ton in 2009 as compared to 2008 is primarily due to the amendment of this contract.
 
Oxford Mining Company, our wholly owned subsidiary, was contributed to us on August 24, 2007. Because Oxford Mining Company is our accounting predecessor, the financial statements we have presented for the periods that ended before August 24, 2007 are the financial statements of Oxford Mining Company. In addition, because Oxford Mining Company is now our wholly owned subsidiary, our financial statements that begin on or after August 24, 2007 include Oxford Mining Company on a consolidated basis, as required by GAAP. The contribution of Oxford Mining Company to us on August 24, 2007 resulted in a change of control that triggered a new fair-value basis of accounting for Oxford Mining Company on that date. We have analyzed the impact of that transaction on our consolidated statements of operations and those of our accounting predecessor.
 
The operations of the predecessor and successor in 2007 were substantially the same as all assets and liabilities were contributed with the exception of the predecessor’s debt, which was paid in full, and certain equipment operating leases, which were paid off. Therefore, the change in control had a limited impact on the comparability of our 2007 results of operations. The most notable changes that resulted from the change in control are set forth below.
 
  •  As part of the contribution, we bought out several equipment operating leases, which had the impact of reducing lease expense within cost of coal sales and increasing depreciation expense during the periods after the change in control.
 
  •  The fair value basis of accounting had the effect of increasing the asset value of certain property, plant and equipment as well as coal reserves, which further increased DD&A expenses during the periods after the change in control.
 
  •  In connection with the contribution, Oxford Mining Company entered into an advisory services agreement with certain affiliates of AIM Oxford, which resulted in higher SG&A expenses during the periods after the change in control.
 
  •  As a result of the contribution, total borrowings increased, which resulted in higher interest charges and amortization of deferred financing fees within interest expense during the periods after the change in control.


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  •  As part of the accounting for the contribution, we established a provision for below-market coal sales contracts, which increased our revenues during the periods after the change in control.
 
Based on our analysis, we concluded that the non-GAAP combined presentation provides for a more meaningful comparison of our 2007 results of operations to other periods. For comparative purposes, Oxford Mining Company’s operating results for the period from January 1, 2007 to August 23, 2007 and our operating results for the period from August 24