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EX-23.1 - EX-23.1 - Westmoreland Resource Partners, LPh69756a2exv23w1.htm
EX-23.2 - EX-23.2 - Westmoreland Resource Partners, LPh69756a2exv23w2.htm
EX-23.3 - EX-23.3 - Westmoreland Resource Partners, LPh69756a2exv23w3.htm
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As filed with the Securities and Exchange Commission on May 17, 2010
Registration No. 333-165662
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
AMENDMENT NO. 2
to
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)
41 South High Street, Suite 3450
Columbus, OH 43215
Phone: (614) 643-0314
(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
41 South High Street, Suite 3450
Columbus, OH 43215
Phone: (614) 643-0314
(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)
 
 
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 May 17, 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 have applied 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 22 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.
 
•     For each of the last five quarters, on average, we would not have generated sufficient available cash from operating surplus to pay the full minimum quarterly distribution on our common units or any distributions on our subordinated units.
 
•     Our general partner and its affiliates have conflicts of interest with us, 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 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.
 
•     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’ share of our income will be taxable to them for U.S. federal income tax purposes 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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 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.


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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 22 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 have included 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 first quarter of 2010, our largest mine represented 12.6% 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.
 
During 2009 and the first quarter of 2010, we produced 5.8 million tons and 1.8 million tons of coal, respectively. During the fourth quarter of 2009 and the first quarter of 2010, we produced 0.4 million tons from the reserves we acquired in western Kentucky from Phoenix Coal on September 30, 2009. Based on our coal production for the first quarter of 2010, our annualized coal production for 2010 would be 7.2 million tons. During 2009 and the first quarter of 2010, we sold 6.3 million tons and 2.0 million tons of coal, respectively, including 0.5 million tons and 0.3 million tons of purchased coal, respectively. We currently have long-term coal sales contracts in place for 2010, 2011, 2012 and 2013 that represent 97.6%, 93.0%, 71.4% and 39.6%, 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.


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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. 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 and the first quarter of 2010, we generated revenues of approximately $293.8 million and $88.1 million, respectively, net income (loss) attributable to our unitholders of approximately $23.5 million and $(0.3) million, respectively, and Adjusted EBITDA of approximately $50.8 million and $10.0 million, respectively. 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 the first quarter of 2010 and our coal reserves as of December 31, 2009:
 
                                                             
                As of December 31, 2009
    Production for
    Production for
    Total
                             
    the Year Ended
    the Quarter
    Proven &
                Average
    Average
    Primary
    December 31,
    Ended
    Probable
    Proven
    Probable
    Heat
    Sulfur
    Transportation
Mining Complexes   2009     March 31, 2010     Reserves(1)     Reserves(1)     Reserves(1)     Value     Content     Methods
    (in million tons)                 (Btu/lb)     (%)      
 
Surface Mining Operations:
                                                           
Northern Appalachia (principally Ohio)
                                                           
Cadiz
    1.1       0.3       12.4       12.2       0.2       11,520       3.3     Barge, Rail
Tuscarawas County
    0.9       0.3       8.8       8.8       0.0       11,570       3.7     Truck
Belmont County
    1.3       0.3       6.6       6.3       0.3       11,510       3.7     Barge
Plainfield
    0.5       0.1       6.4       6.4       0.0       11,350       4.4     Truck
New Lexington
    0.6       0.1       4.9       4.0       0.9       11,260       4.0     Rail
Harrison(2)
    0.7       0.2       2.8       2.8       0.0       12,040       1.8     Barge, Rail, Truck
Noble County
    0.3       0.1       2.5       2.4       0.1       11,230       4.7     Barge, Truck
Illinois Basin (Kentucky)
                                                           
Muhlenberg County
    0.4 (3)     0.4       24.2       23.5       0.7       11,295       3.6     Barge, Truck
                                                             
Total Surface Mining Operations
    5.8       1.8       68.6       66.4       2.2                      
                                                             
Underground Coal Reserves:
                                                           
Northern Appalachia (Ohio)
                                                           
Tusky(4)
                    23.0       18.6       4.4       12,900       2.1      
                                                             
Total Underground Coal Reserves
                    23.0       18.6       4.4                      
                                                             
Total
                    91.6       85.0       6.6                      
                                                             
 
 
(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


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consolidated financial statements for the year ended December 31, 2009 and the first quarter of 2010 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.”
 
(3) Acquired from Phoenix Coal on September 30, 2009. As a result, production data for 2009 represents production from the date of acquisition through 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. We received royalty payments on 0.6 million tons and 0.1 million tons of coal produced from the Tusky mining complex during 2009 and the first quarter of 2010, respectively.
 
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. Please read “Cash Distribution Policy and Restrictions on Distributions — General — Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital” for additional details on how we intend to grow our reserve base and production capacity and the limitations we face in implementing this strategy.
 
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


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  sales contracts in place for 2010, 2011, 2012 and 2013 that represent 97.6%, 93.0%, 71.4% and 39.6%, 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.
 
  •     Our mining operations are flexible and diverse.  During the first quarter of 2010, our largest mine represented 12.6% 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, the expertise of our general partner’s employees and their 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%, respectively, through 2015. 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 general partner’s senior management team and key operational employees have extensive industry experience.  The members of our general partner’s 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.


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  •     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.
 
  •     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


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AIM Oxford. Brian D. Barlow, Matthew P. Carbone and George E. McCown serve on the board of directors of our general partner and 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.
 
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 is a summary of our risk factors. Please read “Risk Factors” beginning on page 22 carefully for a more thorough description of these 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.
 
  •     For each of the last five quarters, on average, we would not have generated sufficient available cash from operating surplus to pay the full minimum quarterly distribution on our common units or any distributions on our subordinated units.
 
  •     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.
 
  •     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.
 
  •     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.
 
  •     New 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.


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  •     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.
 
  •     In the future, we may not receive cash distributions from Harrison Resources, and Harrison Resources may not be able to acquire additional reserves on economical terms from CONSOL Energy.
 
  •     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.
 
  •     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.
 
  •     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.
 
  •     We may be unable to obtain, maintain or renew permits necessary for our operations, which would materially reduce our production, cash flows and profitability.
 
  •     If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated.
 
  •     Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
 
  •     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.
 
  •     Our operations may impact the environment or cause environmental contamination, which could result in material liabilities to 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.
 
  •     Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.
 
  •     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.
 
  •     Our work force could become unionized in the future, which 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 ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
 
  •     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.
 
  •     The amount of estimated reserve replacement 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.


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  •     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.
 
  •     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.
 
  •     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.
 
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 with us, 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.
 
  •     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.
 
  •     The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
 
  •     Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
 
  •     We may issue additional units without unitholder approval, which would dilute unitholder interests.
 
  •     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.
 
  •     Cost reimbursements due to our general partner and its affiliates will reduce cash available 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.
 
  •     We will incur increased costs as a result of being a publicly traded partnership.
 
  •     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 receive distributions or allocations of income or loss on their common units and their common units will be subject to redemption.
 
  •     Our unitholders may have liability to repay distributions.
 
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.


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  •     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’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
 
  •     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.
 
  •     Tax gain or loss on the disposition of our common units could be more or less than expected.
 
  •     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.
 
  •     We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
 
  •     We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes 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.
 
  •     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, such unitholder 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.
 
  •     We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes 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 our common units.
 
  •     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.
 
  •     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.


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The Transactions
 
Immediately prior to the closing of this offering:
 
  •     we will distribute pro rata, in accordance with their respective interests in us, 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, that hold our common units;
 
  •     each general partner unit held by our general partner will automatically split into      general partner units, resulting in the ownership of an aggregate of      general partner units, representing a 2.0% general partner interest in us;
 
  •     each common unit held by participants in our LTIP will automatically split into      common units, resulting in their ownership of an aggregate of           common units, representing an aggregate     % limited partner interest in us;
 
  •     each Class B common unit held by C&T Coal will automatically split into      Class B common units resulting in C&T Coal’s ownership of an aggregate of           Class B common units, representing an aggregate     % limited partner interest in us; and
 
  •     each Class B common unit held by AIM Oxford will automatically split into      Class B common units resulting in C&T Coal’s ownership of an aggregate of           Class B common units, representing an aggregate     % limited partner interest in us.
 
In connection with the closing of this offering, the following will occur:
 
  •     all of our Class B common units held by C&T Coal, representing a     % limited partner interest in us, will automatically convert into: (i) common units, representing a     % limited partner interest in us, and (ii) subordinated units, representing a% limited partner interest in us;
 
  •     all of our Class B common units held by AIM Oxford, representing a     % limited partner interest in us, will automatically convert into: (i)      common units, representing a     % limited partner interest in us, and (ii)      subordinated units, representing a     % 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 for the purposes set forth in “Use of Proceeds”;
 
  •     we will enter into a new credit facility; and
 
  •     we will use 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, Brian D. Barlow, Matthew P. Carbone and George E. McCown serve on the board of directors of our general partner and 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 sometimes 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 41 South High Street, Suite 3450, Columbus, Ohio 43215. Our phone number is (614) 643-0314. 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 us and 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 the participants in our LTIP that hold our common units, (iv) buy out our advisory services agreement with affiliates of AIM for approximately $      million, (v) pay offering expenses of approximately $      million and (vi) 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.
 
For more information about our use of the proceeds of this offering, including a tabular summary, please read “Use of Proceeds.”
 
Cash distributions We intend to pay 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.”


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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 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
Total Quarterly Distribution
    in 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.”
 
Our historical cash available for distribution generated during the year ended December 31, 2009 and the twelve months ended March 31, 2010 was $      million and $      million, respectively. 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 (or an average of $      million per quarter). As a result, for the quarters ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010, on average, we would have generated cash sufficient to pay     %,     %,     %,     % and     %, respectively, of the minimum quarterly distribution on our common units, and we would not have been able to pay any distributions on our subordinated units in any of those quarters.


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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 corresponding distribution on our general partner’s 2.0% general partner interest for the four quarters ending June 30, 2011. 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 $31.9 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 any four quarter period ending on or after June 30, 2011, 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.


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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 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


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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 of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.
 
Directed unit program At our request, the underwriters have established a directed unit program under which they have reserved for sale at the initial public offering price up to      common units offered by this prospectus for our officers, directors and employees of our general partner and certain friends and family of our sponsors, and the officers, directors and employees of our general partner. The number of common units available for sale to the public will be reduced by the number of directed common units purchased by participants in the program. Any directed common units not so purchased will be offered by the underwriters to the public on the same basis as the other common units offered by this prospectus. Please read “Underwriting — Directed Unit Program.”
 
Material federal income tax consequences For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences.”
 
Exchange listing We have applied 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 as of August 23, 2007 and 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 included elsewhere in this prospectus. The summary historical consolidated financial data presented as of and for the quarters ended March 31, 2009 and 2010 are derived from our unaudited historical condensed consolidated financial statements included elsewhere in this prospectus.
 
The summary pro forma consolidated financial data presented for the year ended December 31, 2009 and as of and for the quarter ended March 31, 2010 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 as of March 31, 2010 assumes this offering occurred as of March 31, 2010. The unaudited pro forma consolidated statements of operations for the year ended December 31, 2009 and the quarter ended March 31, 2010 assume 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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    Oxford
                                               
    Mining
                                      Pro Forma Oxford
 
    Company
      Oxford Resource Partners, LP
      Resource Partners, LP
 
    (Predecessor)
      (Successor)       (Successor)  
    Period from
      Period from
                                       
    January 1,
      August 24,
                                    Quarter
 
    2007 to
      2007 to
    Year Ended
    Quarter Ended
      Year Ended
    Ended
 
    August 23,
      December 31,
    December 31,     March 31,       December 31,
    March 31,
 
    2007       2007     2008     2009     2009     2010       2009     2010  
                              (unaudited)                
                  (In thousands, except per ton amounts)       (unaudited)  
Statement of Operations Data:
                                                                   
Revenues:
                                                                   
Coal sales
  $ 96,799       $ 61,324     $ 193,699     $ 254,171     $ 67,377     $ 76,756       $ 312,490     $ 76,756  
Transportation revenue
    18,083         10,204       31,839       32,490       8,660       9,530         37,221       9,530  
Royalty and non-coal revenue
    3,267         1,407       4,951       7,183       2,402       1,774         7,183       1,774  
                                                                     
Total revenues
    118,149         72,935       230,489       293,844       78,439       88,060         356,894       88,060  
Costs and expenses:
                                                                   
Cost of coal sales (excluding DD&A, shown separately)
    70,415         40,721       151,421       170,698       40,825       55,186         214,662       55,186  
Cost of purchased coal
    17,494         9,468       12,925       19,487       8,505       7,859         29,792       7,859  
Cost of transportation
    18,083         10,204       31,839       32,490       8,660       9,530         37,221       9,530  
Depreciation, depletion, and amortization
    9,025         4,926       16,660       25,902       5,688       8,777         31,424       8,777  
Selling, general and administrative expenses
    3,643         2,114       9,577       13,242       3,101       3,535         25,735       3,457  
                                                                     
Total costs and expenses
    118,660         67,433       222,422       261,819       66,779       84,887         338,834       84,809  
                                                                     
Income (loss) from operations
    (511 )       5,502       8,067       32,025       11,660       3,173         18,060       3,251  
Interest income
    26         55       62       35       11       1         39       1  
Interest expense
    (2,386 )       (3,498 )     (7,720 )     (6,484 )     (1,123 )     (1,833 )       (7,669 )     (2,016 )
Gain from purchase of business(1)
                        3,823                     3,823        
                                                                     
Net income (loss)
    (2,871 )       2,059       409       29,399       10,548       1,341         14,253       1,236  
Less: Net income attributable to noncontrolling interest
    (682 )       (537 )     (2,891 )     (5,895 )     (1,165 )     (1,628 )       (5,895 )     (1,628 )
                                                                     
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (3,553 )     $ 1,522     $ (2,482 )   $ 23,504     $ 9,383     $ (287 )     $ 8,358     $ (392 )
                                                                     
Statement of Cash Flows Data:
                                                                   
Net cash provided by (used in):
                                                                   
Operating activities
  $ 17,634       $ (8,519 )   $ 33,992     $ 37,183     $ 10,502     $ 8,341                    
Investing activities
    (16,619 )       (98,745 )     (23,942 )     (49,528 )     (7,482 )     (10,280 )                  
Financing activities
    (234 )       106,724       4,494       532       2,442       (137 )                  
Other Financial Data:
                                                                   
Adjusted EBITDA(2)
  $ 7,832       $ 7,961     $ 21,533     $ 50,799     $ 16,292     $ 10,001       $ 37,800     $ 10,079  
Reserve replacement expenditures(3)
    1,297         163       2,526       3,077       61       528         3,077       528  
Other maintenance capital expenditures(3)
    11,305         4,421       25,321       25,542       6,715       4,995         25,542       4,995  
Distributions
                    12,503       13,407       2,523       2,818                    
Balance Sheet Data (at period end):
                                                                   
Cash and cash equivalents
  $ 1,175       $ 635     $ 15,179     $ 3,366     $ 20,641     $ 1,290                 34,128  
Trade accounts receivable
    18,396         17,547       21,528       24,403       23,196       29,838                 2,000  
Inventory
    4,824         4,655       5,134       8,801       6,584       10,390                 10,390  
Property, plant and equipment, net
    54,510         106,408       112,446       149,461       117,031       147,949                 147,949  
Total assets
    90,893         146,774       171,297       203,363       184,982       212,917                 221,072  
Total debt (current and long-term)
    43,165         75,529       83,977       95,711       91,799       98,432                 103,057  
Operating Data:
                                                                   
Tons of coal produced
    2,693         1,634       5,089       5,846       1,396       1,806         7,221       1,806  
Tons of coal purchased
    641         305       434       530       192       258         885       258  
Tons of coal sold
    3,333         1,938       5,528       6,311       1,559       2,036         8,051       2,036  
Average sales price per ton(4)
  $ 29.04       $ 31.64     $ 35.04     $ 40.27     $ 43.23     $ 37.71       $ 38.81     $ 37.71  
Cost of coal sales per ton produced(5)
  $ 26.15       $ 24.92     $ 29.75     $ 29.20     $ 29.25     $ 30.56       $ 29.56     $ 30.56  
Cost of purchased coal per ton(6)
  $ 27.29       $ 31.08     $ 29.81     $ 36.79     $ 44.32     $ 30.51       $ 33.66     $ 30.51  
 
 
(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 ended 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. Our partnership agreement divides maintenance capital expenditures into two categories — reserve replacement expenditures and other maintenance capital expenditures. Examples of reserve replacement expenditures include capital expenditures associated with the replacement of 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. Examples of other maintenance capital expenditures include capital expenditures associated with the replacement of equipment. 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 reserve replacement expenditures and which of them would have been other 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 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.”
 
 
We must generate approximately $      million (or an average of $      million per quarter) of available cash to pay the minimum quarterly distribution for four quarters on all of our common units, subordinated units and general partner units that will be outstanding immediately after this offering. We did not generate this amount of available cash from operating surplus during the year ended December 31, 2009 and the twelve months ended March 31, 2010. The amounts we generated with respect to those periods were $      million and $      million, respectively. As a result, for the quarters ended March 31, 2009, June 30, 2009,


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September 30, 2009, December 31, 2009 and March 31, 2010, on average, we would have generated available cash sufficient to pay only     %,     %,     %,     % and     %, respectively, of the minimum quarterly distribution on our common units, and we would not have been able to pay any distributions on our subordinated units in any of those quarters.
 
 
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 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. 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.”
 
 
Our business is closely linked to domestic demand for electricity and any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. 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. 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, such as the recent downturn in the U.S. economy and financial markets;
 
  •     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.
 
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 that affect our customers, such as those caused by decreased electricity demand and increased competition, could also adversely affect our business. Indirect competition from gas-fired plants that are cheaper to construct and easier to permit has the most potential to displace a significant amount of coal-fired generation in the near term, particularly older, less efficient coal-powered generators. In addition, uncertainty caused by federal and state regulations could cause coal customers to be uncertain of their coal requirements in future years, which could adversely affect our ability to sell coal to our customers under long-term coal sales contracts.


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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;
 
  •     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.
 
For more information regarding our long-term coal sales contracts, please read “Business — Customers — Long-Term Coal Sales Contracts.”
 
 
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 depends 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.”
 
 
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. Our competitors may have, among other things, greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures (like our competitors in the PRB), partnerships with transportation companies or more effective risk management policies and procedures. Our failure to compete successfully could have a material adverse effect on our business, financial condition or results of operations.


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We derived 77% and 72% of our revenues from coal sales to our five largest customers for the year ended December 31, 2009 and the first quarter of 2010, respectively, and as of May 14, 2010, we had long-term coal sales contracts in place with these same customers for 77% 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.
 
 
One major by-product of burning coal is carbon dioxide, which is a greenhouse gas and a source of concern with respect to global warming, also known as climate change. Climate change continues to attract government, public and scientific attention, especially on ways to reduce greenhouse gas emissions, including from coal-fired power plants. Various international, federal and state regulatory proposals are being considered 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. Future regulation of greenhouse gas emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers and may restrict the construction of new coal-fired power plants.
 
The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions. In addition, at least two U.S. federal appeals courts have allowed lawsuits pursuing federal common law claims to proceed 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. Future regulation, litigation and permitting related to greenhouse gas emissions may cause some users of coal to switch from coal to a lower-carbon fuel, or otherwise reduce 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. For a more detailed discussion of potential climate change impact, please read “Business — Regulation and Laws — Climate Change.”
 
 
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 emissions of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds, including emissions 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 without the use of costly pollution control devices such as scrubbers, the purchase of emission allowances or the blending of 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 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 materially increase the cost of mining and delay or halt production 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 or flooding;
 
  •     the unavailability of qualified labor and contractors;
 
  •     the unavailability or increased prices of equipment or other critical supplies such as tires and explosives, fuel, lubricants and other consumables;
 
  •     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 permits or mineral and surface rights;
 
  •     future health, safety and environmental regulations or changes in the interpretation or enforcement of existing regulations;
 
  •     mine accidents or other unforeseen casualty events, including those involving injuries or fatalities;
 
  •     increased or unexpected reclamation costs; and
 
  •     the inability to monitor our operations due to failures of information technology systems.
 
If any of the foregoing changes, conditions or events occurs and is not excusable as a force majeure event, any resulting failure on our part to deliver coal to the purchaser under a long-term sales contracts could result in economic penalties, suspension or cancellation of shipments or ultimately termination of the agreement. While we have various options that we could pursue to address a delivery failure, including purchasing coal on the open market or entering into negotiations to amend the quantity of coal we are required to deliver, even those efforts may be unsuccessful in preventing any such change, condition or event from having a material adverse effect on our business, financial condition or results of operations. For more information regarding our long-term coal sales contracts, please read “Business — Customers — Long-Term Coal Sales Contracts.”
 
We maintain insurance coverage for some but not all potential 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. In addition, it is not possible to insure fully against safety, pollution and environmental risks. The occurrence of a significant accident or other event that is not fully covered by insurance could have a material adverse effect on our business, financial condition or results of operations.
 
 
In January 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy. Pursuant to its operating agreement, all members of Harrison Resources must approve cash distributions, other than tax distributions to its members. The members of Harrison Resources have consistently approved cash


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distributions from Harrison Resources on a quarterly basis, including an aggregate of $6.3 million in distributions to us during 2009 and $1.5 million in distributions to us in April 2010. In the future, however, there can be no assurance that we will receive regular cash distributions.
 
In addition, CONSOL Energy controls the vast majority of the additional reserves in Harrison County, Ohio that could be acquired by Harrison Resources in the future. However, CONSOL Energy has no obligation to sell those reserves to Harrison Resources, and we cannot assure you that Harrison Resources could acquire those reserves from CONSOL Energy on acceptable terms. As a result, the growth of, and therefore 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.
 
 
In June 2005, we sold our underground mining operations at the Tusky mining complex to an independent coal producer and subleased our underground coal reserves to this producer in exchange for an overriding royalty equal to a percentage of the sales price received for the coal produced and sold. For the year ended December 31, 2009 and the first quarter of 2010, we received royalty income on our underground coal reserves of approximately $4.5 million and $0.9 million, respectively, or approximately 8.9% and 9.1% of our Adjusted EBITDA, respectively. The royalty payments we receive could be adversely affected by any of the following:
 
  •     a substantial and extended decline in the sales price for coal produced from our underground coal reserves;
 
  •     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.
 
If the royalty payments we receive from our sublessee are reduced, our ability to make cash distributions to our unitholders could be adversely affected.
 
 
We use considerable quantities of diesel fuel in our mining operations. Even though we hedge a portion of our diesel fuel needs, if the price of diesel fuel increases significantly, our operating expenses will increase, 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 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.


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The coal mining industry is subject to increasingly strict federal, state and local environmental and mining safety laws and regulations. The enforcement of laws and regulations governing the coal mining industry has substantially increased, due in part to recent mining accidents at certain mines. Violations can result in administrative, civil and criminal penalties and a range of other possible sanctions. The recent fatal mining accident in West Virginia received national attention and led to responses at the state and national levels that may further increase mine safety regulation, reporting requirements, inspection and enforcement, particularly underground mining operations. 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 and be subject to more adverse consequences for non-compliance. Such changes could have a material adverse effect on our business, financial condition or results of operations. Please read “Business — Regulation and Laws.”
 
 
As is typical in the coal industry, our coal production is dependent on our ability to obtain various federal and state permits and approvals 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, which may increase the costs or 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. The slowing pace at which necessary permits are issued or renewed for new and existing mines has materially impacted coal production, especially in Central Appalachia. Permitting by the Army Corps of Engineers, or the Corps, the EPA and the Department of the Interior has become subject to “enhanced review” under both the Surface Mining Control and Reclamation Act of 1977, or SMCRA, and the federal Clean Water Act, or CWA, to reduce the harmful environmental consequences of mountain-top mining, especially in the Appalachian region. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of CWA permits by state and federal agencies.
 
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. For example, one of our permit applications that covers 0.6 million tons of our coal reserves is 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. Additional permits could be delayed in the future if the EPA continues its enhanced review of CWA applications. 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. Please read “Business — Regulation and Laws.”
 
 
SMCRA and counterpart state laws and regulations establish reclamation and closure standards for surface mining. 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


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by our management and engineers. Our estimated reclamation and mine closure obligations could change significantly if actual results change from our assumptions, which could have a material adverse effect on our financial condition or results of operations. Please read Note 2 to our historical consolidated financial statements included elsewhere in this prospectus under the heading “Asset Retirement Obligation” for more information regarding our reclamation and mine closure obligations.
 
 
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 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.
 
 
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 contain covenants requiring us to maintain certain financial ratios. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility.”
 
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.


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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. These and other 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. Please read “Business — Regulation and Laws.”
 
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 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.
 
 
Our ability to operate our business and implement our strategies depends on the continued contributions of Charles C. Ungurean and other executive officers and key employees of our general partner. In particular, we depend significantly on Mr. Ungurean’s long-standing relationships within our industry. The loss of any of our senior executives, and Mr. Ungurean in particular, could have a material adverse effect on our business. 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 and competition for these persons in the coal industry is intense. 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.
 
 
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 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 general partner’s employees, our results of operations could be materially and adversely affected.
 
 
All of our mines are operated by non-union employees of our general partner. 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.


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Our future performance depends on, among other things, the accuracy of the estimates of our proven and probable coal reserves. Please read “Business — Coal Reserves” for more information on the preparation of our reserves estimates. 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 receive payment for the coal we sell depends on the continued creditworthiness of our customers. The current economic volatility and tightening credit markets increase the risk that we may not be able to collect payments from our customers. A continuation or worsening of current economic conditions or other prolonged global or U.S. recessions could also impact the creditworthiness of our customers.
 
If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for all coal we sell to 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.
 
In addition, we sell some of our coal to coal brokers who may resell our coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, we have contractual privity only with the brokers 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. In 2009, approximately 12% of our sales were to coal brokers, and we expect our sales through coal brokers to increase in 2010.


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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 March 31, 2010 of approximately $32.4 million, which were supported by letters of credit of $7.5 million. Certain business transactions, such as coal leases and other obligations, may also require bonding. Our bonding requirements could increase in the future. 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. 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 partnership agreement requires our general partner to deduct from operating surplus each quarter estimated reserve replacement expenditures as opposed to actual reserve replacement expenditures in order to reduce disparities in operating surplus caused by fluctuating reserve replacement costs. Our initial annual estimated reserve replacement expenditures for purposes of calculating operating surplus will be $5.6 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 reserve 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.” In the future our estimated reserve replacement expenditures may be more than our actual reserve replacement expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated reserve replacement 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.
 
 
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 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. However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation


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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 deficiency or combination of deficiencies in internal controls over financial reports 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. A “significant deficiency” is a deficiency or combination of deficiencies that is less severe than a material weakness.
 
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 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
 
 
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 our general partner honestly 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.”
 
 
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 reserve replacement 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.”
 
 
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.
 
 
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.”
 
 
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.
 
 
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.
 
 
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


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common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its 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.”
 
 
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 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.”


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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 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 will reduce the amount of available cash for distribution to our unitholders.
 
 
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; and
 
  •     the other factors described in these “Risk Factors.”
 
In addition, the market price of our common units could decline as a result of sales of a large number of our common units in the public markets after this offering. We, our subsidiaries, our general partner and its affiliates, including C&T Coal and AIM Oxford, and the directors and executive officers of our general partner have entered into “lock-up” agreements with the underwriters, as described in the section entitled “Underwriting — Lock-Up Agreements.” The lock-up agreements cover      common units or     % of the total number of common units that will be outstanding upon completion of this offering. The common units subject to these lock-up agreements will be restricted from immediate resale but may be sold into the market after those restrictions expire, which will be at least 180 days after the date of this prospectus. However,


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Barclays Capital Inc., in its sole discretion, may release the common units subject to the lock-up agreements in whole or in part at any time with or without notice.
 
 
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 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.”
 
 
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.
 
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.


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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.
 
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.
 
 
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 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.
 
 
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


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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.
 
 
Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives 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.
 
 
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, and the IRS’s positions may ultimately be sustained. 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.
 
 
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.
 
 
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


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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.
 
 
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.
 
 
We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes 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.”
 
 
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.
 
 
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


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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.
 
 
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 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.
 
 
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 $96.5 million at May 14, 2010;
 
  •     distribute approximately $      million to C&T Coal in respect of its limited partner interest in us;
 
  •     distribute approximately $      million to the participants in our LTIP that hold our common units in respect of their limited partner interests in us;
 
  •     buy out our advisory services agreement with affiliates of AIM for approximately $     million; 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 that we distributed to our partners immediately prior to the closing of this offering. Please read “Summary — The Transactions.”.
 
The table below sets forth our anticipated use of the net proceeds from this offering.
 
                 
    Application of
       
    Net Proceeds of
    Percentage of
 
    this Offering     Net Proceeds  
    (in thousands)  
 
Repayment of our existing credit facility
  $ 96,500       %
Distribution to C&T Coal
               
Distribution to LTIP participants
               
Buy out of advisory services agreement
               
Payment of offering expenses
               
Replenish working capital
               
                 
Total
  $         100 %
                 
 
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 May 14, 2010, we had approximately $96.5 million of indebtedness outstanding under our existing credit facility. This indebtedness had a weighted average interest rate of 6.58% as of May 14, 2010. Our existing credit facility matures in August 2012.
 
The LTIP participants that will receive the approximately $     million described above consist of our independent director, our executive officers (excluding Charles C. Ungurean and Thomas T. Ungurean) and certain key employees.
 
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


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offering price, we will use the additional proceeds for general partnership purposes, which may include the funding of additional working capital and funds to pay operating expenditures. If the proceeds decrease due to a lower initial public offering price, the amount that we have available to distribute to C&T Coal and the LTIP participants will decrease by a corresponding amount. In the event of such a decrease, we will also reduce our borrowings under our new credit facility and the distribution to AIM Oxford will decrease by a proportional 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. Please read “Underwriting — Relationships/FINRA Conduct Rules.”


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CAPITALIZATION
 
The following table shows:
 
  •     our historical capitalization, as of March 31, 2010; and
 
  •     our pro forma, as adjusted capitalization as of March 31, 2010, 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 (based on the mid-point of the price range set forth on the cover page of this prospectus);
 
  •     the application of the net proceeds from this offering 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 unaudited 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 March 31, 2010  
          Pro Forma,
 
    Actual     As Adjusted  
    (in thousands)  
 
Cash and cash equivalents
  $ 1,290          
                 
Long-term debt (including current maturities):
               
Existing credit facility(1)
    93,518          
New credit facility(2)
             
Other debt
    4,914          
                 
Total long-term debt (including current maturities)
  $ 98,432          
                 
Partners’ capital:
               
Limited partners:
               
Common unitholders — public
             
Common unitholders — LTIP
    962          
Common unitholders — sponsors
    50,158          
Subordinated unitholders — sponsors
             
General partner
    1,048          
                 
Total Oxford Resource Partners, LP partners’ capital
    52,168          
Noncontrolling interest
    3,695          
                 
Total partners’ capital
    55,863          
                 
Total capitalization
  $ 155,585          
                 
 
 
(1) As of May 14, 2010, we had $96.5 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 May 14, 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 March 31, 2010, 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, and LTIP participants(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 and our historical unaudited consolidated financial statements as of and for the quarters ended March 31, 2009 and 2010 included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy
 
Our partnership agreement 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 available cash may also include, 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. 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. In addition, our ability to pay quarterly cash distributions will be restricted if an event of default has occurred under our new credit facility. The financial tests, covenants and events of default 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


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  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.”
 
  •     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 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 and the twelve months ended March 31, 2010 would not have been sufficient to allow us to pay the full minimum quarterly distribution on our common units or pay any distributions on our subordinated units. For the quarters ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010, on average, we would have generated available cash sufficient to pay     %,     %,     %,     % and     %, respectively, of the minimum quarterly distribution on our common units, and we would not have been able to pay any distributions on our subordinated units in any of those quarters.
 
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.


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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. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “— General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be 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. The amount of available cash 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 in order 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 partnership agreement 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 available cash may also include, 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.
 
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 have an honest belief 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.


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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 corresponding distribution on our general partner’s 2.0% general partner interest for the twelve months ending June 30, 2011, which is the first full four quarter period that begins after the expected closing date of this offering. We present a table below, consisting of historical results of operations and cash available for distribution for the year ended December 31, 2009 and the twelve months ended March 31, 2010 and forecasted results of operations and cash available for distribution for the twelve months ending June 30, 2011. 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 and the twelve months ended March 31, 2010, based on our historical consolidated statements 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 based on our historical consolidated statements of operations included elsewhere in this prospectus 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.
 
We must generate approximately $      million (or an average of $      million per quarter) of available cash to pay the minimum quarterly distribution for four quarters on all of our common units, subordinated units and general partner units that will be outstanding immediately after this offering. We did not generate this amount of available cash from operating surplus during the year ended December 31, 2009 and the twelve months ended March 31, 2010. The amounts that we generated with respect to those periods were $      million and $      million, respectively. As a result, for the quarters ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010, on average, we would have generated available cash sufficient to pay     %,     %,     %,     % and     %, respectively, of the minimum quarterly distribution on our common units, and we would not have been able to pay any distributions on our subordinated units in any of those quarters.
 
We forecast that our cash available for distribution generated during the twelve months ending June 30, 2011 will be approximately $31.9 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 corresponding 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 corresponding 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


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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 action and our expected future financial performance. However, this information is not necessarily indicative of future results.
 
Neither our independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the forecast contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the forecast. We do not 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
    Twelve Months
 
    December 31,
    Ended
    Ending June 30,
 
    2009     March 31, 2010     2011  
    (In thousands, except per unit and
 
    per ton amounts)  
 
Operating data:
                       
Coal produced in tons
    5,846       6,256       8,079  
Coal purchased in tons
    530       595       730  
                         
Coal available for sale in tons
    6,376       6,851       8,809  
                         
Coal sold in tons
    6,311       6,788       8,789  
Increase in coal inventory in tons
    65       63       20  
Coal sales in tons — sold/committed(2)
    6,311       6,788       8,121  
Coal sales in tons — uncommitted
    n/a       n/a       668  
Average sales price per ton — sold/committed(2)
  $ 40.27     $ 38.83     $ 38.13  
Average sales price per ton — uncommitted
    n/a       n/a     $ 40.32  
Selected financial data:
                       
Coal sales revenue — sold/committed(2)
  $ 254,171     $ 263,550     $ 309,661  
Coal sales revenue — uncommitted
    n/a       n/a       26,934  
Transportation revenue
    32,490       33,360       44,894  
Royalty and non-coal revenue(3)
    7,183       6,555       7,455  
                         
Total revenues
    293,844       303,465       388,944  
Costs and expenses:
                       
Cost of coal sales (excluding DD&A, shown separately)
    170,698       185,059       226,382  
Cost of purchased coal
    19,487       18,841       23,379  
Cost of transportation
    32,490       33,360       44,894  
Depreciation, depletion and amortization
    25,902       28,991       37,365  
Selling, general and administrative expenses(4)
    13,242       13,676       14,703  
                         
Total costs and expenses
    261,819       279,927       346,723  
                         
Income from operations
    32,025       23,538       42,221  
Interest income
    35       25       15  
Interest expense
    (6,484 )     (7,194 )     (7,093 )
Gain from purchase of business(5)
    3,823       3,823        
                         
Net income
    29,399       20,192       35,143  
Less: income attributable to noncontrolling interest
    (5,895 )     (6,358 )     (7,531 )
                         
Net income attributable to Oxford Resource Partners, LP unitholders
  $ 23,504     $ 13,834     $ 27,612  
                         
Plus:
                       
Depreciation, depletion and amortization
    25,902       28,991       37,365  
Interest expense
    6,484       7,194       7,093  
Non-cash equity compensation expense
    472       667       433  
Less:
                       
Interest Income
    35       25       15  
Gain from purchase of business(5)
    3,823       3,823        
Amortization of below-market coal sales contracts
    1,705       2,330       2,132  
                         
Adjusted EBITDA(6)
  $ 50,799     $ 44,508     $ 70,356  
Less:
                       
Cash interest expense, net of interest income
    5,970       6,248       6,221  
Reserve replacement expenditures(7)
    3,077       3,545       5,625  
Other maintenance capital expenditures(7)
    25,542       23,822       26,644  
                         
Cash available for distribution
  $ 16,210     $ 10,893     $ 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)
                       
                         


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(1) The forecasted column is based on the assumptions set forth in “— Significant Forecast Assumptions” below.
 
(2) Represents coal sold for 2009 and the twelve months ended March 31, 2010 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 and other revenue.
 
(4) Historical SG&A expenses for both the year ended December 31, 2009 and the twelve months ended March 31, 2010 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 ending June 30, 2011 do 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 both the year ended December 31, 2009 and the twelve months ended March 31, 2010.
 
(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. Our partnership agreement divides maintenance capital expenditures into two categories — reserve replacement expenditures and other maintenance capital expenditures. For purposes of this presentation, however, we have evaluated our capital expenditures for both the year ended December 31, 2009 and the twelve months ended March 31, 2010 to determine which of them would have been classified as reserve replacement expenditures and other maintenance capital expenditures, respectively, in accordance with our partnership agreement at the time they were made. Based on this evaluation, we estimate that our reserve replacement expenditures and other maintenance capital expenditures for the year ended December 31, 2009 would have been $3.1 million and $25.5 million, respectively, and for the twelve months ended March 31, 2010 would have been $3.5 million and $23.8 million, respectively. The amount of our actual reserve replacement expenditures may differ substantially from period to period, which could


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cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders, if we subtracted actual reserve replacement expenditures from operating surplus. To eliminate these fluctuations, our partnership agreement will require that an estimate of the reserve replacement expenditures necessary to maintain our asset base be subtracted from operating surplus each quarter as opposed to amounts actually spent on reserve replacement expenditures. The $5.6 million of reserve replacement expenditures for the forecasted twelve months ending June 30, 2011 represents estimated reserve replacement expenditures as defined in our partnership agreement. The amount of estimated reserve replacement 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 reserve replacement expenditures during the forecast period to be consistent with our estimated reserve replacement expenditures for that period. We have not included any expansion capital expenditures in the forecast period. To the extent we incur expansion capital 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 reserve replacement 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 corresponding distributions on our general partner’s 2.0% general partner interest.
 
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 material to our forecasted results of operations and any assumptions not discussed below were not deemed to be material. 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 the year ended December 31, 2009 and $303.5 million for the twelve months ended March 31, 2010. 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 and 6.3 million tons we produced in the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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 first quarter of 2010 (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 11% and 10% compared to the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. These increases are primarily attributable to increased production at our Harrison County mining complex.


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  •     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 and 6.8 million tons we sold in the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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 and $38.83 for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. This estimate takes into account prices in our long-term coal sales 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 non-recurring price increase for 2009, which contributed $13.25 million to revenues and Adjusted EBITDA in 2009, that related to an amendment of a long-term coal sales contract with a major customer.
 
  •     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 and other sources of revenue, will be $7.5 million for the twelve months ending June 30, 2011, as compared to $7.2 million and $6.6 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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 for the year ended December 31, 2009 and the twelve months ended March 31, 2010.
 
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 and 0.6 million tons we purchased for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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, compared to $170.7 million and $185.1 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. The increase in cost of coal sales for the forecast period as compared to the year ended December 31, 2009 and the twelve months ended March 31, 2010 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, compared to $29.20 and $29.56 for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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, compared to $19.5 million and $18.8 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. This increase is primarily attributable to more tons of coal being purchased in the forecast period as compared to the year ended December 31, 2009


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and the twelve months ended March 31, 2010, 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, compared to $36.79 and $31.65 for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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, compared to approximately $25.9 million and $29.0 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. This increase is primarily due to the full year impact of increased depletion as a result 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, compared to approximately $13.2 million and $13.7 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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 the year ended December 31, 2009 and the twelve months ended March 31, 2010 due to $1.6 million of non-recurring expenses associated with the Phoenix Coal acquisition and $1.0 million of legal fees incurred in renegotiating our existing credit facility in connection with that acquisition.
 
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, compared to the aggregate of $6.4 million we received in the year ended December 31, 2009 and the $4.8 million we received for the twelve months ended March 31, 2010. 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 the year ended December 31, 2009 and the twelve months ended March 31, 2010.
 
Financing.  We forecast interest expense of approximately $7.1 million for the twelve months ending June 30, 2011, compared to approximately $6.5 million and $7.2 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. 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 $96.5 million under our existing credit facility with a portion of the proceeds from the offering;
 
  •     we will borrow approximately $101.1 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 of     % for the year ended December 31, 2009 and     % for the twelve months ended March 31, 2010 under our existing credit facility; and
 
  •     we will maintain a low cash balance.
 
Capital Expenditures.  We forecast capital expenditures for the twelve months ending June 30, 2011 based on the following assumptions:
 
  •     Our estimated reserve replacement expenditures for the forecast period are $5.6 million for the twelve months ending June 30, 2011, compared to approximately $3.1 million and $3.5 million of actual reserve replacement expenditures for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. Our estimated other maintenance capital expenditures for the forecast period are $26.6 million for the twelve months ending June 30, 2011, compared to


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  approximately $25.5 million and $23.8 million of actual other maintenance capital expenditures for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. These increases are 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 $33.5 million and $35.7 million of actual capital expenditures for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively, that we would have classified as expansion capital expenditures if we had distinguished between expansion capital expenditures and other capital expenditures during those periods. Of the $33.5 million of expansion capital expenditures for the year ended December 31, 2009, approximately $28.7 million was attributable to the Phoenix Coal acquisition and approximately $4.8 million was attributable to the purchase of other additional coal reserves. Of the $35.7 million of expansion capital expenditures for the twelve months ended March 31, 2010, approximately $28.7 million was attributable to the Phoenix Coal acquisition and approximately $7.0 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 in order 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 in order 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 being paid from “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
 
  •     an amount equal to the amount of accounts receivable that we distributed to our general partner, C&T Coal, AIM Oxford and the participants in our LTIP that hold our common units, immediately prior to the closing of this offering; plus
 
  •     all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below); plus
 
  •     working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus
 
  •     cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus
 
  •     cash distributions paid on equity issued by us (including incremental distributions on incentive distribution rights) to pay the interest on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less
 
  •     all of our operating expenditures (as defined below) after the closing of this offering and the completion of the transactions described in “Summary — The Transactions”; 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 other than working capital 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 the contract).
 
Working capital borrowings are generally borrowings that are made after the closing of the transactions described under “Summary — The Transactions” under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to


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partners and with the intent of the borrower to repay such borrowers within 12 months. If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.
 
We define operating expenditures as the sum of (a) estimated reserve replacement expenditures and (b) all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses to our general partner, repayments of working capital borrowings, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts, actual maintenance capital expenditures other than actual reserve replacement 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:
 
  •     actual repayments of working capital borrowings, if such working capital borrowings were not repaid within twelve months and were previously deemed to have been repaid at the end of such twelve month period;
 
  •     payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;
 
  •     expansion capital expenditures;
 
  •     payment of transaction expenses (including taxes) relating to interim capital transactions;
 
  •     distributions to partners;
 
  •     actual reserve replacement expenditures; or
 
  •     non-pro rata repurchases of units made with the proceeds of an interim capital transaction.
 
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. Our partnership agreement divides maintenance capital expenditures into two categories — reserve replacement expenditures and other maintenance capital expenditures. Examples of reserve replacement expenditures include capital expenditures associated with the replacement of 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. Examples of other maintenance capital expenditures include capital expenditures associated with the replacement of equipment.
 
Because our reserve replacement expenditures can be irregular, the amount of our actual reserve replacement 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 reserve replacement expenditures from operating surplus.
 
Our partnership agreement requires that an estimate of the average quarterly reserve replacement expenditures and the actual amount of other maintenance capital expenditures be subtracted from operating surplus each quarter. The amount of estimated reserve replacement 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, such as a major acquisition, that is likely to result in a material adjustment to the amount of our reserve replacement expenditures on a long-term basis. 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 reserve replacement expenditures and other maintenance capital expenditures for the forecast period ending June 30, 2011, please read “Cash Distribution Policy and Restrictions on Distributions.”


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The use of estimated reserve replacement expenditures in calculating operating surplus will have the following effects:
 
  •     it will reduce the risk that reserve replacement expenditures in any one quarter will be large enough to render operating surplus less than the minimum 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 reserve replacement 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), and (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 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


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  of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units 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 reserve replacement 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 on or after June 30, 2011:
 
  •     distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $           (150.0% of the annualized minimum quarterly distribution) for the immediately preceding four-quarter period;
 
  •     the adjusted operating surplus (as defined below) generated during the immediately preceding four-quarter period equaled or exceeded the sum of $           (150.0% of the annualized 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 thereafter 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
 
  •     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 for a period consists of:
 
  •     operating surplus (excluding the first bullet of the definition) generated with respect to that period; less
 
  •     any net increase in working capital borrowings with respect to such period; less
 
  •     any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •     any net decrease in working capital borrowings with respect to such period; plus


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  •     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.
 
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 in order 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.
 
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


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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.
 
                             
            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.


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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 quarter in 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;
 
  •     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


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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
    Common
    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 available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $          .
 
                                                             
          Cash
                               
          Distributions
    Cash Distributions to General Partner After Reset  
          to
          2.0%
                   
    Quarterly
    Common
          General
    Incentive
             
    Distribution Per
    Unitholders
    Common
    Partner
    Distribution
          Total
 
    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 $                                                    
                                                             
                $       $       $       $       $       $    
                                                             


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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, 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.
 
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%


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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;
 
  •     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;


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  •     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 85% to the unitholders, pro rata, and 15% 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 75% to the unitholders, pro rata, and 25% 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.
 
Manner of Adjustments for Losses
 
If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, 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.


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


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SELECTED HISTORICAL 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 as of August 23, 2007 and 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 included elsewhere in this prospectus. The selected historical consolidated financial data presented as of and for the quarters ended March 31, 2009 and 2010 are derived from our unaudited condensed historical consolidated financial statements included elsewhere in this prospectus.
 
The selected pro forma consolidated financial data presented as of and for the year ended December 31, 2009 and as of and for the quarter ended March 31, 2010 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 March 31, 2010. The unaudited pro forma consolidated statements of operations for the year ended December 31, 2009 assume the Phoenix Coal acquisition, this offering and the transactions related to this offering occurred as of January 1, 2009. The unaudited pro forma consolidated statements of operations for the quarter ended March 31, 2010 assume 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 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.
 


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                                                        Pro Forma Oxford
 
    Oxford Mining Company
      Oxford Resource Partners, LP
      Resource Partners, LP
 
    (Predecessor)       (Successor)       (Successor)  
                Period
      Period
                                       
                from
      from
                                       
    Year
    Year
    January 1,
      August 24,
    Year
    Year
                  Year
    Quarter
 
    Ended
    Ended
    2007 to
      2007 to
    Ended
    Ended
                  Ended
    Ended
 
    December 31,
    December 31,
    August 23,
      December 31,
    December 31,
    December 31,
    Quarter Ended March 31,       December 31,
    March 31,
 
    2005     2006     2007       2007     2008     2009     2009     2010       2009     2010  
                                          (unaudited)       (unaudited)  
    (in thousands, except per ton amounts)  
Statement of Operations Data:
                                                                                   
Revenues:
                                                                                   
Coal sales
          $ 141,440     $ 96,799       $ 61,324     $ 193,699     $ 254,171     $ 67,377     $ 76,756       $ 312,490     $ 76,756  
Transportation revenue
            27,771       18,083         10,204       31,839       32,490       8,660       9,530         37,221       9,530  
Royalty and non-coal revenue
            6,643       3,267         1,407       4,951       7,183       2,402       1,774         7,183       1,774  
                                                                                     
Total revenues
            175,854       118,149         72,935       230,489       293,844       78,439       88,060         356,894       88,060  
Costs and expenses:
                                                                                   
Cost of coal sales (excluding DD&A, shown separately)
            106,657       70,415         40,721       151,421       170,698       40,825       55,186         214,662       55,186  
Cost of purchased coal
            22,159       17,494         9,468       12,925       19,487       8,505       7,859         29,792       7,859  
Cost of transportation
            27,771       18,083         10,204       31,839       32,490       8,660       9,530         37,221       9,530  
Depreciation, depletion, and amortization
            12,396       9,025         4,926       16,660       25,902       5,688       8,777         31,424       8,777  
Selling, general and administrative expenses
            2,097       3,643         2,114       9,577       13,242       3,101       3,535         25,735       3,457  
                                                                                     
Total costs and expenses
            171,080       118,660         67,433       222,422       261,819       66,779       84,887         338,834       84,809  
                                                                                     
Income (loss) from operations
            4,774       (511 )       5,502       8,067       32,025       11,660       3,173         18,060       3,251  
Interest income
            30       26         55       62       35       11       1         39       1  
Interest expense
            (3,672 )     (2,386 )       (3,498 )     (7,720 )     (6,484 )     (1,123 )     (1,833 )       (7,669 )     (2,016 )
Gain from purchase of business(1)
                                      3,823                     3,823        
                                                                                     
Net income (loss)
            1,132       (2,871 )       2,059       409       29,399       10,548       1,341         14,253       1,236  
Less: Net income attributable to noncontrolling interest
                  (682 )       (537 )     (2,891 )     (5,895 )     (1,165 )     (1,628 )       (5,895 )     (1,628 )
                                                                                     
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
          $ 1,132     $ (3,553 )     $ 1,522     $ (2,482 )   $ 23,504     $ 9,383     $ (287 )     $ 8,358     $ (392 )
                                                                                     
Statement of Cash Flows Data:
                                                                                   
Net cash provided by (used in):
                                                                                   
Operating activities
          $ 16,236     $ 17,634       $ (8,519 )   $ 33,992     $ 37,183     $ 10,502     $ 8,341                    
Investing activities
            (13,547 )     (16,619 )       (98,745 )     (23,942 )     (49,528 )     (7,482 )     (10,280 )                  
Financing activities
            (2,548 )     (234 )       106,724       4,494       532       2,442       (137 )                  
Other Financial Data:
                                                                                   
Adjusted EBITDA(2)
          $ 17,170     $ 7,832       $ 7,961     $ 21,533     $ 50,799     $ 16,292     $ 10,001       $ 37,800     $ 10,079  
Reserve replacement expenditures(3)
            3,881       1,297         163       2,526       3,077       61       528         3,077       528  
Other maintenance capital expenditures(3)
            9,665       11,305         4,421       25,321       25,542       6,715       4,995         25,542       4,995  
Distributions
            n/a       n/a               12,503       13,407       2,523       2,818         n/a       n/a  
Balance Sheet Data (at period end):(4)
                                                                                   
Cash and cash equivalents
  $ 252     $ 392     $ 1,175       $ 635     $ 15,179     $ 3,366     $ 20,641     $ 1,290               $ 34,128  
Trade accounts receivable
    21,979       16,826       18,396         17,547       21,528       24,403       23,196       29,838                 2,000  
Inventory
    3,884       3,977       4,824         4,655       5,134       8,801       6,584       10,390                 10,390  
Property, plant and equipment, net
    47,428       48,001       54,510         106,408       112,446       149,461       117,031       147,949                 147,949  
Total assets
    85,099       80,533       90,893         146,774       171,297       203,363       184,982       212,917                 221,072  
Total debt (current and long-term)
    46,091       43,697       43,165         75,529       83,977       95,711       91,799       98,432                 103,057  
Operating Data:
                                                                                   
Tons of coal produced
            3,913       2,693         1,634       5,089       5,846       1,396       1,806         7,221       1,806  
Tons of coal purchased
            962       641         305       434       530       192       258         885       258  
Tons of coal sold
            4,872       3,333         1,938       5,528       6,311       1,559       2,036         8,051       2,036  
Average sales price per ton(5)
          $ 29.03     $ 29.04       $ 31.64     $ 35.04     $ 40.27     $ 43.23     $ 37.71       $ 38.81     $ 37.71  
Cost of coal sales per ton produced(6)
          $ 27.26     $ 26.15       $ 24.92     $ 29.75     $ 29.20     $ 29.25     $ 30.56       $ 29.56     $ 30.56  
Cost of purchased coal per ton(7)
          $ 23.03     $ 27.29       $ 31.08     $ 29.81     $ 36.79     $ 44.32     $ 30.51       $ 33.66     $ 30.51  
 
 
(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 ended 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
 
    Oxford Mining Company
      Oxford Resource Partners, LP
      Resource Partners, LP
 
    (Predecessor)       (Successor)       (Successor)  
          Period
      Period
                                       
          from
      from
                                       
          January 1,
      August 24,
                                       
    Year Ended
    2007 to
      2007 to
    Year Ended
    Year Ended
                  Year Ended
    Quarter Ended
 
    December 31,
    August 23,
      December 31,
    December 31,
    December 31,
    Quarter Ended March 31,       December 31,
    March 31,
 
    2006     2007       2007     2008     2009     2009     2010       2009     2010  
                                    (unaudited)       (unaudited)  
    (in thousands)  
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     $ 9,383     $ (287 )     $ 8,358     $ (392 )
PLUS:
                                                                           
Depreciation, depletion and amortization
    12,396       9,025         4,926       16,660       25,902       5,688       8,777         31,424       8,777  
Interest expense
    3,672       2,386         3,498       7,720       6,484       1,123       1,833         7,669       2,016  
Non-cash equity compensation expense
                  25       468       472       109       304         472       304  
LESS:
                                                                           
Interest income
    30       26         55       62       35       11       1         39       1  
Amortization of below-market coal sales contracts
                  1,955       771       1,705             625         6,261       625  
Gain from purchase of business
                              3,823                     3,823        
                                                                             
Adjusted EBITDA
  $ 17,170     $ 7,832       $ 7,961     $ 21,533     $ 50,799     $ 16,292     $ 10,001       $ 37,800     $ 10,079  
                                                                             
 
(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. Our partnership agreement divides maintenance capital expenditures into two categories — reserve replacement expenditures and other maintenance capital expenditures. Examples of reserve replacement expenditures include capital expenditures associated with the replacement of 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. Examples of other maintenance capital expenditures include capital expenditures associated with the replacement of equipment. 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 reserve replacement expenditures and which of them would have been classified as other 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 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


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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 97.6%, 93.0%, 71.4% and 39.6%, 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 first quarter of 2010, our largest mine represented 12.6% 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.
 
During 2009 and the first quarter of 2010, we produced 5.8 million tons and 1.8 million tons of coal, respectively. During the fourth quarter of 2009 and the first quarter of 2010, we produced 0.4 million tons from the reserves we acquired in western Kentucky from Phoenix Coal on September 30, 2009. Based on our coal production for the first quarter of 2010, our annualized coal production for 2010 would be 7.2 million tons. During 2009 and the first quarter of 2010, we sold 6.3 million tons and 2.0 million tons of coal, respectively, including 0.5 million tons and 0.3 million tons of purchased coal, respectively. 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 and the first quarter of 2010, we generated revenues of approximately $293.8 million and $88.1 million, respectively, net income (loss) attributable to our unitholders of approximately $23.5 million and $(0.3) million, respectively, and Adjusted EBITDA of approximately $50.8 million and $10.0 million, respectively. 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.


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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;
 
  •     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:
 
                                                   
     
     
    Oxford Mining
     
    Company
    Oxford Resource Partners, LP
    (Predecessor)     (Successor)
          Period
               
          from
               
    Period from
    August 24,
  Year
  Year
  Quarter
  Quarter
    January 1,
    2007 to
  Ended
  Ended
  Ended
  Ended
    2007 to August 23,
    December 31,
  December 31,
  December 31,
  March 31,
  March 31,
    2007     2007   2008   2009   2009   2010
    (tons in thousands)
Tons of coal produced
    2,693         1,634       5,089       5,846       1,396       1,806  
Tons of coal purchased
    641         305       434       530       192       258  
Tons of coal sold
    3,333         1,938       5,528       6,311       1,559       2,036  
Tons sold under long-term
    96.6 %       98.9 %     93.8 %     97.8 %     92.8 %     96.3 %
contracts(1)
                                                 
Average sales price per ton
  $ 29.04       $ 31.64     $ 35.04     $ 40.27     $ 43.23     $ 37.71  
 
 
(1) 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


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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.
 
The following table provides summary information for the dates indicated relating to our cost of coal sales per ton produced:
 
                                                   
     
     
    Oxford Mining
     
    Company
    Oxford Resource Partners, LP
    (Predecessor)     (Successor)
    Period from
    Period from
               
    January 1,
    August 24,
               
    2007 to
    2007 to
  Year Ended
  Year Ended
  Quarter Ended
  Quarter Ended
    August 23,
    December 31,
  December 31,
  December 31,
  March 31,
  March 31,
    2007     2007   2008   2009   2009   2010
    (tons in thousands)
Average sales price per ton
  $ 29.04       $ 31.64     $ 35.04     $ 40.27     $ 43.23     $ 37.71  
Cost of coal sales per ton
  $ 26.15       $ 24.92     $ 29.75     $ 29.20     $ 29.25     $ 30.56  
Tons of coal produced
    2,693         1,634       5,089       5,846       1,396       1,806  
 
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. During the first quarter of 2010, 37.4% of the 5.5 million gallons of diesel fuel we purchased was delivered under fixed price forward contracts. In addition, approximately 61.4% and 67.5% of the tons we delivered under our long-term coal sales contracts during 2009 and the first quarter of 2010, respectively, 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 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.


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We evaluate our cost of purchased coal on a per ton basis. For the year ended December 31, 2009 and the first quarter of 2010, we sold 0.5 million tons and 0.3 million tons of purchased coal, respectively. The following table provides summary information for the dates indicated for our cost of purchased coal per ton and the tons of purchased coal:
 
                                                           
     
     
    Oxford Mining
     
    Company
    Oxford Resource Partners, LP
    (Predecessor)     (Successor)
    Period from
    Period from
                   
    January 1,
    August 24,
                   
    2007 to
    2007 to
  Year Ended
  Year Ended
  Quarter Ended
  Quarter Ended
   
    August 23,
    December 31,
  December 31,
  December 31,
  March 31,
  March 31,
   
    2007     2007   2008   2009   2009   2010    
    (tons in thousands)
Average sales price per ton
  $ 29.04       $ 31.64     $ 35.04     $ 40.27     $ 43.23     $ 37.71          
Cost of purchased coal per ton
  $ 27.29       $ 31.08     $ 29.81     $ 36.79     $ 44.32     $ 30.51          
Tons of coal purchased
    641         305       434       530       192       258          
 
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.
 
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 97.6%, 93.0%, 71.4% and 39.6%, respectively, of our 2010 estimated coal sales of 8.5 million tons. During 2010, 2011, 2012 and 2013, we have committed to deliver 8.3 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 63.2%.
 
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, 65%, 80%, 91% 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


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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.”
 
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 with a major customer 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 first quarter of 2010 by 29%, or 0.4 million tons (1.6 million tons on an annualized basis), compared to the first quarter of 2009.
 
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 one-time increase in the price per ton of coal for 2009 along with inflation adjusters and certain cost pass through provisions for the complete term of the contract, which expires at the end of 2012. This price increase contributed $13.25 million to revenues and Adjusted EBITDA in 2009.
 
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


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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.
 
  •     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 results of our predecessor’s operations for the period from January 1, 2007 to August 23, 2007, which we refer to as the 2007 Predecessor Period, and our operating results for the period from August 24, 2007 to December 31, 2007, which we refer to as the 2007 Successor Period, are comparable to our results of operations for the year ended December 31, 2008, except to the extent noted above.
 
Summary
 
The following table presents certain of our historical consolidated financial data and that of our accounting predecessor, Oxford Mining Company, for the periods indicated. The following table should be read in conjunction with “Selected Historical and Pro Forma Consolidated Financial and Operating Data.”
 
Adjusted EBITDA is a non-GAAP financial measure that we use in analyzing the financial performance of 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, DD&A, 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 net income (loss) attributable to our unitholders, its most comparable measure established in accordance with GAAP.
 


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    Oxford Mining
         
    Company
      Oxford Resource Partners, LP
 
    (Predecessor)       (Successor)  
    Period from
      Period from
                         
    January 1,
      August 24,
                         
    2007 to
      2007 to
    Year Ended
    Year Ended
    Quarter Ended
    Quarter Ended
 
    August 23,
      December 31,
    December 31,
    December 31,
    March 31,
    March 31,
 
    2007       2007     2008     2009     2009     2010  
    (in thousands)  
Statement of Operations Data:
                                                 
Revenues:
                                                 
Coal sales
  $ 96,799       $ 61,324     $ 193,699     $ 254,171     $ 67,377     $ 76,756  
Transportation revenue
    18,083         10,204       31,839       32,490       8,660       9,530  
Royalty and non-coal revenue
    3,267         1,407       4,951       7,183       2,402       1,774  
                                                   
Total revenues
    118,149         72,935       230,489       293,844       78,439       88,060  
Costs and expenses:
                                                 
Cost of coal sales (excluding DD&A, shown separately)
    70,415         40,721       151,421       170,698       40,825       55,186  
Cost of purchased coal
    17,494         9,468       12,925       19,487       8,505       7,859  
Cost of transportation
    18,083         10,204       31,839       32,490       8,660       9,530  
Depreciation, depletion, and amortization
    9,025         4,926       16,660       25,902       5,688       8,777  
Selling, general and administrative expenses
    3,643         2,114       9,577       13,242       3,101       3,535  
                                                   
Total costs and expenses
    118,660         67,433       222,422       261,819       66,779       84,887  
Income from operations
    (511 )       5,502       8,067       32,025       11,660       3,173  
Interest income
    26         55       62       35       11       1  
Interest expense
    (2,386 )       (3,498 )     (7,720 )     (6,484 )     (1,123 )     (1,833 )
Gain from purchase of business(1)
                        3,823              
                                                   
Net income (loss)
    (2,871 )       2,059       409       29,399       10,548       1,341  
Net income attributable to noncontrolling interest
    (682 )       (537 )     (2,891 )     (5,895 )     (1,165 )     (1,628 )
                                                   
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (3,553 )     $ 1,522     $ (2,482 )   $ 23,504     $ 9,383     $ (287 )
                                                   
Other Financial Data:
                                                 
Adjusted EBITDA(2)
  $ 7,832       $ 7,961     $ 21,533     $ 50,799     $ 16,292     $ 10,001  
 
 
(1) On September 30, 2009, we acquired all of the active western Kentucky surface 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 ended December 31, 2009.
 
(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 included in our existing credit facility; and
 
• our ability to fund capital expenditure projects from operating cash flow.

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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:
 
                                                   
     
         
    Oxford Mining
         
    Company
      Oxford Resource Partners, LP
 
    (Predecessor)       (Successor)  
    Period from
      Period from
                         
    January 1,
      August 24,
                         
    2007 to
      2007 to
    Year Ended
    Year Ended
    Quarter Ended
    Quarter Ended
 
    August 23,
      December 31,
    December 31,
    December 31,
    March 31,
    March 31,
 
    2007       2007     2008     2009     2009     2010  
    (in thousands)  
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
  $ (3,553 )     $ 1,522     $ (2,482 )   $ 23,504     $ 9,383     $ (287 )
PLUS:
                                                 
Depreciation, depletion, and amortization
    9,025         4,926       16,660       25,902       5,688       8,777  
Interest expense
    2,386         3,498       7,720       6,484       1,123       1,833  
Non-cash equity compensation expense
            25       468       472       109       304  
LESS:
                                                 
Interest income
    26         55       62       35       11       1  
Amortization of below-market coal sales contracts
            1,955       771       1,705             625  
Gain from purchase of business
                        3,823              
                                                   
Adjusted EBITDA
  $ 7,832       $ 7,961     $ 21,533     $ 50,799     $ 16,292     $ 10,001  
                                                   
 
Quarter Ended March 31, 2010 Compared to Quarter Ended March 31, 2009
 
Overview.  Our coal production increased 29.4% to 1.8 million tons in the first quarter of 2010 compared to 1.4 million tons in the first quarter of 2009. Our tons sold increased 30.6% to 2.0 million tons in the first quarter of 2010 compared to 1.6 million tons in the first quarter of 2009. Although our tons sold increased, our average sales price per ton in the first quarter of 2010 decreased 12.8%, or $5.52 per ton, compared to the first quarter of 2009. Our total revenues increased 12.3% to $88.1 million in the first quarter of 2010 compared to $78.4 million for the first quarter of 2009. We generated a net loss attributable to our unitholders in the first quarter of 2010 of $0.3 million compared to net income attributable to our unitholders of $9.4 million in the first quarter of 2009. Our Adjusted EBITDA decreased 38.6% to $10.0 million in the first quarter of 2010 from $16.3 million in the first quarter of 2009. As a result of a non-recurring price increase in 2009 from a major customer, our Adjusted EBITDA for 2009 increased by $4.3 million. Excluding this price increase, our Adjusted EBITDA for the first quarter of 2010 would have decreased by 20% compared to the first quarter of 2009.
 
Coal Production.  Our tons of coal produced increased 29.4% to 1.8 million tons in the first quarter of 2010 from 1.4 million tons in the first quarter of 2009. This increase was primarily due to the inclusion of coal we produced in the first quarter of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009.


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Sales Volume.  Our tons of coal sold increased 30.6% to 2.0 million tons in the first quarter of 2010 from 1.6 million tons in the first quarter of 2009. This increase was primarily attributable to the 0.6 million tons of coal we sold in the first quarter of 2010 at our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009, partially offset by a 0.1 million ton reduction in coal sales to our industrial customers.
 
Average Sales Price Per Ton.  Our average sales price per ton decreased 12.8% to $37.71 in the first quarter of 2010 from $43.23 in the first quarter of 2009. This $5.52 per ton decrease was primarily the result of a non-recurring price increase during 2009 from a major customer. In December of 2008, we agreed to amend a long term coal sales contract with a major customer that resulted in a one year price increase. The expiration of this non-recurring price increase accounts for $2.79 of the $5.52 per ton price decrease that we experienced between the first quarter of 2009 and the first quarter of 2010. The balance of this decrease was due to the effect of the lower priced legacy coal sales contracts that we assumed in the Phoenix Coal acquisition.
 
Coal Sales Revenue.  Our coal sales revenue for the first quarter of 2010 increased by $9.4 million, or 13.9%, compared to the first quarter of 2009. This increase is primarily attributable to coal sales from our Muhlenberg County complex that we acquired in the Phoenix Coal acquisition. However, this increase was partially offset by lower coal sales to our industrial customers during the first quarter of 2010 and the inclusion in the first quarter of 2009 of $4.3 million of revenue relating to the non-recurring price increase discussed above.
 
Royalty and Non-Coal Revenue.  In June 2005, we sold our underground mining operations at the Tusky mining complex and subleased our related underground coal reserves to the purchaser in exchange for an overriding royalty. Our overriding royalty is equal to a percentage of the sales price our sublessee receives for the coal produced from our underground coal reserves. Our sublessee is also obligated to pay the tonnage based royalty that we owe to the lessor of our underground coal reserves. Our royalty and non-coal revenue includes our overriding royalty revenue from our Tusky mining complex, revenue from the sale of limestone that we recover in connection with our coal mining operations and various fees we receive for performing services for others. Our royalty and non-coal revenue declined to $1.8 million in the first quarter of 2010 from $2.4 million during the first quarter of 2009. This decline was primarily attributable to a decrease of $0.9 million in the royalty revenue in the first quarter of 2010 partially offset by an increase in service fees for providing earth moving services. The decrease in royalty revenue was due to lower sales prices and volumes associated with our underground coal reserves that are mined by a third party.
 
Cost of Coal Sales (Excluding DD&A).  Cost of coal sales (excluding DD&A) increased 35.2% to $55.2 million in the first quarter of 2010 from $40.8 million in the first quarter of 2009. This increase was primarily attributable to the increase of 29.4% in our tons produced and higher costs per ton at our Muhlenberg County complex that we acquired in the Phoenix Coal acquisition. Our average cost of coal sales per ton increased by 4.5% to $30.56 in the first quarter of 2010 compared to $29.25 per ton in the first quarter of 2009. Excluding our Muhlenberg County complex, our cost of coal sales per ton would have decreased by approximately 2.2% from the prior year primarily as a result of lower fuel costs and lower repair and maintenance expenses. With respect to our newly acquired Muhlenberg County complex, we began implementing plans late in the fourth quarter of 2009 to lower our production costs. However, in the first quarter of 2010 we experienced difficult mining conditions at our Schoate mine, which resulted in higher than anticipated costs. As a result, we have redeployed equipment and personnel to a new area at this mine that we can extract more efficiently.
 
Cost of Purchased Coal.  Cost of purchased coal declined 7.6% to $7.9 million in the first quarter of 2010 from $8.5 million in the first quarter of 2009. This decrease is primarily attributable to a $13.81 per ton decline in the average cost per ton of purchased coal, partially offset by an increase in volumes purchased of 0.1 million tons. Our average cost of purchased coal per ton decreased by 31.2% to $30.51 per ton in the first quarter of 2010 compared to the first quarter of 2009 due to a significant portion of our purchases in that quarter being supplied under lower priced purchase agreements that we assumed in the Phoenix Coal


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acquisition compared to a higher percentage of higher-priced spot market purchases in the first quarter of 2009.
 
Depreciation, Depletion and Amortization (DD&A).  DD&A expense in the first quarter of 2010 was $8.8 million compared to $5.7 million in the first quarter of 2009, an increase of $3.1 million. Approximately $1.9 million of this increase relates to higher depreciation expense associated with the assets we acquired in the Phoenix Coal acquisition and the remaining increase of $1.2 million relates primarily to equipment placed in service in late 2009 and the first quarter of 2010.
 
Selling, General and Administrative Expenses (SG&A).  SG&A expenses for the first quarter of 2010 were $3.5 million compared to $3.1 million for the first quarter of 2009, an increase of $0.4 million. This increase is due primarily to $0.3 million of additional administrative expenses related to our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009.
 
Transportation Revenue and Expenses.  Our transportation expenses represent the cost to transport our coal by truck or rail from our mines to our river terminals, our rail loading facilities and our customers. Our long-term coal sales contracts have these transportation costs built into the price of our coal. Our transportation revenue reflects the portion of our total revenues that is attributable to reimbursements for transportation expenses. Our transportation revenue fluctuates based on a number of factors, including the volume of coal we transport by truck or rail under those contracts and the related transportation costs. Our transportation revenues and expenses for the first quarter of 2010 increased 10% compared to the first quarter of 2009 due to higher coal sales volumes.
 
Interest Expense.  Interest expense for the first quarter of 2010 was $1.8 million compared to $1.1 million for the first quarter of 2009, an increase of $0.7 million. This increase was primarily attributable to higher effective interest rates in the first quarter of 2010 as a result of an amendment to our existing credit facility in September 2009, coupled with higher borrowings outstanding during the first quarter of 2010 due to the debt that we incurred to acquire the Phoenix Coal assets.
 
Net Income Attributable to Noncontrolling Interest.  In 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy to mine surface coal reserves purchased from CONSOL Energy. We own 51% of Harrison Resources and CONSOL Energy owns the remaining 49% indirectly through one of its subsidiaries. We manage all of the operations of, and perform all of the contract mining and marketing services for, Harrison Resources. Net income attributable to noncontrolling interest relates to the 49% of Harrison Resources that we do not own. For the first quarter of 2010, net income attributable to the noncontrolling interest was $1.6 million compared to $1.2 million for the first quarter of 2009. This increase of $0.4 million is primarily attributable to an increase of 62% in tons of coal sold by Harrison Resources in the first quarter of 2010 compared to the first quarter of 2009, partially offset by a decline in sales prices.
 
Adjusted EBITDA.  For the first quarter of 2010, Adjusted EBITDA was $10.0 million compared to $16.3 million in the first quarter of 2009. This decrease was primarily attributable to a one-time price increase for 2009 from a major customer and a combination of lower priced legacy coal contracts that we acquired in the Phoenix Coal acquisition and lower royalty revenues during the first quarter 2010. These impacts were partially offset by favorable cost of coal sales per ton for our Ohio operations and the benefit of lower cost per ton for purchased coal in the first quarter of 2010 compared to the first quarter of 2009.
 
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
 
Overview.  Our coal production increased 14.9% to 5.8 million tons in 2009 compared to 5.1 million tons in 2008. We sold 6.3 million tons of coal in 2009, an increase of 14.2% when compared to the 5.5 million tons we sold in 2008. Our average sales price per ton increased 14.9%, or $5.23 per ton, in 2009 when compared with 2008. Our total revenues for 2009 increased 27.5% to $293.8 million from $230.5 million in 2008. We generated net income attributable to our unitholders of approximately $23.5 million during 2009 compared to net loss attributable to our unitholders of $2.5 million for 2008. Our Adjusted EBITDA increased 135.9% in 2009 to $50.8 million from $21.5 million in 2008.


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Coal Production.  Our tons of coal produced increased 14.9% to 5.8 million tons in 2009 from 5.1 million tons in 2008. This increase was primarily the result of increased coal production in the fourth quarter of 2009 due to the Phoenix Coal acquisition of 0.4 million tons and higher production at certain of our other mining complexes. We increased our coal production for 2009 to match the increase in the tons that we were committed to deliver under our long-term coal sales contracts during 2009.
 
Sales Volume.  Our tons of coal sold increased 14.2% to 6.3 million tons in 2009 from 5.5 million tons in 2008. The increase in the tons sold in 2009 was primarily attributable to the 0.6 million tons of coal we sold during the fourth quarter of 2009 as a result of the Phoenix Coal acquisition and an increase in the tons we were committed to deliver under our long-term coal sales contracts in 2009 as compared with 2008.
 
Average Sales Price Per Ton.  Our average sales price per ton increased 14.9% to $40.27 in 2009 from $35.04 in 2008. This increase was primarily attributable to the amendment of a long-term coal sales contract with a major customer in December 2008. As part of this amendment, we received a one-time increase in the price per ton in 2009, which added revenue of $13.25 million.
 
Coal Sales Revenue.  Our coal sales for 2009 increased by $60.5 million, or 31.2%, over 2008. The majority of the increase, or $33.5 million, was attributable to the 14.9% improvement in our average sales price per ton for 2009 compared to 2008, of which $13.25 million related to the one-time price increase in 2009 from a major customer. In addition, $26.9 million of this increase was attributable to the 14.2% increase in our tons sold for 2009 compared to 2008.
 
Royalty and Non-Coal Revenue.  Our royalty and non-coal revenue increased to $7.2 million in 2009 from $5.0 million in 2008. This increase was primarily attributable to increases in our royalty revenue from our underground coal reserves of $3.2 million partially offset by decreases in other revenue of $1.0 million. During 2009, our royalty revenue from our underground coal reserves increased to $4.5 million from $1.3 million in 2008. This increase was attributable to significant increases in coal production and sales to third parties by the sublessee of our underground coal reserves. In 2009, our sublessee sold its underground coal production to third parties for the full year compared to 2008 when it sold its production to third parties for approximately six months.
 
Cost of Coal Sales (Excluding DD&A).  Cost of coal sales (excluding DD&A) increased 12.7% in 2009 to $170.7 million from $151.4 million in 2008. This increase was primarily attributable to the increase in our tons of coal produced, partially offset by lower operating costs per ton. During 2009, our cost of coal sales per ton produced decreased 1.9% primarily as a result of lower fuel, oil and explosives prices partially offset by higher operating lease expenses and higher contract labor costs. Our diesel fuel cost per ton of coal produced decreased from $8.47 per ton in 2008 to $6.56 per ton in 2009. Our motor and hydraulic oil cost per ton decreased from $1.17 per ton in 2008 to $0.85 per ton in 2009, and our explosives cost per ton decreased from $3.44 per ton in 2008 to $3.24 per ton in 2009. Our operating lease expenses per ton increased to $0.79 per ton in 2009 from $0.31 per ton in 2008 as we expanded our fleet of large equipment at our Cadiz and Harrison mining complexes. In addition, our contract labor costs per ton increased to $1.44 per ton in 2009 from $0.62 per ton in 2008 as a result of a full year of the costs associated with a highwall mining contractor that we retained in July 2008.
 
Cost of Purchased Coal.  Cost of purchased coal increased 50.8% in 2009 to $19.5 million from $12.9 million in 2008. This increase was primarily attributable to a $6.98 per ton increase in the average cost of purchased coal per ton and a 0.1 million ton increase in the volume of coal purchased during 2009 as compared to 2008. Our average cost of purchased coal per ton increased by 23.4% to $36.79 per ton in 2009 from $29.81 per ton in 2008. During the first quarter of 2009, we purchased a higher percentage of our purchased coal on the spot market in order to meet our coal sales obligations. For the fourth quarter of 2009, we purchased a higher percentage of our purchased coal under a long-term coal purchase contract. During 2009 the volume of coal we purchased increased by 0.1 million tons over 2008 primarily as a result of one quarter of coal purchases under the long-term coal purchase contract that we assumed in connection with the Phoenix Coal acquisition.


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Depreciation, Depletion and Amortization.  DD&A expense for 2009 was $25.9 million compared to $16.7 million for 2008, an increase of $9.2 million. Depreciation expense attributable to equipment upgrades that occurred during 2009 accounted for $7.6 million of this increase and the assets we acquired in the Phoenix Coal acquisition increased our depreciation expense by $1.8 million.
 
Selling, General and Administrative Expenses.  SG&A expenses for 2009 were $13.2 million compared to $9.6 million for 2008, an increase of $3.6 million. The increase in SG&A expenses was primarily due to increased headcount and expenses in our accounting and administrative departments in anticipation of becoming a publicly traded partnership, as well as one-time costs of $1.6 million associated with the Phoenix Coal acquisition and $1.0 million of legal fees incurred in renegotiating our existing credit facility.
 
Transportation Revenue and Expenses.  The 2.0% increase in transportation revenue in 2009 compared to 2008 was a function of the increase in tons of coal sold partially offset by lower trucking rates.
 
Interest Expense.  Interest expense for 2009 was $6.5 million compared to $7.7 million for 2008, a decrease of $1.2 million or 16.0%. The decrease in interest expense was primarily attributable to lower effective weighted average interest rates in 2009 under our existing credit facility compared to 2008 and a gain of $1.7 million on our interest rate swap in 2009. These decreases were partially offset by an increase of $1.3 million in interest expense due to the write off of capitalized financing costs as a result of an amendment in 2009 to our existing credit facility.
 
Gain from Purchase of Business.  On September 30, 2009, we acquired all of the active surface 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 one-time gain of $3.8 million for 2009.
 
Net Income Attributable to Noncontrolling Interest.  For the year ended December 31, 2009, net income attributable to the noncontrolling interest was $5.9 million compared to $2.9 million for 2008. This increase of $3.0 million was primarily attributable to an increase of 64% in tons of coal sold by Harrison Resources in 2009 compared to 2008, as well as to increased sales prices.
 
Adjusted EBITDA.  For 2009, Adjusted EBITDA was $50.8 million compared to $21.5 million for 2008. This increase was due primarily to a 14.2% increase in tons sold, a one-time price increase for 2009 from a major customer that contributed $13.25 million, higher royalty revenues and lower costs of coal sold per ton, partially offset by higher costs of purchased coal, increased SG&A expenses and higher net income attributable to noncontrolling interest.
 
Year Ended December 31, 2008 Compared to the 2007 Predecessor Period and the 2007 Successor Period
 
Overview.  We produced 5.1 million tons of coal in 2008 compared to 2.7 million tons and 1.6 million tons in the 2007 Predecessor Period and the 2007 Successor Period, respectively. We sold 5.5 million tons of coal in 2008 compared to 3.3 million tons and 1.9 million tons in the 2007 Predecessor Period and the 2007 Successor Period, respectively. Our average sales price per ton in 2008 increased 20.7%, or $6.00 per ton, when compared with the 2007 Predecessor Period and 10.7%, or $3.40 per ton, when compared with the 2007 Successor Period. Our total revenues for 2008 were $230.5 million compared to $118.1 million and $72.9 million in the 2007 Predecessor Period and the 2007 Successor Period, respectively. We had a net loss attributable to our unitholders of approximately $2.5 million during 2008 compared to a net loss attributable to our unitholders of $3.6 million for the 2007 Predecessor Period and net income attributable to our unitholders of approximately $1.5 million for the 2007 Successor Period. Our Adjusted EBITDA for 2008 was $21.5 million compared to $7.8 million and $8.0 million for the 2007 Predecessor Period and the 2007 Successor Period, respectively.
 
Coal Production.  We produced 5.1 million tons of coal in 2008 compared to 2.7 million tons and 1.6 million tons during the 2007 Predecessor Period and the 2007 Successor Period, respectively. We benefited from higher production in 2008 from reserves acquired during 2007 at our Belmont and Cadiz mining complexes and the additional reserves acquired by Harrison Resources from CONSOL during 2008. We


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increased our production in 2008 to meet the requirements of a new long-term coal sales contract which took effect in 2008.
 
Sales Volume.  We sold 5.5 million tons of coal in 2008 compared to 3.3 million tons and 1.9 million tons in the 2007 Predecessor Period and the 2007 Successor Period, respectively. Our sales volume for 2008 benefited from the increase in our coal production during 2008, but was partially offset by a decrease in tons of purchased coal.
 
Average Sales Price Per Ton.  Our average sales price per ton in 2008 increased 20.7%, or $6.00 per ton, when compared with the 2007 Predecessor Period and 10.7%, or $3.40 per ton, when compared with the 2007 Successor Period. These increases were due to the replacement of expiring long-term coal sales contracts with higher priced long-term coal sales contracts.
 
Coal Sales Revenue.  Our coal sales for 2008 were $193.7 million compared to $96.8 million and $61.3 million for the 2007 Predecessor Period and the 2007 Successor Period, respectively. The majority of the increase for 2008, or $27.9 million, was attributable to the increase in our average sales price per ton for 2008. In addition, $7.7 million of the 2008 increase was attributable to the increase in our tons of coal sold for 2008.
 
Royalty and Non-Coal Revenue.  We began receiving royalty revenues on our underground coal reserves in June 2008 as the sublessee began selling coal produced from our underground coal reserves directly to third parties. Before June 2008 we purchased, processed and sold all of the coal produced by our sublessee from our underground coal reserves and, as a result, we did not receive an overriding royalty.
 
Cost of Coal Sales (Excluding DD&A).  Cost of coal sales (excluding DD&A) was $151.4 million in 2008 compared to $70.4 million and $40.7 million for the 2007 Predecessor Period and the 2007 Successor Period, respectively. The increase for 2008 was primarily attributable to the increase in our tons of coal produced and higher operating costs. During 2008, our cost of coal sales per ton produced increased 13.8% and 19.4% when compared to the 2007 Predecessor Period and the 2007 Successor Period, respectively. These increases were primarily a result of higher fuel costs.
 
Cost of Purchased Coal.  Cost of purchased coal was $12.9 million in 2008 compared to $17.5 million and $9.5 million in the 2007 Predecessor Period and the 2007 Successor Period, respectively. The decrease for 2008 was primarily attributable to a 0.5 million ton decrease in the volume of coal we purchased during 2008 and a decrease in the average cost of purchased coal per ton in 2008 partially offset by an increase in the average cost of purchased coal per ton in 2008. The decrease in the volume of purchased coal was primarily due to the discontinuation of coal purchases from the sublessee of our underground coal reserves in June 2008. Our average cost of purchased coal per ton was $29.81 in 2008 compared to $27.29 and $31.08 in the 2007 Predecessor Period and the 2007 Successor Period, respectively.
 
Depreciation, Depletion and Amortization.  DD&A expense for 2008 was $16.7 million compared to $9.0 million and $4.9 million for the 2007 Predecessor Period and the 2007 Successor Period, respectively. The increase for 2008 was primarily the result of a full year of depreciation on the higher asset values that resulted from the new asset basis for Oxford Mining Company due to the change of control that occurred on August 24, 2007. Because a new asset basis can inhibit meaningful comparison of historical results before and after the change of control, DD&A expense for 2008 and the 2007 Successor Period are not comparable to DD&A expense for the 2007 Predecessor Period.
 
Selling, General and Administrative Expenses.  SG&A expenses for 2008 were $9.6 million compared to $3.6 million and $2.1 million for the 2007 Predecessor Period and the 2007 Successor Period, respectively. The increase for 2008 was primarily due to increases in accounting and administrative personnel expenses of $1.3 million, increases in professional fees of $1.5 million and the one-time write off of costs associated with an acquisition that we did not complete of $0.4 million.
 
Transportation Revenue and Expenses.  Transportation revenue and expenses increased in 2008 due to an increase in tons of coal sold and higher trucking costs due to increased fuel prices in 2008.


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Interest Expense.  Interest expense for 2008 was $7.7 million compared to $2.4 million and $3.5 million for the 2007 Predecessor Period and the 2007 Successor Period, respectively. The increase for 2008 was primarily attributable to an increase in our weighted average interest rates and average outstanding balances under our existing credit facility during 2008.
 
Net Income Attributable to Noncontrolling Interest.  Net income attributable to the noncontrolling interest was $2.9 million for 2008 compared to $0.7 million and $0.5 million for the 2007 Predecessor Period and the 2007 Successor Period, respectively. The increase in net income attributable to the noncontrolling interest during 2008 was primarily attributable to an increase in tons sold by Harrison Resources in 2008 as well as increases in Harrison’s average sales prices.
 
Adjusted EBITDA.  For 2008, Adjusted EBITDA was $21.5 million compared to $7.8 million and $8.0 million for the 2007 Predecessor Period and 2007 Successor Period, respectively. Our 2008 Adjusted EBITDA was attributable to higher revenues reflecting an increase in average sales price per ton and higher royalties, partially offset by higher costs of coal sold per ton, increased SG&A expenses and higher net income attributable to noncontrolling interest.
 
Liquidity and Capital Resources
 
Liquidity
 
Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in mining our reserves, as well as complying with applicable environmental laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, service our debt and pay cash distributions to our unitholders. Our primary sources of liquidity to meet these needs have been cash generated by our operations, borrowings under our existing credit facility and contributions from our partners.
 
The principal indicators of our liquidity are our cash on hand and availability under our existing credit facility. As of March 31, 2010, our available liquidity was $4.9 million, including cash on hand of $1.3 million and $3.6 million available under our existing credit facility.
 
Following the completion of this offering, we expect our sources of liquidity to include:
 
  •     our working capital;
 
  •     cash generated from operations;
 
  •     borrowing capacity under our new credit facility;
 
  •     issuances of additional partnership units; and
 
  •     debt offerings.
 
We believe that cash generated from these sources will be sufficient to meet our liquidity needs over the next 12 months, including operating expenditures, debt service obligations, contingencies and anticipated capital expenditures, and to fund our quarterly distributions to unitholders.
 
Please read “— Capital Expenditures” for a further discussion on the impact of capital expenditures on liquidity.


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Cash Flows
 
The following table reflects cash flows for the applicable periods:
 
                                                   
     
     
    Oxford Mining
                     
    Company
    Oxford Resource Partners, LP
    (Predecessor)     (Successor)
    January 1,
    August 24,
               
    2007 to
    2007 to
               
    August 23,
    December 31,
  Year Ended December 31,   Quarter Ended March 31,
    2007     2007(1)   2008   2009   2009   2010
    (in thousands)
Net cash provided by (used in):
                                                 
Operating activities
  $ 17,634       $ (8,519 )   $ 33,992     $ 37,183     $ 10,502     $ 8,341  
Investing activities
  $ (16,619 )     $ (98,745 )   $ (23,942 )   $ (49,528 )   $ (7,482 )   $ (10,280 )
Financing activities
  $ (234 )     $ 106,724     $ 4,494     $ 532     $ 2,442     $ (137 )
 
 
(1) Please read Note 1 to our historical consolidated financial statements included elsewhere in this prospectus.
 
Quarter Ended March 31, 2010 Compared to Quarter Ended March 31, 2009.  Net cash provided by operating activities was $8.3 million for the first quarter of 2010, a decrease of $2.2 million from net cash provided by operating activities of $10.5 million for the first quarter of 2010. Our lower net income attributable to our unitholders was offset by non-cash adjustments and favorable changes in assets and liabilities for the first quarter of 2010. As part of the amendment to a long term contract for one of our major customers, we received an advance payment of $13.25 million in December 2008. This advance payment resulted in reducing cash provided by changes in assets and liabilities during 2009, thus offsetting the majority of the impact of the price increase upon our net income attributable to our unit holders and cash provided from operations in 2009. The net impact of the prepayment upon the first quarter of 2010 was to provide an additional $1.5 million in cash from changes in assets and liabilities as compared to the first quarter of 2009.
 
Net cash used in investing activities was $10.3 million for the first quarter of 2010 compared to $7.5 million for the first quarter of 2009. This $2.8 million increase was primarily attributable to increased acquisitions of coal reserves in the first quarter of 2010 and an increase in restricted undistributed cash of $3.1 million relating to Harrison Resources, of which $3.0 million was distributed in early April, compared to the first quarter of 2009 when Harrison Resources made a distribution from restricted cash to its owners of $3.0 million.
 
Net cash used in financing activities was $0.1 million for the first quarter of 2010 compared to net cash provided by financing activities of $2.4 million for the first quarter of 2009. This change was primarily attributable to higher net borrowings in the first quarter of 2009 of $3.8 million, partially offset by a distribution to the noncontrolling interest holder in Harrison Resources in the first quarter of 2009 of $1.5 million.
 
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008.  Net cash provided by operating activities was $37.2 million for 2009 compared to $34.0 million for 2008. This $3.2 million increase was primarily due to the combined effects of the $26.0 million increase in net income (loss) attributable to our unitholders, the $9.2 million impact from the increase in DD&A expense, as well as higher other non-cash adjustments of $1.3 million, partially offset by a decrease in the cash provided by changes in assets and liabilities of $33.5 million. One of the major contributors to this decrease in cash provided by changes in assets and liabilities was a $13.25 million advance payment by one of our major customers in December 2008 for committed deliveries of coal in 2009, of which $11.2 million was offset against outstanding receivables in 2009.


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Net cash used in investing activities was $49.5 million in 2009 compared to $23.9 million for 2008. This $25.6 million increase was primarily attributable to the $18.3 million we spent in connection with the Phoenix Coal acquisition as well as increased purchases of coal properties in 2009 as compared to 2008.
 
Net cash provided by financing activities was $0.5 million for 2009 compared to $4.5 million for 2008. This $4.0 million decrease was primarily attributable to increased distributions to the noncontrolling interest holder in Harrison Resources during 2009 compared to 2008.
 
Year Ended December 31, 2008 Compared to the 2007 Predecessor Period and the 2007 Successor Period.  Net cash provided by operating activities was $34.0 million for 2008 compared to $17.6 million for the 2007 Predecessor Period and net cash used in operating activities of $8.5 million for the 2007 Successor Period. This change was primarily due to an increase in cash provided by changes in assets and liabilities of which $13.25 million was an advance payment by one of our major customers in December 2008 for committed deliveries of coal in 2009 and an increase associated with higher DD&A expense.
 
Our net cash provided by (used in) investing activities and financing activities for 2007 includes the impact of the transactions relating to the contribution of Oxford Mining Company to us in August 2007. Please read “— Results of Operations — Factors Affecting the Comparability of our Results of Operations,” and Note 1 to our historical consolidated financial statements included elsewhere in this prospectus.
 
Credit Facility
 
In connection with our initial public offering, we will pay off our existing credit facility and enter into a new credit facility that will include (i) a $100 million revolver and (ii) a $50 million term loan. The revolver and term loan will mature in 2013 and 2014, respectively, and borrowings will bear interest, at a variable rate per annum equal to the lesser of LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin will each be defined in the credit agreement that evidences our new credit facility). Borrowings made under our new credit facility in connection with the closing of the transactions described in “Summary — The Transactions” will be used for the purposes described in “Use of Proceeds.” We expect that borrowings under our new credit facility that are made after the closing of those transactions may be used for (i) the refinancing and repayment of certain existing indebtedness, (ii) working capital and other general partnership purposes and (iii) capital expenditures. Borrowings under our new credit facility will be secured by a first-priority lien on and security interest in substantially all of our assets. The credit agreement that evidences our new credit facility will contain customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, loans or advances, make distributions to our unitholders, make dispositions or enter into sales and leasebacks, or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. The credit agreement will also require compliance with certain financial covenant ratios, including limiting our leverage ratio (ratio of consolidated indebtedness to Adjusted EBITDA) to no greater than 2.75x and limiting our interest coverage ratio (ratio of Adjusted EBITDA to consolidated interest expense) to no less than 4.0x. In addition, we will not be permitted under the credit agreement to make capital expenditures in any fiscal year in excess of certain specified amounts.
 
The events that constitute an event of default under our new credit agreement are expected to include, among other things, the failure to pay principal and interest when due, breach of representations and warranties, failure to comply with covenants, voluntary bankruptcy or liquidation or a change of control.


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Contractual Obligations
 
We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations as of December 31, 2009 were as follows:
 
                                         
    Payments Due by Period  
          Less than
                More than
 
    Total     1 Year     1-3 Years     4-5 Years     5 Years  
    (in thousands)  
 
Long-term debt obligations(1)
  $ 105,507     $ 5,591     $ 99,916     $     $  
Other long-term debt(2)
    5,435       3,642       1,783       10        
Operating lease obligations
    18,425       6,289       12,013       123        
Fixed price diesel fuel purchase contracts
    9,446       9,446                    
Long-term coal purchase contract(3)
    83,627       14,103       29,796       19,864       19,864  
                                         
Total
  $ 222,440     $ 39,071     $ 143,508     $ 19,997     $ 19,864  
                                         
 
 
(1) Amounts relate to our existing credit facility that will be repaid in full in connection with this offering. Please read “Use of Proceeds.” Assumes a current LIBOR of 1.0% plus the applicable margin, which remains constant for all periods.
 
(2) Represents various notes payable with interest rates ranging from 4.6% to 9.25%.
 
(3) We assumed a long-term coal purchase contract as a result of the Phoenix Coal acquisition. Please read Note 17 to our historical financial statements included elsewhere in this prospectus.
 
Capital Expenditures
 
Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are those capital expenditures required to maintain or replace, including over the long term, our operating capacity, asset base or operating income. Expansion capital expenditures are those capital expenditures made to increase our long-term operating capacity, asset base or operating income. Our partnership agreement divides maintenance capital expenditures into two categories — reserve replacement expenditures and other maintenance capital expenditures. Examples of reserve replacement expenditures include the replacement of coal reserves, whether through the expansion of an existing mine or the acquisition (by lease or otherwise) of new reserves, to the extent such expenditures are incurred to maintain or replace our operating capacity, asset base or operating income. Examples of other maintenance capital expenditures include capital expenditures associated with the replacement of equipment. Examples of expansion capital expenditures include the acquisition (by lease or otherwise) of reserves, equipment or a new mine or the expansion of an existing mine, to the extent such expenditures are incurred to increase our long-term operating capacity, asset base or operating income.
 
For the year ending December 31, 2010, we expect to incur $5.2 million in reserve replacement expenditures and $26.7 million in other maintenance capital expenditures. We expect to fund maintenance capital expenditures primarily from cash generated by our operations. To the extent we incur expansion capital expenditures, we expect to fund those expenditures with the proceeds of borrowings under our new credit facility, issuance of debt and equity securities or other external sources of financings.
 
Off-Balance Sheet Arrangements
 
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, surety bonds, performance bonds and road bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.


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Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond and we typically use bank letters of credit to secure our surety bonding obligations. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral. We also post performance bonds to secure our performance of various contractual obligations and road bonds to secure our obligations to repair local roads.
 
As of March 31, 2010, we had approximately $32.4 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $7.5 million in letters of credit. As of March 31, 2010, we had approximately $12.3 million of performance bonds outstanding and $0.6 million of road bonds outstanding, none of which were secured by letters of credit.
 
Critical Accounting Policies and Estimates
 
Our preparation of financial statements in conformity with GAAP requires that we make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. We base our judgments, estimates and assumptions on historical information and other known factors that we deem relevant. Estimates are inherently subjective as significant management judgment is required regarding the assumptions utilized to calculate accounting estimates. The most significant areas requiring the use of management estimates and assumptions relate to units-of-production amortization calculations, asset retirement obligations, useful lives for depreciation of fixed assets and estimates of fair values for asset impairment purposes. Our significant accounting policies are more fully described in Note 2 to our historical consolidated financial statements included elsewhere in this prospectus. This section describes those accounting policies and estimates that we believe are critical to understanding our historical consolidated financial statements and that we believe will be critical to understanding our consolidated financial statements subsequent to this offering.
 
Inventory
 
Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of supplies, primarily spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes labor, equipment operating expenses and certain transportation and operating overhead. The stripping costs incurred in the production phase of a mine are variable production costs included in the costs of the inventory produced during the period that the stripping costs were incurred.
 
Property, Plant and Equipment
 
Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets based on the following schedule:
 
     
Buildings and tipple
  25 — 39 years
Machinery and equipment
  7 — 12 years
Vehicles
  5 — 7 years
Furniture and fixtures
  3 — 7 years
Railroad siding
  7 years
 
We acquire our reserves through purchases or leases of coal reserves. Coal reserves are recorded at fair value under purchase accounting at our formation date of August 24, 2007, or as part of the Phoenix Coal acquisition. We deplete our reserves using the units-of-production method, without residual value, on the basis of tonnage mined in relation to estimated recoverable tonnage. At December 31, 2009 and 2008, all of our reserves were attributed to mine complexes engaged in mining operations or leased to third parties. We believe that the carrying value of these reserves will be recovered. Residual surface values are classified as land and not depleted.


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Exploration expenditures are charged to operating expense as incurred, including costs related to locating coal deposits and drilling and evaluation costs incurred to assess the economic viability of such deposits.
 
Costs incurred in areas outside the boundary of known coal deposits and areas with insufficient drilling spacing to qualify as proven and probable reserves are also expensed as exploration costs. Once management determines there is sufficient evidence that the expenditure will result in the future economic benefit to the Partnership, the costs are capitalized as mine development costs. Capitalization of mine development costs continues until the mine’s production reaches intended operating levels. Amortization of these mine development costs is then initiated using the units-of-production method based upon the estimated recoverable tonnage.
 
Advance Royalties
 
A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable through a reduction in royalties payable on future production. Amortization of leased coal interests is computed using the units-of-production method over estimated recoverable tonnage.
 
Long-Lived Assets
 
We follow authoritative guidance that requires projected future cash flows from use and disposition of assets to be compared with the carrying amounts of those assets when impairment indicators are present. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount of the assets, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. No impairment triggers occurred and therefore no impairment losses were recognized during any of the years or periods presented.
 
Identifiable Intangible Assets
 
Identifiable intangible assets are recorded in other assets in the accompanying consolidated balance sheets. We capitalize costs incurred in connection with borrowings or the establishment of credit facilities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the interest method.
 
We also have recorded intangible assets and liabilities at fair value associated with certain customer relationships and below-market coal sales contracts, respectively. These balances arose from the use of purchase accounting for business combinations and so the assets and liabilities were adjusted to fair value. These intangible assets are being amortized over their expected useful lives.
 
Asset Retirement Obligation
 
Our asset retirement obligations, or AROs, arise from the SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our AROs are recorded initially at fair value. It has been our practice, and we anticipate that it will continue to be our practice, to perform a substantial portion of the reclamation work using internal resources. Hence, the estimated costs used in determining the carrying amount of our AROs may exceed the amounts that are eventually paid for reclamation costs if the reclamation work was performed using internal resources.
 
To determine the fair value of our AROs, we calculate on a mine by mine basis the present value of estimated reclamation cash flows. This process requires us to estimate the current disturbed acreage subject to reclamation, estimates of future reclamation costs and assumptions regarding the mine’s productivity. These


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cash flows are discounted at the credit-adjusted, risk free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives of our mines.
 
When the liability is initially recorded for the costs to open a new mine site, the offset is recorded to the producing mine asset. Over time, the ARO liability is accreted to its present value, and the capitalized cost is depreciated over the units-of-production for the related mine. The liability is also increased as additional land is disturbed during the mining process. The timeline between digging the mining pit and extracting the coal is relatively short; therefore, much of the liability created for active mining is expensed within a month or so of establishment because the related coal has been extracted. If the assumptions used to estimate the ARO do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than currently estimated. We review our entire reclamation liability at least annually and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from revisions to cost estimates and the quantity of disturbed acreage during the current year.
 
Income Taxes
 
As a limited partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income for financial statement purposes may differ significantly from taxable income reportable to our unitholders as a result of timing or permanent differences between financial reporting under GAAP and the regulations promulgated by the IRS.
 
Revenue Recognition
 
Revenue from coal sales is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales contract. Under the typical terms of these contracts, risk of loss transfers to the customers at the mine or port when the coal is loaded on the rail, barge or truck.
 
Freight and handling costs paid to third-party carriers and invoiced to customers are recorded as cost of transportation and transportation revenue, respectively.
 
Royalty and non-coal revenue consists of coal royalty income, service fees for providing land-fill earth moving services, commissions that we receive from a third party who sells limestone that we recover during our coal mining process, service fees for operating a coal unloading facility for a third party and fees that we receive for trucking ash for two municipal utility customers. Revenues are recognized when earned, or when the services are performed. Royalty revenue relates to the overriding royalty we receive on our underground coal reserves that we sublease to a third party mining company. By June 2008, our sublessee had completed the installation of its processing infrastructure and began to sell its coal production to other third parties.
 
Coal Sales Contracts
 
Our below-market coal sales contracts that were acquired through the Phoenix Coal acquisition and in connection with our acquisition of Oxford Mining Company in 2007 are contracts for which the prevailing market price was in excess of the contract price. The fair value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The difference between the below-market contracts’ cash flows and the cash flows at the prevailing market price is amortized into coal sales on the basis of tons shipped over the term of the respective contract.
 
Unit-Based Compensation
 
We account for unit-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Unit-based compensation expense is recorded based upon the fair value of the award at the grant date. Such costs


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are recognized as expense on a straight-line basis over the corresponding vesting period. The fair value of our LTIP units is determined based on the sale price of our limited partner units in arm’s length transactions. The unit price fair value was increased in September 2009 in connection with the Phoenix Coal acquisition where additional units were purchased by C&T Coal and AIM Oxford disproportionately to their respective ownership interests to help fund the acquisition. This resulted in C&T Coal’s previous ownership interest being diluted. We verified the reasonableness of the new valuation of our units using traditional valuation techniques for publicly traded partnerships.
 
New Accounting Standards Issued and Adopted
 
In June 2009, the FASB issued a new standard establishing the FASB Accounting Standards Codification (“Codification”) as the sole source of authoritative generally accepted accounting principles. The Codification reorganized existing U.S. accounting and reporting standards issued by the FASB and other related private sector standard setters into a single source of authoritative accounting principles arranged by topic. The Codification supersedes all existing U.S. accounting standards; all other accounting literature not included in the Codification (other than SEC guidance for publicly traded companies) is considered non-authoritative. This standard is effective for interim and annual reporting periods ending after September 15, 2009. The Codification does not change existing GAAP.
 
In September 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-06, Implementation Guidance on Accounting for Uncertainty in Income Taxes and Disclosure Amendments for Nonpublic Entities. This update addresses the need for additional implementation guidance on accounting for uncertainty in income taxes for all entities. The update clarifies that an entity’s tax status as a pass through or tax-exempt not-for-profit entity is a tax position subject to recognition requirements of the standard and therefore must use the recognition and measurement guidance when assessing their tax positions. The ASU 2009-06 updates are effective for interim and annual periods ending after September 15, 2009. The adoption of the guidance in ASU 2009-06 during the third quarter of 2009 did not have a material impact on our consolidated financial statements.
 
In May 2009, the FASB issued new guidance for accounting for subsequent events that established the accounting for and disclosure of events that occur subsequent to the balance sheet date but before financial statements are issued or are available to be issued. The standard provides guidance on management’s assessment of subsequent events and incorporates this guidance into accounting literature. The standard is effective prospectively for interim and annual periods ending after June 15, 2009. We adopted this standard for the year ended December 31, 2009 and the adoption did not impact our consolidated financial statements.
 
In December 2007, the FASB issued revised guidance on business combinations. This new guidance establishes principles and requirements for the acquirer of a business to recognize and measure in its financial statements. This amendment applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets, liabilities, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100% ownership in the acquiree. The amendment also requires expensing acquisition-related costs as incurred and establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. This guidance is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008. We have recorded the acquisition of the surface coal mining assets of Phoenix Coal dated September 30, 2009 under this revised guidance. The impact of adoption was to expense $379,000 of previously capitalized acquisition costs as of January 1, 2009.
 
In December 2007, the FASB issued new guidance on the accounting for noncontrolling ownership interests in a subsidiary and for the deconsolidation of a subsidiary. The guidance requires that noncontrolling ownership interests in consolidated subsidiaries be presented in the consolidated balance sheet within partners’ capital as a separate component from the parent’s equity as opposed to mezzanine equity. Consolidated net income will now be disclosed as the amount attributable to both the parent and the noncontrolling interests. The guidance also provides for changes in the parent’s ownership interest in a subsidiary, including transactions where control is retained and where control is relinquished; it also requires expanded disclosures


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in the consolidated financial statements that clearly identify and distinguish between the interests of the parent owners and the interests of the noncontrolling owners of a subsidiary. This guidance requires retrospective application to all periods presented, as included in our consolidated financial statements.
 
New Accounting Standards Issued and Not Yet Adopted
 
In August 2009, the FASB issued ASU 2009-05, Measuring Liabilities at Fair Value. The amendment provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the alternative valuation methods outlined in the guidance. It also clarifies that restrictions preventing the transfer of a liability should not be considered as a separate input or adjustment in the measurement of its fair value. This amendment was effective as of the beginning of interim and annual reporting periods that begin after August 27, 2009. The adoption of this guidance did not impact our consolidated financial statements.
 
In June 2009, the FASB amended guidance for the consolidation of a variable interest entity (“VIE”). This guidance updated the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. This standard also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, reconsideration was required only when specific events had occurred. This guidance also requires enhanced disclosure about an enterprise’s involvement with a VIE. The provisions of these updates are effective as of the beginning of interim and annual reporting periods that begin after November 15, 2009. We do not believe that this standard will have a material impact on our consolidated financial statements.
 
Quantitative and Qualitative Disclosures about Market Risk
 
We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks are commodity price risks and interest rate risk.
 
Commodity Price Risk
 
Historically, we have principally managed the commodity price risks from our coal sales through the use of long-term coal sales contracts of varying terms and durations, rather than through the use of derivative instruments. Please read “— Factors that Impact our Business” for more information about our long-term coal sales contracts.
 
We believe that the price risk associated with diesel fuel is significant because of possible price volatility. Taking into account full or partial diesel fuel cost pass through provisions in our long-term coal sales contracts and our fixed price forward contracts for delivery of diesel fuel, we estimate that a hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income attributable to our unitholders by $0.3 million for the year ended December 31, 2009 and by $0.1 million for the first quarter of 2010.
 
Interest Rate Risk
 
We have exposure to changes in interest rates on our indebtedness associated with our credit facility. On September 11, 2009, we entered into an interest rate cap agreement to hedge our exposure to rising interest rates during 2010. This agreement, which has an effective date of January 4, 2010 and a notional amount of $50.0 million, provides for a LIBOR interest rate cap of 2% using three-month LIBOR. LIBOR was 0.268% as of March 31, 2010. We paid a fixed fee of $85,000 for this agreement which has quarterly settlement dates and matures on December 31, 2010. At December 31, 2009 and March 31, 2010, the value of the interest rate cap was $34,000 and $1,000, respectively. These values are recorded in other assets and the mark-to-market decreases in value of $51,000 and $33,000 are recorded to interest expense in our consolidated statements of operations for the year ended December 31, 2009 and the first quarter of 2010, respectively.


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A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $0.3 million for the year ended December 31, 2009, which reflects the impact of an interest rate swap that terminated in August 2009, and by $0.1 million for the first quarter of 2010.
 
Seasonality
 
Our business has historically experienced only limited variability in its results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as blizzards or floods, can impact our ability to mine and ship our coal and our customers’ ability to take delivery of coal.


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THE COAL INDUSTRY
 
Introduction
 
Coal is an abundant natural resource that is used primarily as an efficient and affordable fuel for the generation of electric power. According to the most recent estimate of the EIA, there are approximately 929.3 billion tons of worldwide recoverable coal reserves. Approximately 262.7 billion tons, or 28.3%, of those reserves are located in the United States, more than in any other country. U.S. coal reserves represent over 200 years of domestic supply based on current production rates. Coal is also the most abundant domestic fossil fuel, accounting for approximately 94% of the nation’s fossil energy reserves.
 
Coal is ranked by heat content, with bituminous, sub-bituminous and lignite coal representing the highest to lowest heat ranking, respectively. Coal is also categorized as either steam coal or metallurgical coal. Steam coal is used by utilities and independent power producers to generate electricity and metallurgical coal is used by steel companies to produce metallurgical coke for use in blast furnaces. Steam coal comprises the vast majority of total coal resources, accounting for approximately 87% and 95% of the total global and U.S. coal production, respectively. Please read “— Special Note Regarding the EIA’s Market Data and Projections” below.
 
Industry 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. These market dynamics and trends include the following:
 
  •     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. The EIA also forecasts that coal-fired electric power generation will increase by 13.0% through 2015 and by 27.0% through 2035, with coal remaining the dominant fuel source in the future.
 
  •     Increasing demand for coal produced in Northern Appalachia and the Illinois Basin.  Coal production in Northern Appalachia and, to a greater extent the Illinois Basin began to decline after the adoption of the CAAA, which among other things, limited sulfur dioxide emissions from coal-fired electric power plants. 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. We believe that this projected increase will be driven by a combination of the continued decline in coal production in Central Appalachia and the new scrubber installations at coal-fired power plants in our primary market area. According to public announcements, approximately 18,400 megawatts of additional scrubbed generating capacity are expected to come online in our primary market area by 2017, including 4,750 megawatts in Ohio in the next three years.
 
  •     Decline in coal production in Central Appalachia.  Although Central Appalachia is currently the nation’s second largest coal production area after the PRB, the EIA forecasts that coal production in Central Appalachia 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. The combination of reserve depletion and increasing regulatory enforcement, mining costs and geologic complexity in Central Appalachia is expected to lead to substantial production declines over the long term.
 
  •     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


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  capacity in Asia, particularly in China and India. In addition, traditional coal exporting countries such as Australia, Indonesia, Colombia and South Africa have been unable to increase exports rapidly enough for a variety of reasons, including geologic and logistical issues and increased domestic consumption. Furthermore, increased international demand for higher priced metallurgical coal has resulted in certain coal from Central Appalachia and Northern Appalachia, which can serve as either metallurgical or steam coal, being drawn into the metallurgical coal export market, which further reduces supplies of steam coal from this region for domestic consumption. Because of these trends, the United States is expected to continue to be an increasingly important swing supplier of coal to the global marketplace in the near term.
 
  •     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 with that amount more than doubling to 68 million tons by 2035. In addition, through the ARRA the federal government has targeted over $1.5 billion to CCS research and another $800 million for the Clean Coal Power Initiative, a ten-year program supporting commercial application of CCS technology.
 
  •     Increasingly stringent air quality legislation will continue to impact the demand for coal.  A series of more stringent requirements related to particulate matter, ozone, mercury, sulfur dioxide, nitrogen oxides, carbon dioxide and other air emissions have been proposed or enacted by federal or state regulatory authorities in recent years. Considerable uncertainty is associated with these air quality regulations, some of which have been the subject of legal challenges in courts, and the actual timing of implementation remains uncertain. However, we believe that it is likely that additional air quality regulations ultimately will be adopted in some form at the federal or state level. While it is currently not possible to determine the impact of any such regulatory initiatives on future demand for coal, it may be materially adverse. See “Risk Factors — Risks Related to Our Business — 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 Consumption and Demand
 
The majority of coal consumed in the United States is used to generate electricity, with the balance used by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Metallurgical coal is predominately consumed in the production of metallurgical coke used in steelmaking blast furnaces. In 2009, coal-fired power plants produced approximately 45% of all electric power generation, more than natural gas and nuclear, the two next largest domestic fuel sources, combined. Steam coal used by utilities and independent power producers to generate electricity, accounted for 92% of total coal consumption in 2009.
 
In 2009, total coal consumption in the United States decreased by approximately 11% from 2008 levels, reflecting the effects of the economic recession. The drop in coal consumption was driven primarily by the reduction in electric power demand and the steep decline in natural gas prices that encouraged coal to natural gas switching among electric utilities. The decreased electric power demand was particularly apparent in the industrial sector where demand fell by an estimated 18.3% in 2009. Unusually cool summer temperatures in some areas of the country where coal is the predominant source of electric power generation also resulted in lower coal consumption.
 
Going forward, the EIA forecasts that total U.S. coal consumption will increase in 2010 by over 3% due to anticipated increases in electricity demand resulting from increased economic activity and higher natural gas prices. In addition, over the long term, the EIA forecasts in its 2010 reference case that total coal consumption will grow by 14% through 2015 and 32% through 2035, primarily due to gradual increases in coal-fired electric power generation and the introduction of coal-to-liquids plants.


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The following table sets forth actual coal consumption for 2008, estimated consumption for 2009 and 2010 and the EIA’s projected coal consumption by sector through 2035 for the periods indicated.
 
U.S. Coal Consumption by Sector
(tons in millions)
 
                                                         
                            Total
          Total
 
    Actual
    Estimate
    Estimate
    Forecast
    Growth
    Forecast
    Growth
 
    2008     2009     2010     2015     2009-2015     2035     2009-2035  
 
Electric Power
    1,042       934       961       1,044       11.7 %     1,183       26.7 %
Other Industrial
    54       44       43       54       19.1 %     51       14.6 %
Coke Plants
    22       16       22       20       28.2 %     14       (10.3 )%
Residential/ Commercial
    4       3       3       3       %     3       %
Coal-to-Liquids
                      20       n/m       68       n/m  
                                                         
Total U.S. Consumption
    1,122       997       1,029       1,141       14.4 %     1,319       32.2 %
                                                         
 
 
Source: EIA.
 
In the United States, the reliance on coal-fired generation is attributable to the abundance and low cost of coal. According to the EIA, coal is expected to remain the dominant energy source for electric power generation for the foreseeable future.
 
U.S. Scrubber Market
 
The CAAA imposed increasingly stringent regulations regarding the emissions of sulfur dioxide and nitrogen oxides. In response to these regulations, emission control technologies such as flue gas desulfurizers, also known as scrubbers, were developed to reduce emissions of sulfur dioxide. The use of scrubbers has addressed a wide array of technological and economic challenges and has become the predominant sulfur dioxide emissions control technology used by U.S. coal-fired power plants. Scrubbers have the additional benefit of being able to reduce mercury emissions. This widespread installation of scrubbers is expected to significantly increase demand for higher sulfur coal, particularly in our primary market area.
 
Nationwide, there are currently over 148,000 megawatts of scrubbed electric generating capacity, including 18,900 megawatts that were added in 2009. According to public announcements, we expect 76,200 megawatts of additional scrubbed electric generating capacity to be added by 2017. Currently, in our primary market area there are over 54,500 megawatts of scrubbed electric generating capacity. According to public announcements, we expect approximately 18,400 megawatts of additional scrubbed electric generating capacity in our primary market area to come online by 2017, including 4,750 megawatts in Ohio in the next three years. This additional scrubbed capacity represents approximately 24% of the total scrubbed capacity to be added nationwide during that period.
 
The following map of the United States shows coal-fired power plants with existing or announced scrubbers:
 
[Map to come]
 
Coal Consumption in Our Primary Market Area
 
Coal is the dominant fuel source for electric power generation in our primary market area and is expected to remain so for the foreseeable future. As shown in the table below, 69.1% of the electricity in our market area is generated by coal-fired power plants as compared to 38.2% for the rest of the United States. In addition, approximately 27.7% of coal consumption nationwide is burned by coal-fired power plants in our primary market area.


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2009 Coal-Fired Electricity Generation
 
                         
    Total
       
    Electricity
  Coal-Fired Electricity
    Generation
  Generation
    GWh   GWh   % of total
 
Ohio
    135,949       113,824       83.7 %
Indiana
    116,668       108,591       93.1 %
Pennsylvania
    218,377       104,927       48.0 %
Illinois
    193,214       90,949       47.1 %
Kentucky
    90,988       84,380       92.7 %
West Virginia
    70,774       68,136       96.3 %
Total — Our Primary Market Area
    825,970       570,807       69.1 %
Total — Rest of United States
    3,125,137       1,193,679       38.2 %
Total — United States
    3,951,107       1,764,486       44.7 %
 
 
Source: EIA.
 
U.S. Coal Production
 
Estimated total U.S. coal production in 2009 was 1.1 billion tons, a decrease of 7.7% from 2008. This decrease is due to the global economic downturn, which significantly reduced domestic demand for coal-fired electric power and led to a decline in exports. The EIA has forecasted a 6.7% increase in coal production through 2015 and an 18.7% increase through to 2035.
 
The following table sets forth historical and forecasted production statistics in each of the major U.S. coal producing regions for the periods indicated based on the EIA’s data and projections.
 
U.S. Coal Production
 
(BAR CHART)
 
 
Source: EIA.
 
Coal Producing Regions
 
Coal is mined in over half of the states in the United States, but domestic coal production is primarily attributed to one of three coal producing regions: Appalachia, the Interior and the Western region. Within those three regions, the major producing centers are Northern and Central Appalachia, the Illinois Basin in the Interior region and the PRB in the Western region. The type, quality and characteristics of coal vary by, and within each, region.


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Northern Appalachia.  Northern Appalachia includes Ohio, Pennsylvania, Maryland and northern West Virginia. The area includes reserves of bituminous coal with mid-to-high heat content (generally ranging from 10,300 to 13,000 Btu/lb) and mid-to-high sulfur content (typically ranging from 1.0% to 4.0%). Coal produced in Northern Appalachia is marketed primarily to electric utilities, industrial consumers and the export market, with some metallurgical coal marketed to steelmakers. The widespread installation of scrubbers by electric utilities is expected to significantly increase demand for high-sulfur coal from Northern Appalachia, providing a positive outlook for the area.
 
Estimated coal production in Northern Appalachia for 2009 was 121.5 million tons, a decline of 10.5% from 2008. In 2010, the EIA forecasts that coal production in Northern Appalachia will increase slightly to 122.1 million tons. The EIA forecasts that coal production in Northern Appalachia will increase by 29.2% through 2015 and by 35.7% through 2035.
 
Central Appalachia.  Central Appalachia includes eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The area includes reserves of bituminous coal with a high heat content (typically 12,000 Btu/lb or greater) and relatively low sulfur content (typically ranging from 0.5% to 1.5%). Coal produced in Central Appalachia is marketed primarily to electric utilities, with metallurgical coal marketed to steelmakers. The combination of reserve depletion and increasing regulatory enforcement, mining costs and geologic complexity in Central Appalachia is expected to lead to substantial production declines over the long term. In addition, the widespread installation of scrubbers is expected to enable higher sulfur coal from Northern Appalachia and the Illinois Basin to replace coal from Central Appalachia.
 
Estimated coal production in Central Appalachia for 2009 was 215.5 million tons, a decline of 8.0% from 2008. In 2010, the EIA estimates that production in Central Appalachia will decline by another 13.9%. The EIA forecasts that coal production in Central Appalachia will decline by 34.5% through 2015, causing total production in Central Appalachia to fall below forecasted production levels for Northern Appalachia. The EIA forecasts the coal production in Central Appalachia will decline by more than half through 2015.
 
The following map of the United States shows domestic electric generating plants that receive coal shipments from Central Appalachia:
 
[Map to come]
 
Illinois Basin.  The Illinois Basin includes western Kentucky, Illinois and Indiana. The area includes reserves of bituminous coal with a mid-level heat content (typically ranging from 10,100 to 12,600 Btu/lb) and mid-to-high sulfur content (typically ranging from 1.0% to 4.3%). Illinois Basin coal also can have high ash and chlorine content. Most of the coal produced in the Illinois Basin is used to produce electricity, with small amounts used in industrial applications. The EIA forecasts that production of high sulfur coal in the Illinois Basin, which has trended down since the early 1990s when many coal-fired plants switched to lower sulfur coal to reduce sulfur dioxide emissions after the passage of the CAAA, will rebound as existing coal-fired capacity is retrofitted with scrubbers and new coal-fired capacity with scrubbers is added. In addition, planned coal-to-liquids facilities, which are backed by state support and incentives and are indifferent to the sulfur content of coal, are poised to become substantial new consumers of Illinois Basin coal.
 
Estimated coal production in the Illinois Basin was 93.4 million tons for 2009, a decrease of 5.9% from 2008. In 2010, the EIA forecasts that coal production in the Illinois Basin will increase slightly to 97.3 million tons. The EIA forecasts that coal production in the Illinois Basin will increase by 33.1% through 2015 and by 42.8% through 2035.
 
Powder River Basin.  The PRB is located in Wyoming and Montana. In terms of production, the PRB is the dominant coal producing region in the world, with its coal-seam geology allowing for high volume, low cost surface mining. The PRB produces sub-bituminous coal with low sulfur content (typically ranging from 0.2% to 0.9%) and low level heat content (typically ranging from 8,000 to 9,500 Btu). After strong growth in production over the past 20 years, growth in demand for PRB coal is expected to moderate in the future due to the slowing demand for low sulfur, low Btu coal as scrubbers proliferate and concerns about increases in rail transportation rates and rising operating costs grow.


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Estimated coal production in the PRB was 417.7 million tons for 2009, a decrease of 7.5% from 2008. In 2010, the EIA forecasts that coal production in the PRB will increase to 434.9 million tons. The EIA forecasts that coal production in the PRB will increase by 12.6% through 2015 and by 31.9% through 2035.
 
Coal Imports and Exports
 
Almost all of the coal consumed in the United States is produced from domestic sources. Coal imports represent a small portion of domestic coal consumption, averaging only about 2% of total U.S. coal consumption. Coal is imported into the United States primarily from Colombia, Indonesia and Venezuela. Imported coal generally serves coastal states along the Gulf of Mexico and the eastern seaboard. We do not expect U.S. coal imports to increase significantly in the near term due to rising demand in Asia and infrastructure limitations in the United States.
 
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. In addition, traditional coal exporting countries such as Australia, Indonesia, Colombia and South Africa have been unable to increase exports rapidly enough for a variety of reasons, including geologic and logistical issues and increased domestic consumption. Furthermore, increased international demand for higher priced metallurgical coal has resulted in certain coal from Central Appalachia and Northern Appalachia, which can serve as either metallurgical or steam coal, being drawn into the metallurgical coal export market, which further reduces supplies of steam coal from this region for domestic consumption. Because of these trends, the United States is expected to continue to be an increasingly important swing supplier of coal to the global marketplace in the near term.
 
Coal Mining Methods
 
Coal is mined using two primary methods, underground mining and surface mining.
 
Surface Mining
 
Surface mining is generally used when coal is found relatively close to the surface, when multiple seams in close vertical proximity are being mined or when conditions otherwise warrant. Surface mining involves removing the overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life. There are four primary surface mining methods in use in Northern Appalachia and the Illinois Basin: area, contour, auger and highwall.
 
  •     Area Mining.  Area mining removes coal from broad areas where the land is relatively flat. An initial cut of overburden is removed and placed in a location that will facilitate final reclamation. After the coal is removed from the initial cut, a second cut of overburden is removed and placed in the initial cut, exposing the coal for removal in the second mine cut. This process is repeated until the mining cuts have advanced through the reserve area.
 
  •     Contour Mining.  Contour mining removes coal from more hilly terrain. Contour mining is characterized by mine cuts that follow the contour of the hill and are generally smaller than the mine cuts common in area mining. A wedge of overburden is removed along the coal outcrop on the side of a hill, forming a bench at the level of the coal. After the coal is removed, overburden from subsequent mine cuts is placed back on the bench to return the hill to its natural slope.
 
  •     Auger Mining.  Auger mining recovers coal that is uneconomic to mine by the area and contour mining methods due to the large amount of overburden overlying the coal. The auger is placed at the exposed coal face and bores into the coal seam. Pillars of undisturbed coal are left in place to support the overlying overburden.
 
  •     Highwall Mining.  Highwall mining is similar to auger mining. A highwall miner consists of a launch vehicle, push beams and a continuous miner head. This system utilizes the continuous miner to cut into the exposed coal face. The push beams contain augers or conveyor belts that transport the


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  coal back to the launch vehicle as the continuous miner advances. The launch vehicle applies hydraulic pressure on the push beams to push the continuous miner against the face as it advances into the coal seam. As in the auger mining method, pillars of undisturbed coal are left in place to support the overburden. Both the auger and highwall mining methods allow recovery of coal that would otherwise have been lost due to the depth of the coal seam below the surface.
 
Surface mining produces the majority of U.S. coal output, accounting for nearly 70% of U.S. production in 2009, with large surface mines (mines producing greater than 10 million tons per annum) contributing over 40% of the total. Productivity for surface mines in the eastern United States in 2009 averaged 3.64 tons per employee per hour.
 
Underground Mining
 
Underground mining is generally used when the coal seam is too deep to permit surface mining. There are two principal underground mining methods: room and pillar and longwall.
 
  •     Room and Pillar Mining.  In room and pillar mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment is used to cut the coal from the mining face. The room and pillar method is often used to mine smaller coal blocks or thin seams.
 
  •     Longwall Mining.  The other underground mining method commonly used in the United States is the longwall mining method. In longwall mining, a rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface.
 
Productivity for underground mines in the eastern United States in 2009 averaged 3.02 tons per employee per hour.
 
Coal Quality Characteristics
 
Coal quality is differentiated primarily by its heat content as measured in British thermal units per pound (Btu/lb). In general, coal with low moisture and ash content has high heat content. Coal with higher heat content commands higher prices because less coal is needed to generate a given quantity of electric power.
 
Coal quality is also differentiated by sulfur content. When coal is burned sulfur dioxide and other air emissions are released. Sub-bituminous coal (e.g., PRB coal) typically has lower sulfur content than bituminous coal. Coal in southern West Virginia, eastern Kentucky, Colorado and Utah, however, also generally has low sulfur content. A coal’s sulfur content can be further classified as compliance or non-compliance. Compliance coal is a term used in the United States to describe coal that, when burned, emits less than 1.2 lbs of sulfur dioxide per million Btu and complies with the requirements of the CAAA without the use of scrubbers. The primary reserves of compliance coal are found in both the PRB and Central Appalachia.
 
High sulfur coal can be burned in electric utility plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by more than 90%. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal, or by purchasing emission allowances on the open market.
 
Coal ash and chlorine content also can influence the marketability of a particular coal. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is also an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The chlorine content of coal is important to generating station operators since high levels can adversely impact boiler performance directly by both high and low temperature corrosion and indirectly by reacting with other coal impurities to cause ash fouling. Coal found in the central Illinois Basin (primarily within the state of Illinois) typically exhibits higher chlorine concentrations than the coal found in western Kentucky and Indiana.


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Transportation
 
The U.S. coal industry is dependent on the availability of a consistent and responsive transportation network connecting the various supply regions to the domestic and international markets. Railroads and barges comprise the foundation of the domestic coal distribution system, collectively handling about three-quarters of all coal shipments. Truck and conveyor systems typically move coal over shorter distances.
 
Although the purchaser typically pays the freight, transportation costs are still important to coal mining companies because the purchaser may choose a supplier largely based on the total delivered cost of coal, which includes the cost of transportation. Coal used for domestic consumption is generally sold free-on-board at the mine, or FOB mine, which means the purchaser normally bears the transportation costs. Transportation can be a large component of a purchaser’s total cost.
 
While coal can sometimes be moved by one transportation method to market, it is common for two or more modes to be used to ship coal (i.e., inter-modal movements). The method of transportation and the delivery distance greatly impact the total cost of coal delivered to the consumer.
 
Special Note Regarding the EIA’s Market Data and Projections
 
Coal industry market data and projections referred to in this section and elsewhere in this prospectus and prepared by the EIA reflect statements of what might happen in the coal industry given the assumptions and methodologies used by the EIA. Industry projections of the EIA are subject to numerous assumptions and methodologies chosen by the EIA. In addition, these projections assume that the laws and regulations in effect at the time of the projections remain unchanged and that no pending or proposed federal or state carbon emissions legislation has been enacted and that additional coal-fired power plants will be built during the period. Therefore, the EIA’s projections do not take into account potential regulation of greenhouse gas emissions pursuant to proposed or future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, or federal or additional state adoption of a greenhouse gas regulatory scheme or reductions in greenhouse gas emissions mandated by courts or through other legally enforceable mechanisms. The EIA’s projections with respect to the demand for coal may not be met, absent other factors, if comprehensive carbon emissions legislation is enacted. In addition, these projections may assume certain general economic conditions or industry conditions and commodity prices for alternative energy sources at the time of the projection that may or may not reflect actual economic or industry conditions during the forecast period, including with respect to planned and unplanned additional electricity generating capacity. The economic conditions accounted for in the EIA’s industry projections reflect existing and projected economic conditions at the time the projections were made and do not necessarily reflect current economic conditions or any subsequent deterioration of economic conditions. Actual results may differ from those results projected by the EIA, including projections related to the demand for additional electricity generating capacity, because of changes in economic conditions, laws or regulations, pricing for other energy sources, unanticipated production cuts, or because of other factors not anticipated in the EIA’s projections.


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BUSINESS
 
Overview
 
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 first quarter of 2010, our largest mine represented 12.6% 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.
 
During 2009 and the first quarter of 2010, we produced 5.8 million tons and 1.8 million tons of coal, respectively. During the fourth quarter of 2009 and the first quarter of 2010, we produced 0.4 million tons from the reserves we acquired in western Kentucky from Phoenix Coal on September 30, 2009. Based on our coal production for the first quarter of 2010, our annualized coal production for 2010 would be 7.2 million tons. During 2009 and the first quarter of 2010, we sold 6.3 million tons and 2.0 million tons of coal, respectively, including 0.5 million tons and 0.3 million tons of purchased coal, respectively. We currently have long-term coal sales contracts in place for 2010, 2011, 2012 and 2013 that represent 97.6%, 93.0%, 71.4% and 39.6%, 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 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 and the first quarter of 2010, we generated revenues of approximately $293.8 million and $88.1 million, respectively, net income (loss) attributable to our unitholders of approximately $23.5 million and $(0.3) million, respectively, and Adjusted EBITDA of approximately $50.8 million and $10.0 million, respectively. 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


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complexes, our coal production for the year ended December 31, 2009 and the first quarter of 2010 and our coal reserves as of December 31, 2009:
 
                                                             
            As of December 31, 2009
    Production for
  Production for
  Total
                   
    the Year Ended
  the Quarter Ended
  Proven &
          Average
  Average
  Primary
    December 31,
  March 31,
  Probable
  Proven
  Probable
  Heat
  Sulfur
  Transportation
Mining Complexes   2009   2010   Reserves(1)   Reserves(1)   Reserves(1)   Value   Content   Methods
        (in million tons)               (Btu/lb)   (%)    
 
Surface Mining Operations:
                                                           
Northern Appalachia (principally Ohio)
                                                           
Cadiz
    1.1       0.3       12.4       12.2       0.2       11,520       3.3     Barge, Rail
Tuscarawas County
    0.9       0.3       8.8       8.8       0.0       11,570       3.7     Truck
Belmont County
    1.3       0.3       6.6       6.3       0.3       11,510       3.7     Barge
Plainfield
    0.5       0.1       6.4       6.4       0.0       11,350       4.4     Truck
New Lexington
    0.6       0.1       4.9       4.0       0.9       11,260       4.0     Rail
Harrison(2)
    0.7       0.2       2.8       2.8       0.0       12,040       1.8     Barge, Rail, Truck
Noble County
    0.3       0.1       2.5       2.4       0.1       11,230       4.7     Barge, Truck
Illinois Basin (Kentucky)
                                                           
Muhlenberg County
    0.4 (3)     0.4       24.2       23.5       0.7       11,295       3.6     Barge, Truck
                                                             
Total Surface Mining Operations
    5.8       1.8       68.6       66.4       2.2                      
                                                             
Underground Coal Reserves:
                                                           
Northern Appalachia (Ohio)
                                                           
Tusky(4)
                    23.0       18.6       4.4       12,900       2.1      
                                                             
Total Underground Coal Reserves
                    23.0       18.6       4.4                      
                                                             
Total
                    91.6       85.0       6.6                      
                                                             
 
 
(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 “— Coal Reserves.”
 
(2) The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL Energy. 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 and the first quarter of 2010 as required by 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 “— Mining Operations — Northern Appalachia — Harrison Mining Complex.”
 
(3) Acquired from Phoenix Coal on September 30, 2009. As a result, production data for 2009 represents production from the date of acquisition through December 31, 2009.
 
(4) Please read “— 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 in exchange for an overriding royalty. We received royalty payments on 0.6 million tons and 0.1 million tons of coal produced from the Tusky mining complex during 2009 and the first quarter of 2010, respectively.


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[Map to come]
 
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. 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.
 
  •     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 utilize surface mining methods that allow us to leverage our large scale mobile equipment and experienced work force to minimize our mining costs while balancing our production with near-term coal sales commitments without incurring large start up costs. 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 part of the Phoenix Coal acquisition. We currently have 19 active surface mines that are managed as eight mining complexes, with our largest mine comprising 12.6% of our coal production during the first quarter of 2010. This diversity and focus on reserves with low regulatory risks reduce the likelihood that operational or permitting issues at any one mine will have a material impact on our business or our results of operations.
 
  •     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 the market prices. We believe our senior management’s longstanding relationships within our industry will allow us to continue to obtain long-term contracts for substantially all of our production. We believe our long-term coal sales contracts provide us with a reliable and stable revenue base, and we intend to seek cost pass through or inflation adjustment provisions in our long-term coal sales contracts to mitigate our exposure to rising costs.
 
  •     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 are focused primarily on acquisitions that are consistent with our target customer base in terms of location and coal quality. We believe this strategy will allow us to expand our presence in our primary market area, target new customers and increase our annual coal production. We believe that our existing relationships with owners of large reserve blocks and our position as the largest producer of surfaced mined coal in Ohio will allow us to acquire additional reserves in the future. 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. Please read “Cash Distribution Policy and Restrictions on Distributions — General — Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital” for additional details on how we intend to grow our reserve base and production capacity and the limitations we face in implementing this strategy.


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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 97.6%, 93.0%, 71.4% and 39.6%, respectively, of our 2010 estimated coal sales of 8.5 million tons. A majority of our estimated annual coal production for 2010 will be delivered to utilities that are investment grade. Our long-term coal sales contracts typically contain full or partial cost pass through or inflation adjustment provisions that provide some protection in rising operating cost environments. 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 substantially all of our production.
 
  •     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. As a result of the Phoenix Coal acquisition and production increases in Ohio, our coal production for the first quarter of 2010 on an annualized basis was 7.2 million tons, an increase of 24% over our actual 2009 production.
 
  •     Our mining operations are flexible and diverse.  During the first quarter of 2010, our largest mine represented 12.6% of our coal production. We currently have 19 active surface mines that are managed as eight mining complexes. This diversity reduces the risk that operational or production 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. Additionally, we have the flexibility to add mining hours to our work week, which allows us to respond to increasing customer demand and to compensate for unexpected disruptions at any one mine by increasing the production at other mines. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky, that enhance our ability to supply coal to our customers with river access from multiple mines. Our river terminals also give us access to power plants in our primary market area that receive coal by barge, which is the lowest cost coal transportation alternative.
 
  •     We are a low cost producer of coal.  We use efficient mining practices that take advantage of economies of scale and reduce operating costs per ton. For example, in Northern Appalachia we operate some of the largest mobile equipment in use east of the Mississippi River. The productive capacity of this equipment helps us to maintain low overburden removal costs and allows us to mine coal reserves that are not efficiently mineable with smaller equipment. Our use of large scale equipment, our good labor relations with our non-union workforce, the expertise of our general partner’s employees and their 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. In addition, we are in the process of deploying the same mining practices that we currently use in Ohio at the mines that we acquired as part of the Phoenix Coal acquisition.
 
  •     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


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  Basin is expected to increase by 29.2% and 33.1%, respectively, through 2015. This compares to an expected increase in total coal production in the United States of 6.7% over the same period. According to the EIA, this expected increase in coal production in Northern Appalachia and the Illinois Basin is attributable to anticipated increases in demand for high-sulfur coal from scrubbed power plants. The EIA also forecasts increased demand from consumers of Central Appalachia coal as coal production in that region continues to decline.
 
  •     Our general partner’s senior management team and key operational employees have extensive industry experience.  The members of our general partner’s 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. In addition, our general partner’s key operational employees have extensive mining experience and have been with us for an average of 22 years. We believe our general partner’s operational employees are one of the key strengths to our business because their knowledge and skills allow us to operate our mines in a safe and efficient manner.
 
  •     We have a strong safety and environmental record.  We operate some of the industry’s safest mines. Over the last four years, our MSHA reportable incident rate was on average 14.4% lower than the rate for all surface coal mines in the United States. In addition, we are committed to maintaining a system that controls and reduces the environmental impacts of mining operations. We have won numerous awards for our strong safety and environmental record. In January 2010, the West Virginia Coal Association awarded us their Surface Mine North Award for our past reclamation efforts in West Virginia. In addition, in 2008 the Appalachian Regional Reforestation Initiative awarded us their Regional Award for Excellence in Reforestation for exemplary performance using the forestry reclamation approach for reclaiming coal mined lands.
 
Our History
 
We are a Delaware limited partnership that was formed in August 2007 by AIM 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
 
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. Brian D. Barlow, Matthew P. Carbone and George E. McCown serve on the board of directors of our general partner and 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).


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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.
 
Mining Operations
 
We currently have 19 active surface mines that are managed as eight mining complexes. We define a mining complex as a group of mines that are located in close proximity to each other or that routinely sell coal to the same customer. Our transportation facilities include two river terminals and two rail loading facilities. Our mining facilities include two wash plants, six blending facilities and nine crushing facilities.
 
Our surface mining operations use area, contour, auger and highwall mining methods. Our area mining operations use truck/shovel and truck/loader equipment fleets along with large dozers. Our contour mining operations use truck/loader equipment fleets and large dozers. We own and operate seven augers and move these machines between mining complexes as needed. We currently own and utilize one Superior highwall miner at our Tuscarawas County mining complex, and a third party contractor operates one Superior highwall miner at our Belmont County mining complex. Both highwall miners are mobile and are moved among our mining complexes as necessary.
 
In Northern Appalachia we operate large electric and hydraulic shovels matched with a fleet of 240-ton haul trucks and 200-ton haul trucks, which are some of the largest in use east of the Mississippi River. We also deploy a fleet of over 65 large Caterpillar D-11 and similar class dozers. We employ preventive maintenance and rebuild programs to ensure that our equipment is well-maintained. The rebuild programs are performed by third-party contractors. We assess the equipment utilized in our mining operations on an ongoing basis and replace it with new, more efficient units on an as-needed basis.
 
Our transportation facilities include our Bellaire river terminal that is located on the Ohio River in eastern Ohio, our Cadiz rail loadout facility located on the Ohio Central Railroad near Cadiz, Ohio, our New Lexington rail facility located on the Ohio Central Railroad in Perry County, Ohio and our Island river terminal and transloading facility located on the Green River in western Kentucky. Our Bellaire river terminal, which is located on the Ohio River in Bellaire, Ohio, has an annual throughput capacity of over 4 million tons with a sustainable barge loading rate of 2,000 tons per hour. The barge harbor for this terminal can simultaneously hold up to 25 loaded barges and 30 empty barges. We control our Bellaire river terminal through a long-term lease agreement with a third party, and we have approximately six months remaining on the current term of this lease with two subsequent five year renewable terms at our option. We own our Island river terminal and transloading facility that is located on the Green River in western Kentucky. Our Island river terminal has an annual throughput capacity of approximately 3 million tons with a sustainable barge loading rate of 1,500 tons per hour.
 
Depending on coal quality and customer requirements, in most cases our coal is crushed and shipped directly from our mines to our customers. However, blending different types or grades of coal may be required from time to time to meet the coal quality and specifications of our customers. Coal of various sulfur and ash contents can be mixed or “blended” to meet the specific combustion and environmental needs of customers. Blending is typically done at one of our six blending facilities:
 
  •     our Barb Tipple blending and coal crushing facility that is adjacent to one of our customer’s power plants near Coshocton, Ohio;
 
  •     our Strasburg wash plant near Strasburg, Ohio;
 
  •     our Bellaire river terminal on the Ohio River;
 
  •     our Island river terminal on the Green River in western Kentucky;


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  •     our Stonecreek coal crushing facility located in Tuscarawas County, Ohio; and
 
  •     our Schoate wash plant located in Muhlenberg County, Kentucky.
 
[Map to come]
 
Northern Appalachia
 
We operate seven surface mining complexes in Northern Appalachia, substantially all of which are located in eastern Ohio. For the year ended December 31, 2009, our mining complexes in Northern Appalachia produced an aggregate of 5.4 million tons of steam coal and, for the first quarter of 2010, an aggregate of 1.4 million tons of steam coal. The following table provides summary information regarding our mining complexes in Northern Appalachia as of December 31, 2009 and March 31, 2010:
 
                                                     
                    Tons Produced for the
                Number
  Year Ended
   
    Transportation Facilities Utilized   Transportation
  of Active
  December 31,   Quarter Ended
Mining Complex
  River Terminal   Rail Loadout   Method(1)   Mines   2007   2008   2009   March 31, 2010
                    (in millions)
 
Cadiz
  Bellaire   Cadiz   Barge, Rail     2       1.1       1.4       1.1       0.3  
Tuscarawas County
      Truck     4       1.1       1.0       0.9       0.3  
Belmont County
  Bellaire     Barge     4       0.8       0.9       1.3       0.3  
Plainfield
      Truck     1       0.3       0.5       0.5       0.1  
New Lexington
    New Lexington   Rail     1       0.6       0.7       0.6       0.1  
Harrison(2)
  Bellaire   Cadiz   Barge, Rail, Truck     1       0.2       0.4       0.7       0.2  
Noble County
  Bellaire     Barge, Truck     2       0.2       0.2       0.3       0.1  
                                                     
Total
                15       4.3       5.1       5.4       1.4  
                                                     
 
 
(1) Barge means transported by truck to our Bellaire river terminal and then transported to the customer by barge. Rail means transported by truck to a rail facility and then transported to the customer by rail. Truck means transported to the customer by truck.
 
(2) The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL Energy. 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 and the first quarter of 2010 as required by GAAP, coal production attributable to the Harrison mining complex is presented on a gross basis assuming we owned 100% of Harrison Resources. Please read “— Harrison Mining Complex.”
 
Cadiz Mining Complex.  The Cadiz mining complex is located in Harrison County, Ohio and includes reserves located in Jefferson County, Ohio and Washington County, Pennsylvania and consists of the Daron and County Road 29 mines. We began our mining operations at this mining complex in 2000. Operations at the Cadiz mining complex target the Pittsburgh #8, Redstone #8A and Meigs Creek #9 coal seams. As of December 31, 2009, the Cadiz mining complex included 12.4 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes a coal crusher, a truck scale and the Cadiz rail loadout. Coal produced from the Cadiz mining complex is trucked either to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, or trucked to our Cadiz rail loadout facility on the Ohio Central Railroad and then transported by rail to the customer. This mining complex uses area and auger methods of surface mining. This mining complex produced 1.1 million tons and 0.3 million tons of coal for the year ended December 31, 2009 and the first quarter of 2010, respectively.
 
Tuscarawas County Mining Complex.  The Tuscarawas County mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and consists of the Stonecreek, Stillwater, Chumney and Strasburg mines. We began our mining operations at this mining complex in 2003. Operations at this mining complex target the Brookville #4, Lower Kittanning #5, Middle Kittanning #6, Upper Freeport #7 and Mahoning #7A coal seams. As of December 31, 2009, the Tuscarawas County mining complex included


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8.8 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes two coal crushers with truck scales and the Strasburg wash plant. Coal produced from the Tuscarawas County mining complex is trucked directly to our customers, our Barb Tipple blending and coal crushing facility or our Strasburg wash plant. Coal trucked to our Barb Tipple blending and coal crushing facility or our Strasburg wash plant is then transported by truck to the customer after processing is completed. This mining complex uses the area, contour, auger and highwall miner methods of surface mining. This mining complex produced 0.9 million tons and 0.3 million tons of coal for the year ended December 31, 2009 and the first quarter of 2010, respectively.
 
Belmont County Mining Complex.  The Belmont County mining complex is located in Belmont County, Ohio, and consists of the Lafferty, Boswell, Flushing and Wheeling Valley mines. We began our mining operations at this mining complex in 1999. Operations at the Belmont County mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2009, the Belmont County mining complex included 6.6 million tons of proven and probable coal reserves. Coal produced from the Belmont County mining complex is primarily transported by truck to our Bellaire river terminal on the Ohio River. Coal produced from this mining complex is crushed and blended at the Bellaire river terminal before it is loaded onto barges for shipment to our customers on the Ohio River. This mining complex uses area, contour, auger and highwall miner methods of surface mining. This mining complex produced 1.3 million tons and 0.3 million tons of coal for the year ended December 31, 2009 and the first quarter of 2010, respectively.
 
Plainfield Mining Complex.  The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and consists of the Plainfield mine. We began our mining operations at this mining complex in 1990. Operations at the Plainfield mining complex target the Middle Kittanning #6 coal seam. As of December 31, 2009, the Plainfield mining complex included 6.4 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes our Barb Tipple blending and coal crushing facility. Substantially all of the coal we produce from the Plainfield mining complex is sold to AEP. The majority of the coal produced from the Plainfield mining complex is trucked to our Barb Tipple facility for crushing and blending or directly to AEP’s Conesville generating station. Coal trucked to our Barb Tipple facility is transported by truck to AEP after processing is completed. Some of the coal production from this mining complex is trucked to our Strasburg wash plant and then transported by truck to the customer. This mining complex uses contour, auger and highwall miner methods of surface mining. This mining complex produced 0.5 million tons and 0.1 million tons of coal for the year ended December 31, 2009 and the first quarter of 2010, respectively.
 
New Lexington Mining Complex.  The New Lexington mining complex is located in Perry, Athens and Morgan Counties, Ohio, and consists of the New Lexington mine. We began our mining operations at this mining complex in 1993. Operations at the New Lexington mining complex target the Lower Kittanning #5 and Middle Kittanning #6 coal seams. As of December 31, 2009, the New Lexington mining complex included 4.9 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes a coal crusher, a truck scale and the New Lexington rail loadout. Coal produced from the New Lexington mining complex is delivered via-off highway trucks to our New Lexington rail loadout facility on the Ohio Central Railroad where it is then transported by rail to the customer. This mining complex uses the area method of surface mining. This mining complex produced 0.6 million tons and 0.1 million tons of coal for the year ended December 31, 2009 and the first quarter of 2010, respectively.
 
Harrison Mining Complex.  The Harrison mining complex is located in Harrison County, Ohio, and consists of the Harrison mine. Mining operations at this mining complex began in 2007. The Harrison mining complex is owned by Harrison Resources. We own 51% of Harrison Resources and CONSOL Energy owns the remaining 49% indirectly through one of its subsidiaries. We entered into this joint venture in 2007 to mine coal reserves purchased from CONSOL Energy. We manage all of the operations of, and perform all of the contract mining and marketing services for, Harrison Resources. Because the results of operations of Harrison Resources are included in our consolidated financial statements for the year ended December 31, 2009 and the first quarter of 2010 as required by 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.


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Since its formation in 2007, Harrison Resources has acquired 3.5 million tons of proven and probable coal reserves from CONSOL Energy. We believe that CONSOL Energy controls additional reserves in Harrison County, Ohio, that could be acquired by Harrison Resources in the future. However, CONSOL Energy has no obligation to sell those reserves to Harrison Resources, and we cannot assure you that Harrison Resources could acquire those reserves from CONSOL Energy on acceptable terms.
 
Operations at the Harrison mining complex target the Pittsburgh #8, Redstone #8A and Meigs Creek #9 coal seams. As of December 31, 2009, the Harrison mining complex included 2.8 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes a coal crusher and a truck scale. Coal produced from the Harrison mining complex is trucked to our Bellaire river terminal, our Cadiz rail loadout facility or directly to customers. Coal trucked to our Bellaire river terminal is transported to the customer by barge and coal trucked to our Cadiz rail loadout facility is transported to the customer by rail. This mining complex uses the area method of surface mining. This mining complex produced 0.7 million tons and 0.2 million tons of coal for the year ended December 31, 2009 and the first quarter of 2010, respectively.
 
Noble County Mining Complex.  The Noble County mining complex is located in Noble and Guernsey Counties, Ohio, and consists of the Long-Sears and Hall’s Knob mines. We began our mining operations at this mining complex in 2006. Operations at the Noble County mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of December 31, 2009, the Noble County mining complex included 2.5 million tons of proven and probable coal reserves. Coal produced from the Noble County mining complex is trucked to our Bellaire river terminal on the Ohio River or to our Barb Tipple facility. Coal trucked to our Bellaire river terminal is then transported by barge to the customer. Coal trucked to our Barb Tipple blending and coal crushing facility is transported by truck to the customer after processing is completed. This mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.3 million tons and 0.1 million tons of coal for the year ended December 31, 2009 and the first quarter of 2010, respectively.
 
Illinois Basin
 
We operate one surface mining complex in the Illinois Basin, which is located in western Kentucky. We acquired this operation from Phoenix Coal on September 30, 2009. For the three months that began on October 1, 2009 and ended on December 31, 2009, this mining complex produced an aggregate of 0.4 million tons of steam coal and, for the first quarter of 2010, an aggregate of 0.4 million tons of steam coal. The following table provides summary information regarding our mining complex in the Illinois Basin as of December 31, 2009 and March 31, 2010:
 
                                                 
    Transportation           Tons Produced for
   
    Facilities Utilized           the Year Ended
  Tons Produced for
    River
  Rail
  Transportation
  Number of
  December 31,
  the Quarter Ended
Mining Complex
  Terminal   Loadout   Method(1)   Active Mines   2009(2)   March 31, 2010
 
Muhlenberg County
    Island             Barge, Truck       4       0.4       0.4  
 
 
(1) Barge means transported by truck to our Island river terminal and then transported to the customer by barge. Truck means transported to customer by truck.
 
(2) Acquired in the Phoenix Coal acquisition that occurred on September 30, 2009. As a result, production data is limited to the fourth quarter of 2009.
 
Muhlenberg County Mining Complex.  The Muhlenberg County mining complex is located in Muhlenberg and McClean Counties, which is in western Kentucky, and consists of the Schoate/431, Winn, Jessup and KO mines. We began our mining operations at this mining complex in October 2009. Operations at the Muhlenberg County mining complex target the #5, #6, #9, #10, #11, #12 and #13 coal seams of the Illinois Basin. As of December 31, 2009, the Muhlenberg County mining complex included 24.2 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes the Schoate wash plant, the Winn, Jessup, and KO coal crushers and our Island river terminal. Coal produced from this mining complex is usually crushed at the mine site and then trucked to our Island river terminal on the Green River or directly to the customer. Coal trucked to our Island river terminal is then transported to the customer by barge.


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Some of the production from this mining complex is washed at our Schoate wash plant prior to being transported either by truck directly to the customer, or by truck to our Island river terminal and then transported by barge to the customer. This mining complex uses the area method of surface mining. This mining complex produced 0.4 million tons and 0.4 million tons of steam coal during the quarters ended December 31, 2009 and March 31, 2010, respectively.
 
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. Our coal reserves are 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. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or dispositions of coal properties will also change these estimates. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will changes in preparation plant processes. We maintain reserve information in secure computerized databases, as well as in hard copy. The ability to update or modify the estimates of our coal reserves is restricted to our engineering group and the modifications are documented.
 
“Reserves” are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 divides reserves between “proven (measured) reserves” and “probable (indicated) reserves,” which are defined as follows:
 
  •     “Proven (Measured) Reserves.” Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; and grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
 
  •     “Probable (Indicated) Reserves.” Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
 
As of December 31, 2009, all of our proven and probable coal reserves were “assigned” reserves, which are coal reserves that can be mined without a significant capital expenditure for mine development.
 
As of December 31, 2009, we owned 17.4% of our coal reserves and leased 82.6% of our coal reserves from various third-party landowners. The majority of our leases have terms denominated in years and we believe that the term of years will allow the recoverable coal reserves to be fully extracted in accordance with our projected mining plan. Some of our leases have an initial term denominated in years but also provide for the term of the lease to continue until exhaustion of the “mineable and merchantable” coal in the lease area so long as we comply with the terms of the lease.
 
It generally takes us from 12 to 30 months to obtain a SMCRA permit. Permits are issued for an initial five year term and must be renewed if mining is to continue after the end of the term. We submit and obtain new mining permits on a continuing basis to replace existing permits as they are depleted. Based on our current surface mining plan, we have proven and probable coal reserves with active permits that will allow us


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to mine for approximately the next three years. We do not expect to have any material delays in obtaining or renewing permits on our remaining coal reserves associated with our mining operations.
 
The following table provides information as of December 31, 2009 on the location of our operations and the amount and ownership of our coal reserves:
 
                         
    Total Tons of Proven and
    Probable Coal Reserves(1)
Mining Complex
  Total   Owned   Leased
    (in million tons)
 
Surface Mining Operations:
                       
Northern Appalachia (principally Ohio)
                       
Cadiz
    12.4       7.5       4.9  
Tuscarawas
    8.8       0.1       8.7  
Belmont County
    6.6       1.9       4.7  
Plainfield
    6.4       0.7       5.7  
New Lexington
    4.9       2.8       2.1  
Harrison(2)
    2.8       2.8        
Noble County
    2.5       0.1       2.4  
                         
Total Northern Appalachia
    44.4       15.9       28.5  
                         
Illinois Basin (Kentucky)
                       
Muhlenberg County
    24.2             24.2  
                         
Total Illinois Basin
    24.2             24.2  
                         
Total Surface Mining Operations
    68.6       15.9       52.7  
                         
Underground Coal Reserves:
                       
Tusky(3)
    23.0             23.0  
                         
Total Underground Coal Reserves
    23.0             23.0  
                         
Total
    91.6       15.9       75.7  
                         
Percentage of Total
    100 %     17.4 %     82.6 %
                         
 
 
(1) Reported as recoverable coal reserves. All proven and probable coal reserves are “assigned” coal reserves, which are coal reserves that can be mined without a significant capital expenditure for mine development.
 
(2) The Harrison mining complex is owned by Harrison Resources. 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 and the first quarter of 2010 as required by GAAP, 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 “— Mining Operations — Northern Appalachia — Harrison Mining Complex.”
 
(3) Please read “— Underground Coal Reserves” for more information about our underground coal reserves at the Tusky mining complex, which we have leased to a third party in exchange for royalty payments. We received royalty payments on 0.6 million tons and 0.1 million tons of coal produced from the Tusky mining complex during 2009 and the first quarter of 2010, respectively.


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The following table provides information on particular characteristics of our coal reserves as of December 31, 2009:
 
                                                                 
    As received Basis(1)                
                # of
  Proven and Probable Coal Reserves
                SO2/mm
  Sulfur Content(1)
Mining Complex
  % Ash   % Sulfur   Btu/lb.   Btu   Total   <2%   2-4%   >4%
                        (in million tons)
 
Surface Mining Operations:
                                                               
Northern Appalachia (principally Ohio)
                                                               
Cadiz
    11.6       3.3       11,520       5.7       12.4       1.1       6.1       5.2  
Tuscarawas County
    10.5       3.7       11,570       6.3       8.8       1.6       3.5       3.7  
Belmont County
    12.6       3.7       11,510       6.4       6.6             4.6       2.0  
Plainfield
    10.7       4.4       11,350       7.7       6.4             0.7       5.7  
New Lexington
    11.1       4.0       11,260       7.1       4.9             2.0       2.9  
Harrison(2)
    11.9       1.8       12,040       3.0       2.8       2.1       0.7        
Noble County
    13.2       4.7       11,230       8.4       2.5             0.3       2.2  
Illinois Basin (Kentucky)
                                                               
Muhlenberg County
    11.2       3.6       11,295       6.4       24.2             23.0       1.2  
Underground Coal Reserves:
                                                               
Tusky(3)
    5.4       2.1       12,900       3.3       23.0       3.8       19.2        
 
 
(1) As received represents an analysis of a sample as received at a laboratory operated by a third party.
 
(2) The Harrison mining complex is owned by Harrison Resources. We own 51% of Harrison Resources and CONSOL Energy Inc 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 and the first quarter of 2010 as required by U.S. generally accepted accounting principles, 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 “— Mining Operations — Northern Appalachia — Harrison Mining Complex.”
 
(3) Please read “— Underground Coal Reserves” for more information about our underground coal reserves at the Tusky mining complex, which we have leased to a third party in exchange for royalty payments. We received royalty payments on 0.6 million tons and 0.1 million tons of coal produced from the Tusky mining complex during 2009 and the first quarter of 2010, respectively.
 
Underground Coal Reserves
 
We originally leased our underground coal reserves from a third party in 2003 in exchange for a royalty based on tonnage sold. We began our underground mining operation in late 2003. In June 2005, we sold the Tusky mining complex, and we subleased our underground coal reserves associated with that complex to the purchaser in exchange for an overriding royalty. Our overriding royalty is equal to a percentage of the sales price received by our sublessee for the coal produced from our underground coal reserves. In addition, our sublessee is obligated to pay the royalty we owe to our lessor. We have at least 15 years remaining on the lease for our underground coal reserves, and our sublessee has at least 15 years remaining on its sublease from us.
 
Reclamation
 
We are committed to minimizing our environmental impact during the mining process. However, there is always some degree of impact. To minimize the long-term environmental impact of our mining activities, we plan and monitor each phase of our mining projects as well as our post-mining reclamation efforts. As of March 31, 2010, we had approximately $32.4 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $7.5 million in letters of credit. In


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addition to providing surety bonds, we have also made a significant investment to complete the required reclamation activities in a timely and professional manner to cause our surety bonds to be released. We have historically performed, and expect to continue to perform, reclamation activities on a continuous basis as our mining activities progress.
 
Over 95% of our active surface mining permits are associated with reserves that were mined by other coal producers prior to the implementation of SMCRA. We are able to economically mine these reserves due to increased coal pricing and improved mining technologies compared to the pre-SMCRA period. Reclamation standards prior to SMCRA were considerably lower than today’s standards. These pre-SMCRA mining areas have unreclaimed highwalls and often have water quality or vegetation deficiencies. Our mining activities not only recover coal that was left behind by previous operators, but also significantly reduce the environmental and safety hazards created by their mining activities. Although we have reclamation obligations with respect to these pre-SMCRA mining areas, these obligations are typically no greater than the reclamation obligations for newly mined reserves.
 
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 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. One site on the AMD Inventory List has been recommended by Ohio for removal from the AMD Inventory List and the remaining sites are being monitored to assess long-term AMD treatment issues. Moreover, we anticipate that one of these sites being monitored will receive final surety bond release in 2010 and will be removed from the AMD Inventory List.
 
Limestone
 
At our Cadiz mining complex, we remove limestone in order to mine the underlying coal. We sell this limestone to a third party that crushes and processes the limestone before it is sold to local governmental authorities, construction companies and individuals. The third party pays us for this limestone based on a percentage of the revenue it receives from sales of this limestone. Our revenues for the year ended December 31, 2009 and the first quarter of 2010 include $1.4 million and $0.3 million in limestone sales, respectively.
 
During 2009 and the first quarter of 2010, we produced 0.4 million tons and 0.1 million tons of limestone, respectively. Based on estimates from our internal engineers, our Cadiz mining complex includes 8.0 million tons of proven and probable limestone reserves as of December 31, 2009. All of these limestone reserves were assigned reserves, which are limestone reserves that can be recovered without a significant capital expenditure for mine development.
 
Other Operations
 
During 2009 and the first quarter of 2010, we generated $1.3 million and $0.5 million of revenue, respectively, from a variety of services we perform in connection with our surface mining operations. This revenue included the following:
 
  •     services fees we earn for operating a transloader for a third party that offloads coal from railcars on the Ohio Central Railroad at one of our customer’s power plants;
 
  •     service fees we earn for providing earth-moving services for Tunnel Hill Partners, LP, an entity owned by our sponsors that owns a landfill; and
 
  •     service fees we earn for hauling and disposing of ash at a third party landfill for two municipal utilities.


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For more information regarding our relationships and our sponsors’ relationships with Tunnel Hill Partners, please read “Certain Relationships and Related Party Transactions.”
 
Customers
 
General
 
We market the majority of the coal we produce to base-load power plants in our six-state market area under long-term coal sales contracts. Our primary customers are major electric utilities, municipalities and cooperatives and industrial customers. For the year ended December 31, 2009, we derived 70% of our revenues from coal sales to electric utilities (including sales through brokers), 19% from coal sales to municipalities and cooperatives, 9% from coal sales to industrial customers and the remaining 2% from a mixture of sales of non-coal material such as limestone, royalty payments on our underground coal reserves and fees for services we perform for third parties. For the first quarter of 2010, we derived 78.7% of our revenues from coal sales to electric utilities (including sales through brokers), 14.9% from coal sales to municipalities and cooperatives, 4.5% from coal sales to industrial customers and the remaining 1.9% from a mixture of sales of non-coal material such as limestone, royalty payments on our underground coal reserves and fees for services we perform for third parties.
 
Long-Term Coal Sales Contracts
 
For the year ended December 31, 2009 and the first quarter of 2010, we generated approximately 95.8% and 96.3%, respectively, of our revenues from coal delivered under our long-term coal sales contracts, and we expect to continue selling a significant portion of our coal under long-term coal sales contracts in the future. We define long-term contracts as those with a term of one year or longer and our long-term coal sales contracts typically have terms ranging from one to eight years. For 2010, 2011, 2012 and 2013, we currently have long-term coal sales contracts that represent 97.6%, 93.0%, 71.4% and 39.6%, respectively, of our 2010 estimated coal sales of 8.5 million tons. During 2010, 2011, 2012 and 2013, we have committed to deliver 8.3 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 63.2%.
 
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, 65%, 80%, 91% 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,


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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.
 
Quality and volumes for the coal are stipulated in our coal sales contracts, and in some instances our customers have the option to vary annual or monthly volumes. Most of our coal sales contracts contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Some of our coal sales contracts specify approved locations from which coal must be sourced. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or ultimately termination of the agreements. Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions, mine closures, or transportation disruptions that affect us as well as unanticipated customer plant outages that may affect our customer’s ability to receive coal deliveries.
 
Customer Concentration
 
We derived 90% and 94% of our total revenues from coal sales to our ten largest customers for the year ended December 31, 2009 and the first quarter of 2010, respectively, with our top five customers accounting for 77% and 72% of our total revenues, respectively. In addition, for the year ended December 31, 2009, we derived 34.7%, 14.7% and 14.6% of our revenues from AEP, East Kentucky Power Cooperative and Duke Energy, respectively. For the first quarter of 2010, we derived 31.9%, 10.0% and 11.2% of our revenues from AEP, East Kentucky Power Cooperative and Duke Energy, respectively.
 
Transportation
 
Our coal is delivered to our customers by barge, truck or rail. Over 55% and 63% of the coal we shipped during 2009 and the first quarter of 2010, respectively, was transported to our customers by barge, which is generally cheaper than transporting coal by truck or rail. We operate river terminals on the Ohio River in eastern Ohio and the Green River in western Kentucky, which have annual throughput capacities of approximately 4 million tons and 3 million tons, respectively. We also use third-party trucking to transport coal to our customers. In addition, certain of our mines are located near rail lines. On April 1, 2006, we entered into a long-term transportation contract for rail services, which has been amended and extended through March 31, 2011. Our customers typically pay the transportation costs to their location when coal is shipped by barge. We typically pay for the cost to transport coal to our customers by truck and rail and to our river terminals and rail loadout facilities. However, our sales contracts typically have these transportation costs built into the price. For the year ended December 31, 2009, 55.0%, 42.0% and 3.0% of our coal sales tonnage was shipped by barge, truck and rail, respectively. For the first quarter of 2010, 63%, 33% and 4% of our coal sales tonnage was shipped by barge, truck and rail, respectively.
 
We believe that we have good relationships with rail carriers and truck companies due, in part, to our modern coal-loading facilities and the working relationships and experience of our general partner’s transportation and distribution employees.
 
Suppliers
 
For the year ended December 31, 2009 and the first quarter of 2010, expenses we incurred to obtain goods and services in support of our mining operations were $97.8 million and $31.0 million, respectively, excluding capital expenditures. Principal supplies and services used in our business include diesel fuel, oil, explosives, maintenance and repair parts and services, and tires and lubricants. For the year ended December 31, 2009 and the first quarter of 2010, we hedged 54.4% and 37.4%, respectively, of our diesel fuel usage using fixed priced forward contracts that provide for physical delivery. These fixed priced forward contracts have terms ranging from six months to one year and generally do not have collateral requirements.
 
We use third-party suppliers for a significant portion of our equipment rebuilds and repairs and for blasting services. We also use a third party contractor for highwall mining services. We use bidding processes


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to promote competition between suppliers and we seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers that identify and concentrate on implementing continuous improvement opportunities within their area of expertise.
 
Competition
 
The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States, and we compete with many of these producers. Our main competitors include Alliance Resource Partners, L.P., Alpha Natural Resources, Inc., Armstrong Coal Company, Buckingham Coal Co., Inc., The Cline Group, CONSOL Energy, Massey Energy Company, Murray Energy Corporation, Patriot Coal Corp., Peabody Energy, Inc. and Rhino Mining Inc.
 
The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and international consumers. These coal consumption patterns are influenced by factors beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, quality, price and availability of competing sources of fuel such as natural gas, oil and nuclear sources, and alternative energy sources such as hydroelectric power and wind.
 
Regulation and Laws
 
Federal, state and local authorities regulate the U.S. coal mining industry with respect to environmental, health and safety matters such as employee health and safety, permitting and licensing requirements, air and water pollution, plant and wildlife protection, and the reclamation and restoration of mining properties after mining has been completed. These laws and regulations have had, and will continue to have, a significant effect on production costs and may impact our competitive advantages. Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may substantially increase operating costs, result in delays and disrupt operations, the extent of which cannot be predicted with any degree of certainty. Future laws, regulations or orders may also cause coal to become a less attractive source of energy, thereby reducing its market share as fuel used to generate electricity. Thus, future laws, regulations or enforcement priorities may adversely affect our mining operations, cost structure or the demand for coal.
 
We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, due in part to the complexity, extent and nature of the various regulatory requirements, violations can and do occur from time to time. We cannot assure complete compliance at all times with all applicable laws and regulations.
 
Mining Permits and Approvals
 
Numerous federal, state or local governmental permits or approvals are required to conduct coal mining and reclamation operations. When we apply for these permits and approvals, we are required to prepare and present data to governmental authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the natural or human environment. The authorization and permitting requirements imposed by governmental authorities are costly and increasingly take more time to obtain and may delay commencement or continuation of mining operations.
 
In order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators or applicants must submit a reclamation plan for restoring the mined land to its prior productive or other approved use. Typically, we submit the necessary permit applications 12 to 30 months before we plan to mine a new area. Some 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 coal in certain areas of the application in order to obtain permit approvals. The application review process takes longer to complete and is increasingly


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being challenged by environmentalists and other advocacy groups, although we are not aware of any such challenges to any of our pending permit applications.
 
Violations of federal, state and local laws, regulations or any permit or approval issued under such authorization can result in substantial fines and penalties, including revocation or suspension of mining permits. In certain circumstances, criminal sanctions may be imposed for failure to comply with these laws in addition to fines and civil penalties.
 
Surface Mining Control and Reclamation Act
 
SMCRA establishes mining, reclamation and environmental protection standards for all aspects of surface coal mining, including the surface effects of underground coal mining. Mining operators must obtain SMCRA permits and permit renewals from the Office of Surface Mining, or the OSM, or from the applicable state agency if the state has obtained primacy. A state may achieve primacy if it develops a regulatory program that is no less stringent than the federal program and is approved by OSM. Our mines are located in Ohio, Pennsylvania, West Virginia and Kentucky, which have primacy to administer the SMCRA program.
 
SMCRA permit provisions include a complex set of requirements, which include, among other things, coal exploration, mine plan development, topsoil or a topsoil removal alternative, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, disposal of excess spoil, protection of the hydrologic balance, surface runoff and drainage control, establishment of suitable post mining land uses and re-vegetation. The process of preparing a mining permit application begins by collecting baseline data to adequately characterize the pre-mining environmental conditions of the permit area. This work is typically conducted by third-party consultants with specialized expertise and typically includes surveys or assessments of the following: cultural and historical resources, geology, soils, vegetation, aquatic organisms, wildlife, potential for threatened, endangered or other special status species, surface and groundwater hydrology, climatology, riverine and riparian habitat and wetlands. The geologic data and information derived from the other surveys or assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatory program, and are also used to support applications for other authorizations or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, public road use, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.
 
Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for this process to take from 12 to 30 months for a SMCRA mine permit application. This variability in time frame for permitting is a function of the discretion vested in the various regulatory authorities’ handling of comments and objections relating to the project received from the governmental agencies involved and the general public. The public also has the right to comment on and otherwise engage in the administrative process including at the public hearing and through judicial challenges to an issued permit.
 
Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being “permit blocked” under the federal Applicant Violator Systems, or AVS. Thus, non-compliance with SMCRA can provide the bases to deny the issuance of new mining permits or modifications of existing mining permits, although we know of no basis to be and are not permit-blocked.


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We have subleased our underground coal reserves at the Tusky mining complex to a third party in exchange for an overriding royalty. Under our sublease, our sublessee is contractually obligated to comply with all federal, state and local laws, including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil as required under SMCRA. Regulatory authorities may attempt to assign the SMCRA liabilities of our sublessee to us if it is not financially capable of fulfilling those obligations and it is determined that we “own” or “control” the sublessee’s mining operation. To our knowledge, no such claims have been asserted against us to date. If such claims are ever asserted against us, we will contest them vigorously on the basis that, among other things, receiving an overriding royalty under a sublease does not alone meet the legal or regulatory test of “ownership” or “control” so as to subject us to the SMCRA liabilities of our sublessee.
 
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 under SMCRA and other federal and state regulations. 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 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.
 
In 1983, the OSM adopted the “stream buffer zone rule,” or SBZ Rule, which prohibited mining disturbances within 100 feet of streams if there would be a negative effect on water quality. In December 2008, the OSM finalized a revised SBZ Rule, which purported to clarify certain aspects of the 1983 SBZ Rule. Several organizations challenged the 2008 revision to the SBZ Rule in two related actions filed in the U.S. District Court for the District of Columbia. In June 2009, the Interior Department and the U.S. Army entered into a memorandum of understanding on how to protect waterways from degradation if the revised SBZ Rule were vacated due to the litigation. In August 2009, the District Court concluded that the revised SBZ Rule could not be vacated without following the Administrative Procedure Act and other related requirements. On November 30, 2009, the OSM published an advanced notice of proposed rulemaking to further revise the SBZ Rule. In a March 2010 settlement with litigation parties, OSM agreed to use its best efforts to adopt a proposed rule by February 28, 2011 and a final rule by June 29, 2012. The requirements of the revised SBZ Rule, when adopted, will likely be stricter than the prior SBZ Rule to further protect streams from the impacts of surface mining, and may adversely affect our business and operations. In addition, Congress has proposed legislation in the past and may propose legislation in the future to restrict the placement of mining material in streams. Such legislation could also have an adverse impact on our business.
 
In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines. In 2009, we recorded $1.7 million of expense related to these reclamation fees.
 
Surety Bonds
 
State laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. The cost of surety bonds have fluctuated in recent years, and the market terms of these bonds have generally become more unfavorable to mine operators. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. Some mine operators have therefore used letters of credit to secure the performance of a portion of our reclamation obligations.
 
As of March 31, 2010, we had approximately $32.4 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $7.5 million in letters of credit.


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Mine Safety and Health
 
Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977, or the Mine Act, significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, all of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. The Mine Act requires mandatory inspections of surface and underground coal mines and requires the issuance of citations or orders for the violation of a mandatory health and safety standard. A civil penalty must be assessed for each citation or order issued. Serious violations of mandatory health and safety standards may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators who knowingly or willfully violates a mandatory health and safety standard, or order and provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly or willfully violate a mandatory health and safety standard or order. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards. In response to recent underground mine accidents, Congress, in 2006, enacted the Mine Improvement and New Emergency Response Act, or MINER Act, which imposed additional burdens on coal operators, including, among other matters, (i) obligations related to (a) the development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel, (b) establishing additional requirements for mine rescue teams, and (c) promptly notifying federal authorities of incidents that pose a reasonable risk of death and (ii) increased penalties for violations of the applicable federal laws and regulations. The penalty regulations promulgated in 2007 as a result of this legislation included new heightened penalty categories for certain types of violations and have resulted in the imposition of penalty assessment amounts that doubled between fiscal years 2007 and 2008 in the coal industry and are expected to increase. In the wake of the 2006 legislation, enforcement scrutiny also increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions. Various states also have enacted their own new laws and regulations addressing many of these same subjects. Our compliance with these or any new mine health and safety regulations could increase our mining costs.
 
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. During 2009 and the first quarter of 2010, we recorded $3.1 million and $0.9 million, respectively, of expense related to this excise tax. The Affordable Health Choices Act currently being debated in the U.S. Congress proposes potentially significant changes to the federal black lung program, including provisions, retroactive to 2005, which would (i) provide an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim, without requiring proof that the death was due to pneumoconiosis and (ii) establish a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These or similar proposed changes, if enacted, could have a material impact on our costs expended in association with the federal Black Lung program. In addition, we are liable under various state statutes for black lung claims.
 
Clean Air Act
 
The federal Clean Air Act and the amendments thereto and state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and control requirements for particulate matter, which includes


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fugitive dust from roadways, parking lots, and equipment such as conveyors and storage piles. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, carbon monoxide, ozone, mercury and other compounds emitted by coal-fired power plants. In addition to greenhouse gas emissions discussed below, air emission control programs that affect our operations, directly or indirectly, include, but are not limited to, the following:
 
  •     Acid Rain.  Title IV of the Clean Air Act was added through the CAAA and requires reductions of sulfur dioxide emissions by electric utilities regulated under the Acid Rain Program, or ARP. The ARP was designed to reduce the electric power sector emissions of sulfur dioxide and nitrous oxides. Sulfur dioxide emissions were controlled through the development of a national market-based cap-and-trade system. Under the ARP, a cap is established and then EPA issues allowances to regulated entities up to the cap using defined formulas. A small percentage of the allowances are retained for auctions. Each power plant must have enough allowances to cover all its annual SO2 emissions or pay penalties. The electric power plant can choose to reduce emissions and sell or bank the surplus allowances or purchase allowances. Though the CAAA created flexibility by allowing power plants to choose to emit or control emissions, emission reductions are encouraged by requiring an allowance to be retired every year for each ton of SO2 emitted. Affected power plants have sought to reduce sulfur dioxide emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emissions allowances. These efforts will make it more costly to operate coal-fired power plants and could make coal a less attractive fuel alternative in the planning and building of power plants in the future.
 
  •     Particulate Matter.  The Clean Air Act requires the EPA to set standards, referred to as National Ambient Air Quality Standards, or NAAQS, for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. Although our operations are not currently located in non-attainment areas, should any of the areas in which we operate be designated as non-attainment areas for particulate matter, our mining operations may be directly affected by any NAAQS implementation.
 
  •     Ozone.  The EPA issued revised ozone NAAQS imposing more stringent limits that took effect in May 2008. Nitrogen oxides, which are a by-product of coal combustion, are classified as an ozone precursor. Under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. In July 2009, the U.S. Court of Appeals for the District of Columbia vacated part of a rule implementing the ozone NAAQS and remanded certain other aspects of the rule to the EPA for further consideration. Notwithstanding the decision, we expect that additional emissions control requirements may be imposed on new and expanded coal-fired power plants and industrial boilers in the years ahead. The combination of these actions may impact demand for coal nationally, the impact of which we are unable to predict to any reasonable degree of certainty.
 
  •     NOx, or Nitrogen Oxides State Implementation Plan, or SIP Call.  The NOx SIP Call program was established by the EPA in October 1998 to reduce the transport of nitrogen oxide and ozone on prevailing winds from the Midwest and South to states in the Northeast that alleged they could not meet federal air quality standards because of NOx emissions. The program is designed to reduce NOx emissions by one million tons per year in 22 eastern states, including the six states in our primary market area, and the District of Columbia. As a result of this program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction, or SCR, devices. Installation of additional emission control measures will make it more costly to operate coal-fired power plants, which could make coal a less competitive fuel.
 
  •     Clean Air Interstate Rule.  The EPA’s CAIR calls for power plants in 28 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap and trade program similar to the system now in effect for acid rain. In July 2008, the U.S. Court of


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  Appeals for the District of Columbia Circuit vacated the EPA’s CAIR in its entirety and directed the EPA to commence new rule-making. After a petition for rehearing, the court ruled in December 2008 that to completely vacate CAIR would sacrifice public health and environmental benefits and that CAIR should remain in effect while the EPA modifies the rule. It is uncertain how the EPA will proceed to modify CAIR, although the EPA has indicated that it intends to propose a replacement rule in 2010 and to issue a final rule by early 2011. Under CAIR and any replacement rule, some coal-fired power plants might be required to install additional pollution control equipment, such as scrubbers and/or SCR equipment that could lead plants with these controls to become less sensitive to the sulfur-content of coal and more sensitive to delivered price, thereby making our high sulfur coal more competitive.
 
  •     Mercury.  In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the EPA’s Clean Air Mercury Rule, or CAMR, which had established a cap and trade program to reduce mercury emissions from power plants. At present, there are no federal regulations that require monitoring and reducing of mercury emissions at existing power plants. As a result of the decision to vacate the CAMR, in February 2009 the EPA announced that it would regulate mercury emissions by issuing Maximum Achievable Control Technology standards, or MACT, that will likely impose stricter limitations on mercury emissions from power plants than the vacated CAMR. The EPA is under a court deadline to issue a final rule requiring MACT for power plants by November, 2011. In conjunction with these efforts, on December 24, 2009, EPA approved an Information Collection Request (ICR) requiring all US power plants with coal-or oil-fired electric generating units to submit emissions information for use in developing air toxic emissions standards. EPA has stated that it intends to propose air toxic emissions standards for coal- and oil-fired electric generating units by March 10, 2011. In the meantime, case-by-case MACT determinations for mercury may be required for new and reconstructed coal-fired power plants. Apart from CAMR, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. The Obama Administration has also indicated a desire to begin negotiations on an international treaty to reduce mercury pollution. More stringent regulation of mercury emissions by the EPA, states, Congress, or pursuant to an international treaty may decrease the future demand for coal, but we are unable to predict the magnitude of any such impact with any reasonable degree of certainty.
 
There are lawsuits pending or threatened legal actions that have named coal producers as defendants for personal injury and property damage resulting from mercury emissions from coal-fired plants (e.g. by entering human pathways of exposure).
 
  •     Regional Haze.  The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. This program may result in additional emissions restrictions from new coal-fired power plants whose operation may impair visibility at and near such federally protected areas. This program may also require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, ozone and particulate matter. These limitations could also affect the future market for coal, to the extent of which we are unable to predict with any reasonable degree of certainty.
 
  •     New Source Review or, or NSR.  A number of pending regulatory changes and court actions will affect the scope of the EPA’s NSR program, which requires, among other emission sources, new coal-fired power plants and certain modifications to existing coal-fired power plants to install the same air emissions control equipment as new plants. The changes to the NSR program may impact demand for coal nationally, but we are unable to predict the magnitude of any such impact with any reasonable degree of certainty.


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Climate Change
 
Carbon dioxide is a “greenhouse gas,” the man-made emissions of which are of major concern under any regulatory framework intended to control climate change or prevent global warming. Carbon dioxide is a by-product of the combustion process, a primary source of which are coal-fired power plants. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. To date, the U.S. has not ratified the Kyoto Protocol, which expires in 2012. The United States is participating in international discussions currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. Any replacement treaty or other international arrangement requiring additional reductions in greenhouse gas emissions will have a potentially significant impact on the demand for coal if the United States were to adopt such requirements.
 
Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax, a cap-and-trade program or other programs aimed at carbon reduction, or by regulatory programs that may be established by the EPA under its existing authority. Congress is actively considering various proposals to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power, promote the use of clean energy and require energy efficiency measures. In June 2009, the House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act, and the Senate has considered similar legislation that would, among other things, impose a nationwide cap on greenhouse gas emissions and require major sources, including coal-fired power plants, to obtain “allowances” to meet that cap. The Senate is also crafting a compromise bill that may favor expansion of domestic energy production and limit the imposition of a cap and trade approach. Passage of such comprehensive climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and have a material adverse affect on our business and the results of our operations.
 
Even in the absence of new federal legislation, greenhouse gas emissions may be regulated in the future by the EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling Massachusetts v. EPA that the EPA has authority to regulate carbon dioxide emissions under the Clean Air Act, the EPA has taken several steps towards implementing regulations regarding the emission of greenhouse gases. In December 2009, the EPA issued a finding that carbon dioxide and certain other greenhouse gases emitted by motor vehicles endanger public health and the environment. This finding allows the EPA to begin regulating greenhouse gas emissions under existing provisions of the Clean Air Act. In anticipation of this finding, in October 2009, the EPA published a proposed rule that makes it clear that the EPA anticipates regulating the emission of greenhouse gases from certain stationary sources with an initial focus on facilities that release more than 25,000 tons of greenhouse gases a year, and which would require best available control technology for greenhouse gas emissions whenever such facilities are built or significantly modified. If the EPA were to set emission limits for carbon dioxide from electric utilities, the amount of coal our customers purchase from us could decrease. Moreover, in October 2009, the EPA published a final rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their greenhouse gas emissions to the EPA beginning in 2011 for emissions occurring in 2010.
 
Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities. In December 2005, seven northeastern states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont) signed the Regional Greenhouse Gas Initiative agreement, or RGGI, calling for implementation of a cap and trade program by 2009 aimed at reducing carbon dioxide emissions from power plants in the participating states. The RGGI program calls for signatory states to stabilize carbon dioxide emissions to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 through 2018. Since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers. RGGI has begun holding quarterly carbon dioxide allowance auctions for its initial


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three-year compliance period from January 1, 2009 to December 31, 2011 to allow utilities to buy allowances to cover their carbon dioxide emissions.
 
Midwestern states and Canadian provinces have also adopted initiatives to reduce and monitor greenhouse gas emissions. In November 2007, Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Ohio, South Dakota and Wisconsin and Manitoba signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. The draft recommendations, released in June 2009, call for a 20% reduction below 2005 emissions levels by 2020 and additional reductions to 80% below 2005 emissions levels by 2080. Climate change initiatives are also being considered or enacted in some western states.
 
Also, two U.S. federal appeals courts have allowed lawsuits by individuals, state attorneys general and others to pursue claims against major utility, coal, oil and chemical companies on the basis that those companies have created a public nuisance due to their emissions of carbon dioxide.
 
In addition to direct regulation of greenhouse gases, 33 states have adopted “renewable portfolio standards,” including Illinois, Ohio and Pennsylvania, which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. An additional five states have renewable portfolio standard goals that are not yet legal requirements. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for our coal.
 
These and other current or future climate change rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired power plants and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon dioxide emitting fuels or shut-down coal-fired power plants. There can be no assurance at this time that a carbon dioxide cap and trade program, a carbon tax or other regulatory regime, if implemented by the states in which our customers operate or at the federal level, or future court orders or other legally enforceable mechanisms, will not affect the future market for coal in those regions. The permitting of new coal-fired power plants has also recently been contested by some state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal. If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. For example, the U.S. Department of Energy announced in May 2009 that it would provide $2.4 billion of federal stimulus funds under the ARRA to expand and accelerate the commercial deployment of large-scaled CCS technology. However, there can be no assurances that cost-effective CCS capture and storage technology will become commercially feasible in the near future.
 
Clean Water Act
 
The CWA and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including the discharge of dredged or fill materials, into waters of the United States. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Legislation that seeks to clarify the scope of CWA jurisdiction is under consideration by Congress. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time we expend on CWA compliance.
 
CWA requirements that may directly or indirectly affect our operations include the following:
 
  •     Wastewater Discharge.  Section 402 of the CWA regulates the discharge of “pollutants” into navigable waters of the United States. The National Pollutant Discharge Elimination System, or


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  NPDES, requires a permit for any such discharges and entails regular monitoring, reporting and compliance with performance standards that govern discharges. Failures to comply with the CWA or the NPDES permits can lead to the imposition of penalties, compliance costs and delays in coal production.
 
The CWA and corresponding state laws also protect waters that states have designated for special protections including those designated as: impaired (i.e., as not meeting present water quality standards) through Total Maximum Daily Load, or TMDL, regulations; and “high quality/exceptional use” streams through anti-degradation regulations which restrict or prohibit discharges which result in degradation. Other requirements require the treatment of discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from surface mining and/or the surface impacts of underground mining. Individually and collectively, these requirements may cause us to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.
 
  •     Dredge and Fill Permits.  Many mining activities, including the development of settling ponds and other impoundments, may require a Section 404 permit from the Corps, prior to conducting such mining activities where they involve discharges of “fill” into navigable waters of the United States. The Corps is empowered to issue “nationwide” permits for specific categories of filling activities that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404 of the Clean Water Act. Using this authority, the Corps issued NWP 21, which authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Individual Section 404 permits are required for activities determined to have more significant impacts to waters of the United States.
 
Since 2003, environmental groups have pursued litigation primarily in West Virginia and Kentucky challenging the validity of NWP 21 and various individual Section 404 permits authorizing valley fills associated with surface coal mining operations (primarily mountain-top removal operations). This litigation has resulted in delays in obtaining these permits and has increased permitting costs. The most recent major decision in this line of litigation is the opinion of the U.S. Court of Appeals for the Fourth Circuit in Ohio Valley Environmental Council v. Aracoma Coal Company, 556 F.3d 177 (2009) (Aracoma), issued on February 13, 2009. In Aracoma the Court rejected all of the substantive challenges to the Section 404 permits involved in the case primarily by deferring to the expertise of the Corps in review of the permit applications. We currently have only one pending NWP 21 authorization, and we do not anticipate seeking NWP 21 authorizations in the future. As a result, we do not believe the outcome of this case will be material to us. However, the U.S. Supreme Court granted certiorari for this case on August 26, 2009, and it remains pending. If reversed, such a result could have an adverse effect on the surface mining industry.
 
After this decision was published, however, the EPA undertook several initiatives to address the issuance of Section 404 permits for coal mining activities in the Eastern U.S. First, the EPA began to comment on Section 404 permit applications pending before the Corps raising many of the same issues decided in favor of the coal industry in Aracoma. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. These letters have created regulatory uncertainty regarding the issuance of Section 404 permits for coal mining operations and have substantially expanded the time required for issuance of these permits.
 
In June 2009, the Corps, the EPA and the Department of the Interior announced an interagency action plan for an “enhanced review” of any project that requires both a SMCRA and a CWA permit designed to reduce the harmful environmental consequences of mountain-top mining in the Appalachian region. As part of this interagency memorandum of understanding, the Corps proposed to suspend and modify NWP 21 in the Appalachian region of Kentucky, Ohio, Pennsylvania,


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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. One of our permit applications is currently being reviewed by EPA under this enhanced review procedure even though the mining activities in question do not utilize mountain-top mining, a method of mining we do not employ. The permit covered by this application covers 0.6 million tons of our proven and probable coal reserves.
 
The EPA is also taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia, and announced in September 2009 that it was delaying the issuance of 74 Section 404 permits in central Appalachia. This is especially true in West Virginia, where the EPA plans to review all applications for NPDES permits even though the State of West Virginia is authorized to issue NPDES permits in West Virginia. These initiatives have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with obtaining and complying with those permits will increase substantially. Additionally, while it is unknown precisely what other future changes will be implemented as a result of the interagency action plan, any future changes could further restrict our ability to obtain other new permits or to maintain existing permits.
 
Resource Conservation and Recovery Act
 
The Resource Conservation and Recovery Act, or RCRA, was enacted in 1976 to establish requirements for the management of hazardous wastes from the point of generation through treatment of disposal. RCRA does not apply to most of the wastes generated at coal mines, overburden and coal cleaning wastes, because they are not considered hazardous wastes as EPA applies that term. Only a small portion of the total amount of wastes generated at a mine are regulated as hazardous wastes.
 
Although this act has the potential to apply to wastes from the combustion of coal, the EPA determined that coal combustion wastes do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state solid waste laws also regulate coal combustion wastes as non-hazardous wastes. The EPA is currently considering whether national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when used as mine-fill.
 
Comprehensive Environmental Response, Compensation and Liability Act
 
The Comprehensive Environmental Response, Compensation and Liability Act, CERCLA or Superfund, and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we currently own, lease or operate or that we or our predecessors have previously owned, leased or operated, and sites to which we or our predecessors sent waste materials. This includes the Tusky mining complex where we have subleased our underground coal reserves to a third party in exchange for an overriding royalty. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we own surface rights.
 
Endangered Species Act
 
The federal Endangered Species Act, or ESA, and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service, or USFWS, works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. A number of species indigenous to the areas in which we operate, specifically the Indiana bat, are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or delaying us


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from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. Should more stringent protective measures be applied, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures.
 
Use of Explosives
 
We use third party contractors for blasting services and our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to regulatory requirements. We presently do not engage in blasting activities. All of our blasting activities are conducted by independent contractors that use certified blasters.
 
Other Environmental Laws and Matters
 
We are required to comply with numerous other federal, state and local environmental laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act.
 
Office Facilities
 
We lease and own office space in Columbus and Coshocton, Ohio, respectively, that is used by our general partner’s executive and administrative employees. Our lease expires in 2015.
 
Employees
 
To carry out our operations, our general partner employed over 815 full-time employees as of March 31, 2010. None of these employees are subject to collective bargaining agreements or are members of any unions. We believe that we have good relations with these employees, and we continually seek their input with respect to our operations. Since our inception, we have had no history of work stoppages or union organizing campaigns.
 
Legal Proceedings
 
Although we are, from time to time, involved in litigation and claims arising out of our operations in the normal course of business, we do not believe that we are a party to any litigation that will have a material adverse impact on our financial condition or results of operations. We are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us. We maintain such insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.


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MANAGEMENT
 
We are managed and operated by the directors and executive officers of our general partner, Oxford Resources GP, LLC. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. C&T Coal owns 33.7% of the ownership interests in our general partner and AIM Oxford owns the remaining 66.3% of the ownership interests in our general partner. Oxford Resources GP has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly participate in our management or operations. 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, Brian D. Barlow, Matthew P. Carbone and George E. McCown serve on the board of directors of our general partner and are principals of AIM and have ownership interests in AIM. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. 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, we intend to incur indebtedness that is nonrecourse to our general partner.
 
Our partnership agreement provides for the Conflicts Committee, as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. The Conflicts Committee, which will consist solely of independent directors, will determine if the resolution of a conflict of interest that has been presented to it by our general partner is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the New York Stock Exchange and the Exchange Act. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, we will have an audit committee, or Audit Committee, that complies with the New York Stock Exchange requirements, and we will have a compensation committee, or Compensation Committee.
 
Even though most companies listed on the New York Stock Exchange are required to have a majority of independent directors serving on the board of directors of the listed company, the New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of its general partner.
 
Gerald A. Tywoniuk, along with two other independent board members to be appointed, will serve as the members of the Audit Committee. Mr. Tywoniuk serves as the chair of the Audit Committee. In compliance with the rules of the New York Stock Exchange, the members of the board of directors named below will appoint to the Audit Committee one additional independent member within 90 days of the listing and one additional independent member within twelve months of the listing. Thereafter, our general partner is generally required to have at least three independent directors serving on its board at all times.
 
Brian D. Barlow, Matthew P. Carbone and Gerald A. Tywoniuk serve as the members of the Compensation Committee. Mr. Barlow serves as the chair of the Compensation Committee.
 
Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the


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discretion of the board. The following table shows information for the directors and executive officers of our general partner.
 
             
Name
 
Age
 
Position
 
George E. McCown
    74     Chairman of the Board
Charles C. Ungurean
    60     Director, President and Chief Executive Officer
Jeffrey M. Gutman
    44     Senior Vice President, Chief Financial Officer and Treasurer
Gregory J. Honish
    53     Senior Vice President, Operations
Thomas T. Ungurean
    58     Senior Vice President, Equipment, Procurement and Maintenance
Michael B. Gardner
    55     Secretary and General Counsel
Denise M. Maksimoski
    35     Senior Director of Accounting
Brian D. Barlow
    40     Director
Matthew P. Carbone
    44     Director
Gerald A. Tywoniuk
    48     Director
 
George E. McCown was elected Chairman of the board of directors of our general partner in August 2007. Mr. McCown has been a Managing Director of AIM since he co-founded AIM in July 2006. Additionally, Mr. McCown has been a Managing Director of McCown De Leeuw & Co., or MDC, a private equity firm based in Foster City, California that specializes in buying and building industry-leading middle-market companies in partnership with management, since he co-founded MDC in 1983. Mr. McCown is Chairman of the board of directors of the general partner of Tunnel Hill Partners, an affiliate of AIM and C&T Coal. Mr. McCown received an MBA from Harvard University and a B.S. in mechanical engineering from Stanford University, where he served as a trustee from 1980 to 1985 and chaired the Finance Committee and Investment Policy Subcommittee of Stanford’s board of trustees.
 
Mr. McCown’s over 40 years of experience in buying and building companies, as well as his in-depth knowledge of the coal industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.
 
Charles C. Ungurean was elected President and Chief Executive Officer and a member of the board of directors of our general partner in August 2007. In 1985, Mr. Ungurean co-founded our predecessor and wholly owned subsidiary, Oxford Mining Company. He served as President and Treasurer of our predecessor from 1985 to August 2007. He has served as the President and Chief Executive Officer of our general partner since its formation in August 2007. Mr. Ungurean currently serves on the board of directors of the National Mining Association. In addition, Mr. Ungurean served as Chairman of the Ohio Coal Association from July 2002 to July 2004. Mr. Ungurean is the brother of Thomas T. Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our general partner.
 
Mr. Ungurean’s 37 years of experience in the coal industry, over 25 of which have been spent running our operations or the operations of our predecessor and wholly owned subsidiary, Oxford Mining Company, provide him with the necessary skills to be a member of the board of directors of our general partner.
 
Jeffrey M. Gutman has served as Senior Vice President, Chief Financial Officer and Treasurer of our general partner since April 2008. Prior to joining us, from 1991 to March 2008, Mr. Gutman served in a number of positions with The Williams Companies, Inc., an integrated natural gas company based in Tulsa, Oklahoma. His positions at the Williams Companies included Director of Capital Services from February 1998 to April 2000, Director of Structured Finance from April 2000 to December 2002, Chief Financial Officer of Gulf Liquids, a wholly-owned subsidiary of the Williams Companies, from December 2002 to December 2005, Director of Planning & Market Analysis from April 2005 to February 2008, and Commercial Development from December 2005 until joining our general partner in April 2008. Prior to joining the Williams Companies, Mr. Gutman was with Deloitte & Touche, LLP in their Tulsa office. Mr. Gutman is a certified public accountant in Oklahoma and holds a B.S. in Business Administration in Accounting from Oklahoma State University.


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Gregory J. Honish has served as Senior Vice President, Operations of our general partner since March 2009. Mr. Honish has served in other capacities with us and our predecessor since January 1999, including Vice President, Mining and Business Development from September 2007 to March 2009 and Senior Mining Engineer from January 1999 to September 2007. Mr. Honish has held a balanced spectrum of engineering, operations and management positions in the coal mining industry during his 30 year professional career at mines in Northern Appalachia, Central Appalachia, the Illinois Basin and the PRB. He is a Licensed Professional Engineer in Ohio and West Virginia and a Certified Surface Mine Foreman in Ohio and Wyoming. Mr. Honish holds a B.S. in Mining Engineering from the University of Wisconsin.
 
Thomas T. Ungurean has served as Senior Vice President, Equipment, Procurement and Maintenance of our general partner since March 2010, prior to which he was Vice President of Equipment from August 2007 to February 2010. In 1985, Mr. Ungurean co-founded our predecessor and wholly owned subsidiary, Oxford Mining Company. Since then he has served in various capacities with our predecessor, including Vice President and Secretary from September 2000 to August 2007. Mr. Ungurean is the brother of Charles C. Ungurean, the President and Chief Executive Officer and a member of the board of directors of our general partner.
 
Michael B. Gardner has served as Secretary and General Counsel of our general partner since September 2007. Prior to joining us, from June 2004 until May 2007, Mr. Gardner served as Associate General Counsel of Murray Energy Corporation, the largest privately-owned coal mining company in the United States. While at Murray Energy, Mr. Gardner served as an officer of several Murray Energy subsidiaries, including Vice President of UMCO Energy, Inc. and Secretary of UMCO Energy, Inc., Maple Creek Mining, Inc., Maple Creek Processing, Inc., The Ohio Valley Coal Company, The Ohio Valley Transloading Company, Ohio Valley Resources, Inc., and Sunburst Resources, Inc., and represented these entities in a variety of corporate, financial, real property, labor, litigation, environmental, health, safety, governmental affairs and public relations matters. Mr. Gardner is a licensed attorney in Ohio with more than 30 years of experience in the coal industry and in environmental regulatory compliance management. He is an alternate member of the Board of Directors of the Ohio Coal Association. Mr. Gardner received a J.D. from Case Western Reserve University, an MBA from Ashland University and a B.S. in Environmental Biology from Ohio University.
 
Denise M. Maksimoski has served as Senior Director of Accounting of our general partner since December 2009, prior to which she was Director, Financial Reporting and General Accounting from August 2008 to December 2009. Prior to joining us, from 1997 to 2008 Ms. Maksimoski was with Deloitte & Touche, LLP in Washington, D.C. and Columbus, Ohio in various positions including most recently as an Audit Senior Manager from August 2005 to August 2008 and as an Audit Manager from August 2003 to August 2005. While at Deloitte, Ms. Maksimoski gained extensive SEC reporting experience through leading large audit teams on public clients primarily in the energy and financial services industries. Ms. Maksimoski is a certified public accountant in the states of Ohio, Maryland and Virginia and in the District of Columbia. She received a B.A. degree in Accounting and Actuarial Studies from Thiel College.
 
Brian D. Barlow was elected as a member of the board of directors of our general partner in August 2007. Mr. Barlow has been a Principal with AIM since January 2007. Prior to joining AIM, he was a Senior Securities Analyst for Scion Capital, a private investment partnership located in Cupertino, California, from August 2004 to August 2006 and was self-employed from August 2006 to January 2007. Mr. Barlow has 18 years of investing experience in both the public and private equity markets; and while at Scion, he focused on public and private investments in the energy and natural resources sectors. He received an MBA from Columbia Business School and a B.A. from the University of Washington.
 
Mr. Barlow’s 18 years of investing experience, as well as his in-depth knowledge of the coal industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.
 
Matthew P. Carbone was elected as a member of the board of directors of our general partner in August 2007. Mr. Carbone has been a Managing Director of AIM since he co-founded AIM in July 2006. Prior to co-founding AIM, from January 2005 until July 2006, Mr. Carbone was a Managing Director of MDC. Mr. Carbone has spent nearly 20 years in private equity and investment banking. Prior to MDC, he led Wit


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Capital Group’s West Coast operations and worked in the investment banking divisions of Morgan Stanley, First Boston Corporation and Smith Barney. Mr. Carbone is a member of the board of directors of the general partner of Tunnel Hill Partners, an affiliate of AIM and C&T Coal. Mr. Carbone is also a member of the board of directors of the general partner of American Midstream Partners, LP. He received an MBA from Harvard Business School and a B.A. in Neuroscience from Amherst College.
 
Mr. Carbone’s nearly 20 years of experience in corporate finance, as well as his in-depth knowledge of the coal industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.
 
Gerald A. Tywoniuk was elected as a member of the board of directors of our general partner in January 2009. In May 2010, he was appointed interim Senior Vice President, Finance of CIBER, Inc., a global information technology services company. Mr. Tywoniuk continues to act on a part-time consulting basis as the Chief Financial Officer and acting Chief Executive Officer of Pacific Energy Resources Ltd., an oil and gas acquisition, exploitation and development company. Mr. Tywoniuk joined Pacific Energy Resources Ltd. in June 2008 as Senior Vice President, he was appointed Chief Financial Officer in August 2008 and he was appointed acting Chief Executive Officer in September 2009. He held these positions as an employee until May 2010. Prior to joining Pacific Energy Resources Ltd., Mr. Tywoniuk acted as an independent consultant in accounting and finance from March 2007 to June 2008. From December 2002 through November 2006, Mr. Tywoniuk was Senior Vice President and Chief Financial Officer of Pacific Energy Partners, LP. From November 2006 to March 2007, Mr. Tywoniuk assisted with the integration of Pacific Energy Partners, LP after it was acquired by Plains All American Pipeline, L.P. Mr. Tywoniuk holds a Bachelor of Commerce degree from The University of Alberta, Canada, and is a Canadian chartered accountant.
 
Mr. Tywoniuk joined Pacific Energy Resources Ltd. in June 2008 as Senior Vice President, Finance to help the management team work through the company’s financially distressed situation. In August 2008, he was appointed as the company’s Chief Financial Officer. The board of the company elected to file for Chapter 11 protection in March 2009 and, in September 2009, following the departure of the CEO and the President, Mr. Tywoniuk assumed the role of acting CEO. In December 2009, the company completed the sale of its assets, and is now working through the remaining steps of liquidation.
 
Mr. Tywoniuk has 28 years of experience in accounting and finance, including 12 years as the Chief Financial Officer of three public companies and Controller of a fourth public company. Mr. Tywoniuk’s extensive accounting, financial and executive management experience, as well as his in-depth knowledge of the mining industry generally and our partnership in particular, and his prior experience with publicly traded partnerships, provide him with the necessary skills to be Chair of the Audit Committee of the board of directors of our general partner, where he also qualifies as an “audit committee financial expert.”
 
Compensation Discussion and Analysis
 
The following is a discussion of the compensation policies and decisions of the board of directors of our general partner, or the Board, and the Compensation Committee with respect to the following individuals, who are executive officers of our general partner and referred to as the “named executive officers”:
 
  •     Charles C. Ungurean, President and Chief Executive Officer;
 
  •     Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer;
 
  •     Thomas T. Ungurean, Senior Vice President, Equipment, Procurement and Maintenance;
 
  •     Gregory J. Honish, Senior Vice President, Operations; and
 
  •     Michael B. Gardner, Secretary and General Counsel.
 
Our compensation program is designed to recruit and retain as executive officers individuals with the highest capacity to develop, grow and manage our business, and to align their compensation with our short-term and long-term goals. To do this, our compensation program for executive officers is made up of the following components: (i) base salary, designed to compensate our executive officers for work performed


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during the fiscal year; (ii) short-term incentive programs, designed to reward our executive officers for our yearly performance and for their individual performances during the fiscal year; and (iii) equity-based awards, meant to align our executive officers’ interests with our long-term performance.
 
Role of the Board, the Compensation Committee and Management
 
Our general partner, under the direction of the Board, is responsible for the management of our operations and employs all of the employees that operate our business. Historically, from our formation in August 2007 through compensation decisions made in early 2010, decisions with respect to the compensation of executive officers were made by the Board, based primarily on negotiations between our management group and the directors on our Board who were not employees of our general partner, or the Non-employee Directors. In connection with this offering, we have revised certain policies and practices with respect to executive compensation. In particular, the Board has appointed the Compensation Committee to help the Board administer certain aspects of the compensation policies and programs for our executive officers and certain other employees and to make recommendations to the Board relating to the compensation of the directors and executive officers of our general partner. The Compensation Committee and the Board are charged with, among other things, the responsibility of reviewing executive officer compensation policies and practices to ensure (i) adherence to our compensation philosophies and (ii) that the total compensation paid to our executive officers is fair, reasonable and competitive.
 
The compensation programs for our executive officers consist of base salaries, annual incentive bonuses and awards under the Oxford Resource Partners, LP Long-Term Incentive Plan, which we refer to as our LTIP, in the form of equity-based phantom units, as well as other customary employment benefits. We expect that total compensation of our executive officers and the components and relative emphasis among components of their annual compensation will be reviewed on at least an annual basis by the Compensation Committee with any proposed changes recommended to the Board for final approval.
 
During 2009, the Board discussed compensation issues at several meetings. The Compensation Committee has held and expects to continue to hold compensation-related meetings for 2010 and in future years. Topics discussed and to be discussed at these meetings included and will include, among other things, (i) assessing the performance of the Chief Executive Officer, or the CEO, and our other executive officers with respect to our results for the prior year, (ii) reviewing and assessing the personal performance of our executive officers for the preceding year and (iii) determining the amount of the bonus pool to be approved by the Board and paid to our executive officers for a given year after taking into account the target bonus levels established for those executive officers at the outset of the year. In addition, at these meetings, and after taking into account the recommendations of our CEO with respect to executive officers other than our CEO, base salary levels and target bonus levels (representing the bonus that may be awarded expressed as a percentage of base salary or as a dollar amount for the year) for our executive officers to be recommended to the Board will be established by the Compensation Committee. In addition, the Compensation Committee will make its recommendations to the Board with respect to any awards under the LTIP.
 
Compensation Objectives and Methodology
 
The principal objective of our executive compensation program is to attract and retain individuals of demonstrated competence, experience and leadership who share our business aspirations, values, ethics and culture. A further objective is to provide incentives to and reward our executive officers and other key employees for positive contributions to our business and operations, and to align their interests with our unitholders’ interests.
 
In setting our compensation programs, we consider the following objectives:
 
  •     to create unitholder value through sustainable earnings and cash available for distribution;
 
  •     to provide a significant percentage of total compensation that is “at-risk” or variable;


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  •     to encourage significant equity holdings to align the interests of executive officers and other key employees with those of unitholders;
 
  •     to provide competitive, performance-based compensation programs that allow us to attract and retain superior talent; and
 
  •     to develop a strong linkage between business performance, safety, environmental stewardship, cooperation and executive compensation.
 
Taking account of the foregoing objectives, we structure total compensation for our executives to provide a guaranteed amount of cash compensation in the form of competitive base salaries, while also providing a meaningful amount of annual cash compensation that is at risk and dependent on our performance and individual performance of the executives, in the form of discretionary annual bonuses. We also seek to provide a portion of total compensation in the form of equity-based awards under our LTIP, in order to align the interests of executives and other key employees with those of our unitholders and for retention purposes. Historically, we have not made regular annual grants of awards under our LTIP. Instead, such awards have typically been made in connection with our formation, upon commencement of employment for executives who joined us after our formation, and in discrete circumstances to reward service or performance. Going forward, we expect that equity-based awards will be made more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process.
 
Compensation decisions for individual executive officers are the result of the subjective analysis of a number of factors, including the individual executive officer’s experience, skills or tenure with us and changes to the individual executive officer’s position. In measuring the contributions of executive officers and our performance, a variety of financial measures are considered, including non-GAAP financial measures used by management to assess our financial performance. Historically, the Board has used the amount of cash distributions made to our equityholders as the primary measure of our operating performance. For a discussion of cash distributions and related matters, please read “Cash Distribution Policy and Restrictions on Distributions.” In addition, an evaluation of the individual performance of each of the executive officers is taken into consideration.
 
In making individual compensation decisions, the Board historically has not relied on pre-determined performance goals or targets. Instead, determinations regarding compensation have been and are expected to continue to be the result of the exercise of judgment based on all reasonably available information and, to that extent, are discretionary. Each executive officer’s current and prior compensation is considered in setting future compensation. The amount of each executive officer’s current compensation is considered as a base against which determinations are made as to whether increases are appropriate to retain the executive officer in light of competition or in order to provide continuing performance incentives. The Board has discretion to adjust any of the components of compensation to achieve our goal of recruiting, promoting and retaining as executive officers individuals with the skills necessary to execute our business strategy and develop, grow and manage our business.
 
Prior to 2010, we did not review executive compensation against a specific group of comparable companies. Rather, the Board has historically relied upon the judgment and industry experience of its non-employee directors in making decisions with respect to total compensation and with respect to the allocation of total compensation among our three main components of compensation. Going forward, we expect that the Compensation Committee will make compensation recommendations to the Board based upon trends occurring within our industry, including from a peer group of companies that our Compensation Committee has recently identified, which includes the following coal companies and similar-sized publicly traded partnerships: Alliance Resource Partners, L.P., National Coal Corp., Westmoreland Coal Co., James River Coal Co., International Coal Group, Inc., Patriot Coal Corporation, Vanguard Natural Resources, LLC, Global Partners LP, Legacy Reserves LP, Copano Energy LLC, Suburban Propane Partners LP and Crosstex Energy Inc.


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Elements of the Compensation Programs
 
Overall, our executive officer compensation programs are designed to be consistent with the philosophy and objectives set forth above. The principal elements of our executive officer compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation element.
 
         
Element
  Characteristics   Purpose
 
Base Salaries
  Fixed annual cash compensation. Our executive officers are eligible for periodic increases in base salaries. Increases may be based on performance or such other factors as the Board or the Compensation Committee may determine.   Keep our annual compensation competitive with the defined market for skills and experience necessary to execute our business strategy.
Annual Incentive Bonuses
  Performance-related annual cash incentives earned based on our objectives and individual performance of the executive officers. Beginning in 2010, trends for our peer group will be taken into account in setting future annual cash incentive awards for our executive officers.   Align annual compensation with our financial performance and reward our executive officers for individual performance during the year and for contributing to our financial success. Amounts provided as incentive bonuses are also designed to provide competitive total direct compensation; potential for awards above or below target amounts are intended to motivate our executive officers to achieve greater levels of performance.
Equity-Based Awards (phantom-units)
  Performance-related, equity-based awards granted at the discretion of the Board. Awards are based on our performance and, beginning in 2010, will be based on competitive practices at peer companies. Grants typically vest ratably over four years and will be settled upon vesting with either a net cash payment or an issuance of common units, at the discretion of the Board.   Align interests of our executive officers with unitholders and motivate and reward our executive officers to increase unitholder value over the long term. Ratable vesting over a four-year period is designed to facilitate retention of our executive officers.


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Element
  Characteristics   Purpose
 
Retirement Plan
  Qualified retirement plan benefits are available for our executive officers and all other regular full-time employees. Through 2009, we maintained a defined contribution money purchase pension plan to which we made contributions for the benefit of the participants. Effective with 2010, we have adopted and are maintaining a 401(k) plan in which all eligible employees can elect to contribute compensation for retirement up to IRS imposed limits, either on a tax deferred or after-tax basis. The 401(k) plan permits us to make annual discretionary contributions to the plan, even if the participants do not contribute, as a percentage of the eligible compensation of participants in the plan. Annual contributions of 3% or more of such eligible compensation will maintain “safe harbor” tax-qualified status for the plan, and while it is discretionary, we intend generally to make annual contributions at that level or higher. For 2010, we have committed to make an employer discretionary contribution of 4% of such eligible compensation.   Provide our executive officers and other employees with the opportunity to save for their future retirement.
Health and Welfare Benefits
  Health and welfare benefits (medical, dental, vision, disability insurance and life insurance) are available for our executive officers and all other regular full-time employees.   Provide benefits to meet the health and wellness needs of our executive officers and other employees and their families.
 
Base Salaries
 
Design.  Base salaries for our executive officers are determined annually by an assessment of our overall financial and operating performance, each executive officer’s performance evaluation and changes in executive officer responsibilities. While many aspects of performance can be measured in financial terms, senior management is also evaluated in areas of performance that are more subjective. These areas include the development and execution of strategic plans, the exercise of leadership in the development of management and other employees, innovation and improvement in our business activities and each executive officer’s involvement in industry groups and in the communities that we serve. We seek to compensate executive officers for their performance throughout the year with annual base salaries that are fair and competitive within our marketplace. We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our marketplace and adjusted for financial and operating performance and each executive officer’s performance evaluation, length of service with us and previous work experience. Individual salaries have historically been established by the Board based on the general industry knowledge and experience of the directors on our Board that were not

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employees of our general partner, in alignment with these considerations and with reference to industry survey data, to ensure the attraction, development and retention of superior talent. Going forward, we expect that determinations will continue to focus on the above considerations and will also be made based upon relevant market data, including data from our peer group.
 
Base salaries are reviewed annually to ensure continuing consistency with market levels and our level of financial performance during the previous year. Future adjustments to base salaries and salary ranges will reflect average movement in the competitive market as well as individual performance. Annual base salary adjustments, if any, for the CEO have been determined by the Non-employee Directors. After this offering, annual base salary adjustments for the CEO will be approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual base salary adjustments, if any, for the other executive officers have been determined by the Board taking into account input from the CEO. After this offering, annual base salary adjustments for the other executive officers will be approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the CEO.
 
Actions Taken With Respect to Base Salaries in 2009.  Effective May 1, 2009 (except effective March 30, 2009 in the case of Gregory J. Honish), the Board provided base salary increases to each of the named executive officers as provided in the table below. These base salary increases were provided as “merit” increases based on the Board’s subjective assessment of each named executive officer’s performance in 2008 and early 2009, considering a variety of factors, none of which was individually material to such assessment, and to ensure that the base salaries for the named executive officers remained competitive with other companies in our industry. In addition, for Gregory J. Honish, the increase reflected in part his promotion to Senior Vice President, Operations.
 
                         
        Base Salary
   
    Base Salary at
  Increase
  2009 Base Salary
Name
  Start of 2009   in 2009   Following Increase
 
Charles C. Ungurean
  $ 300,000     $ 75,000     $ 375,000  
Jeffrey M. Gutman
    250,000       10,000       260,000  
Thomas T. Ungurean
    200,000       25,000       225,000  
Gregory J. Honish
    110,000       40,000       150,000  
Michael B. Gardner
    133,000       12,000       145,000  
 
Annual Incentive Bonuses
 
Design.  As one way of accomplishing compensation objectives, our executive officers are rewarded for their contribution to our financial and operational success through the award of discretionary annual cash incentive bonuses. Annual incentive awards, if any, for the CEO have been determined by the Non-employee Directors. After this offering, annual incentive awards, if any, for the CEO will be approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual incentive awards, if any, for the other executive officers have been determined by the Board taking into account input from the CEO. After this offering, annual incentive awards for the other executive officers will be approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the CEO.
 
While target bonuses for our executive officers are initially set at percentages or dollar amounts that are 50% to 75% of their base salaries, the Board has broad discretion to retain, reduce or increase the award amounts when making its final bonus determinations. For our executive officers other than Charles C. Ungurean and Thomas T. Ungurean, certain target bonus amounts were individually negotiated with the executive officers and are set forth in their existing employment agreements, which are discussed in more detail under “— Employment and Severance Agreements” below. Although the employment agreements that were in effect for 2009 for Charles C. Ungurean and Thomas T. Ungurean provided that these executives were not eligible to receive annual incentive bonuses, the Board has historically paid annual bonuses to these executive officers and expected to, and did in fact, pay bonuses to these executives for 2009. These bonus


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payments have been made because prior to 2009, the Board determined that these executives would not otherwise be sufficiently motivated to achieve high levels of performance and that the total compensation for their services would not be competitive with compensation paid by other companies in our industry unless they were eligible to receive annual bonuses similar to those paid to our other named executive officers. In connection with this offering, we will enter into new employment agreements with Messrs. Charles C. Ungurean and Thomas T. Ungurean, which will provide for their eligibility to receive annual incentive bonuses on a basis similar to our other named executive officers, in an amount up to 66.6% of their annual base salary, or such other greater percentage as may be approved by the Board or the Compensation Committee.
 
The annual incentive bonus award for each executive officer is contingent on the executive officer’s continued employment with our general partner at the time of the award. Further, bonuses (similar to other elements of the compensation provided to executive officers) are not based on a prescribed formula but rather have been determined on a discretionary subjective basis and generally have been based on a subjective evaluation of individual, company-wide and industry performances. The Board and the Compensation Committee believe that this approach to assessing performance results in a more comprehensive evaluation for compensation decisions. The Board has recognized, and the Compensation Committee will recognize, the following factors in making discretionary annual bonus recommendations and determinations:
 
  •     a subjective performance evaluation based on company-wide financial and individual qualitative performance, as determined in the Board’s discretion; and
 
  •     the scope, level of expertise and experience required for the executive officer’s position.
 
These factors were selected as the most appropriate measures upon which to base the annual incentive cash bonus decisions because our Board believes that they help to align individual compensation with competency and contribution. With respect to its evaluation of company-wide financial performance, although no official numerical goals are established for purposes of our bonus decisions, the Board’s general practice historically has been to pay annual bonuses based on our achieving our company-wide budgeted goals with respect to cash distributions made to our equityholders for the applicable year. For 2009, the Board determined to make bonus payments based on our achieving our budgeted cash distribution target for the year of $1.68 per unit (which amount does not take into account the unit split described in “Summary — The Transactions). Our budgeted cash distribution target did not change for 2010, and we expect that the Compensation Committee will make annual bonus decisions for 2010 based on actual cash distributions made as compared to this budgeted target for the period from January 1, 2010 to the closing of this offering, and following the closing of this offering, based on our making cash distributions at or in excess of the minimum quarterly distribution rate, as described under “Cash Distribution Policy and Restrictions on Distributions.”
 
Notwithstanding the achievement of our cash distribution target, as described above, the Board retained, and going forward we expect that the Board and the Compensation Committee will retain, broad discretion with respect to the amount of each named executive officer’s annual bonus award, in order to provide total cash compensation for the year that is competitive and consistent with total cash compensation provided by other companies in our industry, as determined by the Non-employee Directors and based on their industry knowledge and experience, and to address the Board’s assessment of each named executive officer’s individual performance and contributions to our overall success. Based on these considerations, the Board determined to award the incentive bonus amounts set forth in the table below to our named executive officers for performance in 2009. For the named executive officers with target bonus amounts set forth in their employment agreements, these awards represented approximately 85%-90% of the applicable target bonus amounts. The Board determined each individual amount based on its assessment of what was fair and competitive total cash compensation for each named executive officer in light of our achievement of our


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cash distribution target for 2009, the individual named executive officer’s level of responsibility within our organization and the Board’s view of each named executive officer’s contributions to our success for 2009.
 
         
Name
  2009 Bonus(1)
 
Charles C. Ungurean
  $ 225,000  
Jeffrey M. Gutman
    112,500  
Thomas T. Ungurean
    175,000  
Gregory J. Honish
    63,750  
Michael B. Gardner
    61,625  
 
 
(1) Amounts shown in this column do not include vacation pay amounts included in bonus amounts in the Summary Compensation Table for 2009 below.
 
Beginning in 2010, the Compensation Committee expects that it will base annual incentive compensation award recommendations on additional company-wide criteria as well as industry criteria, recognizing the following factors as part of its determination of annual incentive bonuses (without assigning any particular weighting to any factor):
 
  •     financial performance for the prior fiscal year, including the level of achievement of our budgeted cash distribution target for the year as discussed above;
 
  •     distribution performance for the prior fiscal year compared to the peer group;
 
  •     unitholder total return for the prior fiscal year compared to the peer group; and
 
  •     competitive compensation data for executive officers in the peer group.
 
These factors were selected as the most appropriate measures upon which to base the annual cash incentive bonus decisions going forward because the Compensation Committee believes that they will most directly correlate to increases in long-term value for our unitholders.
 
Equity-Based Awards
 
Design.  The LTIP was adopted in 2007 in connection with our formation. In adopting the LTIP, the Board recognized that it needed a source of equity to attract new members to and retain members of the management team, as well as to provide an equity incentive to other key employees. We believe the LTIP promotes a long-term focus on results and aligns executive and unitholder interests.
 
The LTIP is designed to encourage responsible and profitable growth while taking into account non-routine factors that may be integral to our success. Long-term incentive compensation in the form of equity grants are used to incentivize performance that leads to enhanced unitholder value, encourage retention and closely align the executive officers’ interests with unitholders’ interests. Equity grants provide a vital link between the long-term results achieved for our unitholders and the rewards provided to executive officers and other key employees. The equity grants we made upon adoption of the LTIP were designed to be comparable with long-term incentive plans of other coal production companies and coal master limited partnerships, based upon the industry knowledge and experience of the Non-employee Directors, and on individual negotiations with the named executive officers.
 
Phantom Units.  The only awards made under the LTIP since its adoption have been phantom units. A phantom unit is a notional unit granted under the LTIP that entitles the holder to receive an amount of cash equal to the fair market value of one common unit upon vesting of the phantom unit, unless the Board elects to pay such vested phantom unit with a common unit in lieu of cash. Unvested phantom units are forfeited at the time the holder terminates employment, except for a termination due to death or disability, which results in vesting acceleration. In general, phantom units awarded to executive officers under our LTIP vest as to 25% of the award on the initial vesting date established at the time of the award and on each of the first three anniversaries of that initial vesting date. Mr. Gutman’s LTIP awards will vest in full upon a change of control of us or our general partner.


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Equity-Based Award Policies.  Prior to 2010, equity-based awards were granted by the Board and were limited to the grants at our formation in 2007 (or for executives who joined us after our formation, upon or in connection with their commencement of employment) and grants that were made in certain limited circumstances to reward individual service and performance. In early 2010, the Board delegated a portion of its duties and responsibilities under the LTIP to the Compensation Committee. Going forward, we expect that equity-based awards will be awarded more regularly, as part of the ongoing total annual compensation package for executive officers, rather than only in such discrete circumstances. After this offering, annual equity compensation grants, if any, for the CEO will be approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Equity compensation grants, if any, for the other executive officers have been determined by the Board taking into account input from the CEO. After this offering, annual equity compensation grants for the other executive officers will be approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the CEO.
 
Equity-Based Awards for 2009.  None of our named executive officers received any equity-based awards under the LTIP in 2009. However, in January 2010, Jeffrey M. Gutman received an award of 14,984 phantom units in recognition of his performance in connection with a restructuring of certain of our indebtedness and the completion of the Phoenix Coal acquisition in September 2009. In making this award, the Board also took into account its determination that the initial equity awards granted to Mr. Gutman in connection with his commencement of employment in 2008 were, in the Board’s view based on its general industry knowledge and experience, below the level of equity participation granted to similarly situated executives at many other companies in our industry.
 
Deferred Compensation
 
Tax-deferred retirement plans are a common way that companies assist employees in preparing for retirement. Through 2009, we maintained a defined contribution money purchase pension plan to which we made contributions for the benefit of the participants, including named executive officers. Effective beginning in 2010, we provide our eligible executive officers and other employees with an opportunity to participate in our 401(k) savings plan. The plan allows executive officers and other employees to contribute compensation for retirement up to IRS imposed limits (for 2010, $16,500 for participants age 49 and under and $22,000 for participants age 50 and over), either on a tax deferred or after-tax basis. The 401(k) plan permits us to make annual discretionary contributions to the plan as a percentage of the eligible compensation of participants in the plan. Annual contributions of 3% or more of such eligible compensation will maintain “safe harbor” tax-qualified status for the plan, and while it is discretionary we intend generally to make annual contributions at that level or higher. For 2010, we have committed to make an employer discretionary contribution of 4% of such eligible compensation. Decisions regarding this element of compensation do not impact any other element of compensation.
 
Perquisites and Other Benefits
 
Although perquisites are not a significant factor in our compensation programs, we provide certain limited perquisite and personal benefits to certain of the named executive officers, including the use primarily for business purposes (with personal usage being limited to usage for commuting purposes) of company-owned automobiles for Charles C. Ungurean and Thomas T. Ungurean. We provide these benefits to assist the executive officers in performing their services for us and they are not factored into the Board’s determinations with respect to other elements of total compensation. In addition, under our company-wide policy in effect through 2009, we maintained for all salaried employees including the executive officers a vacation program that provided additional annual payments to each of our salaried employees including the executive officers in the amount of his or her base salary over a period equal to the vacation time allotted to him or her. This payment was in addition to continuing the payment of base salaries for all salaried employees including the executive officers during periods when they were on vacation. Effective in 2010, the vacation policy was changed so that no such additional payments are made but base salaries will continue to be paid to the salaried employees including the executive officers while they are on vacation. The additional vacation-related


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payments made to the named executive officers for 2009 are included in bonus amounts and set forth in a footnote to the Summary Compensation Table for 2009 below.
 
Recoupment Policy
 
We currently do not have a recoupment policy applicable to annual incentive bonuses or equity awards. The Compensation Committee expects to continue to evaluate the need to adopt such a policy, in light of current legislative policies as well as economic and market conditions.
 
Employment and Severance Arrangements
 
The Board and the Compensation Committee consider the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, we recognize that the uncertainty that may exist among management with respect to their “at-will” employment with our general partner may result in the departure or distraction of management personnel to our detriment. Accordingly, our general partner has previously entered into employment agreements with each of our named executive officers, which employment agreements contain severance arrangements that we believe are appropriate to encourage the continued attention and dedication of members of our management. Our general partner will enter into new employment agreements with our executive officers that will become effective upon the closing of this offering. These agreements will have two year terms, new base salary and target bonus amounts for each named executive officer and, in the case of Charles C. Ungurean and Thomas T. Ungurean, their eligibility to receive future awards under our LTIP. The following table sets forth information regarding the expected annual base salary and annual target bonus for each of our named executive officers under these agreements.
 
                 
        Target Annual
        Bonus
    Annual
  as a % of
Name
  Base Salary   Annual Salary
 
Charles C. Ungurean
  $ 500,000       66.6 %
Jeffrey M. Gutman
    270,000       50.0 %
Thomas T. Ungurean
    275,000       66.6 %
Gregory J. Honish
    185,000       50.0 %
Michael B. Gardner
    165,000       50.0 %
 
The employment agreements with our executive officers are described more fully below under “— Potential Payment Upon Termination or Change in Control — Employment Agreements with Named Executive Officers.”


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Summary Compensation Table for 2009
 
The following table sets forth certain information with respect to the compensation paid to the named executive officers for the year ended December 31, 2009.
 
                                 
            All Other
   
            Compensation
   
Name and Principal Position
  Salary ($)(1)   Bonus ($)(2)   ($)(3)   Total ($)
 
Charles C. Ungurean
President and Chief Executive Officer
  $ 375,002     $ 248,077     $ 17,702     $ 640,781  
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and Treasurer
    261,385       125,481       15,370       402,236  
Thomas T. Ungurean
Senior Vice President, Equipment, Procurement and Maintenance
    233,333       190,385       16,079       439,797  
Gregory J. Honish
Senior Vice President, Operations
    142,116       70,096       12,771       224,983  
Michael B. Gardner
Secretary and General Counsel
    152,083       75,567       13,560       241,210  
 
 
(1) Amounts shown in this column represent base salaries paid to the named executive officers in 2009 and include pro-rated amounts based on the increases in base salaries that occurred in 2009.
 
(2) The bonus amounts for the named executive officers reflect bonuses paid in late 2009 and early 2010 that relate to services performed in 2009, in the following amounts for each of the named executive officers: Charles C. Ungurean: $225,000; Jeffrey M. Gutman: $112,500; Thomas T. Ungurean: $175,000; Gregory J. Honish: $63,750; and Michael B. Gardner: $61,625. The bonus amounts also include vacation payments in 2009 (including in the case of Michael B. Gardner an additional payment in early 2010 with respect to cancelled vacation time in late 2009 during which he performed services for us), as follows: Charles C. Ungurean: $23,077; Jeffrey M. Gutman: $12,981; Thomas T. Ungurean: $15,385; Gregory J. Honish: $6,346; and Michael B. Gardner: $13,942.
 
(3) Amounts shown in this column include contributions being made to our defined contribution money purchase pension plan for each of the named executive officers with respect to services performed in 2009, payments made in 2009 with respect to life insurance benefits provided to each of the named executive officers and a holiday-related allowance paid in 2009 to each of the named executive officers. For each of Charles C. Ungurean and Thomas T. Ungurean, who are provided company-owned automobiles primarily for business use (with personal use being limited to usage for commuting purposes), the amount shown also includes the cost to us of providing an automobile to them for their use for the estimated personal usage portion thereof for commuting purposes (20% of the total cost in the case of Charles C. Ungurean and 5% of the total cost in the case of Thomas T. Ungurean) in the amount of $2,248 and $660, respectively.
 
Grants of Plan-Based Awards for 2009
 
The named executive officers received no grants of plan-based awards during the year ended December 31, 2009.


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Outstanding Equity-Based Awards at December 31, 2009
 
The following table provides information regarding outstanding equity-based awards held by the named executive officers as of December 31, 2009. All such equity-based awards consist of phantom units granted under the LTIP. Neither Charles C. Ungurean nor Thomas T. Ungurean held any outstanding equity-based awards at December 31, 2009. None of the named executive officers hold outstanding option awards.
 
                 
    Unit Awards
    Number of
  Market Value of
    Phantom Units
  Phantom Units
    That Have Not
  That Have Not
Name
  Vested(1)   Vested ($)(2)
 
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and Treasurer
    14,848     $ 258,801  
Gregory J. Honish
Senior Vice President, Operations
    5,128       89,381  
Michael B. Gardner
Secretary and General Counsel
    3,204       55,846  
 
 
(1) On March 31, 2010, 7,425 units vested and the remaining unvested units will vest on March 31, 2011. Messrs. Honish’s and Gardner’s remaining unvested units, which were granted in 2007, will vest 50% on December 1, 2010 and 50% on December 1, 2011.
 
(2) Based on the fair market value of our common units of $17.43 on December 31, 2009.
 
Units Vested in 2009
 
The following table shows the phantom unit awards that vested during 2009. Charles C. Ungurean and Thomas T. Ungurean did not hold or vest in any phantom unit awards in 2009 and none of the named executive officers held or exercised any stock options in 2009.
 
                 
    Number of
  Value
    Units Acquired
  Realized on
Name
  on Vesting (#)   Vesting ($)
 
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and Treasurer(1)
    7,425     $ 83,160  
Gregory J. Honish
Senior Vice President, Operations(2)
    2,564       44,691  
Michael B. Gardner
Secretary and General Counsel(2)
    1,603       27,940  
 
 
(1) Mr. Gutman’s units vested on March 31, 2009, and the value realized amount reflects a unit value of $11.20 per unit, the fair market value on such vesting date.
 
(2) Units vested on December 1, 2009, and the value realized amounts reflect a unit value of $17.43 per unit, the fair market value on such vesting date.
 
Pension Benefits
 
The named executive officers do not participate in any pension plans and received no pension benefits (other than with respect to our defined contribution money purchase pension plan) during the year ended December 31, 2009.
 
Nonqualified Deferred Compensation
 
The named executive officers do not participate in any nonqualified deferred compensation plans and received no nonqualified deferred compensation during the year ended December 31, 2009.


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Potential Payment Upon Termination or Change in Control
 
Employment Agreements with Named Executive Officers
 
Prior to 2009, Messrs. Charles C. Ungurean, Gutman, Thomas T. Ungurean, Honish and Gardner each entered into employment agreements with our general partner. Each of these employment agreements had an initial term of two years, with the exception of that of Mr. Gardner which had an initial term of one year. These employment agreements are each automatically extended for successive one-year periods unless and until either party elects to terminate the agreement by giving at least 90 days written notice prior to the commencement of the next succeeding one-year period. These employment agreements are expected to remain in effect until the closing of this offering. These agreements establish customary employment terms including base salaries, bonuses and other incentive compensation and other benefits.
 
These employment agreements also provide for, among other things, the payment of severance benefits and in some cases the continuation of certain benefits following certain terminations of employment by our general partner prior to the expiration of the term described in each of the employment agreements or the termination of employment for “Good Reason” (as defined in each of the employment agreements) by the executive officer. Under these agreements, if the executive’s employment is terminated by the general partner without “Cause” (as defined in the employment agreements) or the executive resigns for Good Reason, the executive will have the right to a lump sum cash payment by our general partner equal to one times (two times with respect to Charles C. Ungurean and Thomas T. Ungurean) the executive’s annual base salary on the date of such termination, which will be subject to reimbursement by us to our general partner. In addition, for Messrs. Charles C. Ungurean and Thomas T. Ungurean, in the event of a termination due to death or disability (as such term is defined in the employment agreements), or by our general partner without Cause, the executive and his dependents will be entitled to continued participation in our general partner’s employee benefit plans and insurance arrangements providing medical and dental benefits in which they are enrolled at the time of such termination for the remainder of the employment term, provided that the continuation is permitted at the time of termination under the terms of our general partner’s employee benefit plans and insurance arrangements. Each of the foregoing severance benefits are conditioned on the executive executing a release of claims in favor of our general partner and its affiliates including us.
 
“Cause” is defined in each employment agreement as the executive having (i) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him under the employment agreement, (ii) refused without proper reason to perform the duties and responsibilities required of him under the employment agreement, (iii) willfully engaged in conduct that is materially injurious to our general partner or its affiliates including us (monetarily or otherwise), (iv) committed an act of fraud, embezzlement or willful breach of fiduciary duty to our general partner or an affiliate including us (including the unauthorized disclosure of confidential or proprietary material information of our general partner or an affiliate including us or, in the case of Mr. Gutman’s employment agreement only, including instead the unauthorized disclosure of information that is, and is known or reasonably should have been known to the executive to be, confidential or proprietary information of our general partner or an affiliate including us) or (v) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony. “Good Reason” is defined in each employment agreement as a termination by the executive in connection with or based upon (i) a material diminution in the executive’s responsibilities, duties or authority, (ii) a material diminution in the executive’s base compensation or (iii) a material breach by us of any material provision of the employment agreement (and, in the case of Mr. Gutman’s employment agreement, a breach of obligations with respect to his LTIP award granted on March 31, 2008).
 
Each employment agreement also contains certain confidentiality covenants prohibiting each executive officer from, among other things, disclosing confidential information relating to our general partner or any of its affiliates including us. The employment agreements also contain non-competition and non-solicitation restrictions. For Messrs. Charles C. Ungurean and Thomas T. Ungurean, those provisions apply during the term of their respective agreements and continue for a period of two years following termination for any reason. In addition, in connection with the contribution of Oxford Mining Company to us in August 2007, Messrs. Charles C. Ungurean and Thomas T. Ungurean agreed that they would not compete with us in the


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coal mining business in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia and Virginia until August 24, 2014. In the cases of Messrs. Honish and Gardner, those provisions apply during the term of their respective agreements and continue for a period of 12 months following termination for any reason, except for expiration. For Mr. Gutman, the non-competition and non-solicitation restrictions will apply during the term of his agreement and for 24 months after any termination by the general partner, except in connection with the expiration of the agreement, or if Mr. Gutman initiated the termination.
 
Mr. Gutman’s employment agreement also provides that, upon a change in control with respect to us or our general partner, Mr. Gutman will be entitled to accelerated vesting of all of his unvested awards under the LTIP. Assuming that a change in control with respect to us or our general partner had occurred on December 31, 2009, Mr. Gutman would have been entitled to accelerated vesting with respect to 14,848 phantom units that he held as of such date, having a fair market value on such date of $258,801. In addition, Mr. Gutman’s employment agreement provides that, at the time of an initial public offering involving us in which a profits interest plan is adopted by our general partner, Mr. Gutman will receive a 0.5% profits participation interest in our general partner in connection with the closing of this offering. The interest would vest over the four-year period following the date of grant of the interest, and would be subject to accelerated vesting upon a change in control.
 
The following table shows the value of the severance benefits and other benefits for the named executive officers under the employment agreements, assuming each named executive officer had terminated employment on December 31, 2009.
 
                             
        Death or
    Termination
    Resignation for
 
        Disability
    Without Cause
    Good Reason
 
Name
  Payment Type   ($)     ($)     ($)  
 
Charles C. Ungurean
  Cash severance           $ 750,000     $ 750,000  
    Benefit continuation   $ 10,769       10,769          
    Total     10,769       760,769       750,000  
Thomas T. Ungurean
  Cash severance             450,000       450,000  
    Benefit continuation     9,212       9,212          
    Total     9,212       459,212       450,000  
Jeffrey M. Gutman
  Cash severance             260,000       260,000  
Gregory J. Honish
  Cash severance             150,000       150,000  
Michael B. Gardner
  Cash severance             145,000       145,000  
 
In connection with this offering, our general partner will enter into new employment agreements with each of the named executive officers. The terms of these agreements have not yet been finalized. The new agreements will contain similar change in control and termination provisions to the previous agreements. However, under these new agreements, for all of the named executive officers, if our general partner chooses to terminate a named executive officer’s employment without cause or the executive resigns for good reason, in each case within 12 months after the expiration of the agreement following notice by our general partner that it is not renewing the term of the agreement, the named executive officer would be entitled to a lump sum payment equal to six months of the named executive officer’s annual base salary.
 
Long-Term Incentive Plan
 
The board of directors of our general partner has adopted our LTIP for employees, consultants and directors of our general partner and affiliates who perform services for us. Prior to the closing of this offering, we will adopt an amended and restated LTIP, which will allow for awards of options, phantom units, restricted units, unit awards and unit appreciation rights. Distribution equivalent rights may be granted in tandem with phantom units. The amended and restated LTIP will limit the number of units that may be delivered pursuant to awards under the LTIP to a number of units equal to 10% of the number of issued and outstanding common and subordinated units immediately following the closing of this offering. However, units that are forfeited (including units forfeited in net issuances) or units that are subject to awards that are cancelled without the


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issuance of units are available for new awards under the LTIP. The LTIP provides that it is to be administered by the board of directors of our general partner, provided that the board may delegate authority to administer the LTIP to a committee of non-employee directors.
 
The LTIP may be terminated or amended at any time with respect to any units for which a grant has not yet been made. The LTIP or any part thereof may also be altered or amended from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the vested benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants, upon its termination by the plan administrator or upon the tenth anniversary of the date that the LTIP’s amendment and restatement was approved by our partners.
 
Retirement Plan
 
We provide qualified retirement plan benefits to our executive officers and all other eligible employees. Through 2009, we maintained a defined contribution money purchase pension plan to which we made contributions for the benefit of the participants. Effective with 2010, we adopted a 401(k) plan in which all eligible employees can elect to contribute compensation for retirement, either on a tax deferred or after-tax basis. We use the 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred or after-tax basis. The 401(k) plan permits all eligible employees to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. Employee contributions are subject to annual dollar limitations (for 2010, $16,500 for participants age 49 and under and $22,000 for participants age 50 and over), which are periodically adjusted for inflation. The 401(k) plan is intended to be tax-qualified under section 401(a) of the Internal Revenue Code so that contributions to the plan (other than after-tax contributions), and income earned on plan contributions, are not taxable to employees until withdrawn from the plan and so that tax-deferred contributions, if any, will be deductible when made. The plan permits us to make annual discretionary contributions to the plan as a percentage of the eligible compensation of participants in the plan. Annual contributions of 3% or more of such eligible compensation will maintain “safe harbor” tax-qualified status for the plan, and while it is discretionary we intend generally to make annual contributions at that level or higher. For 2010, we have committed to make an employer discretionary contribution of 4% of such eligible compensation.
 
Compensation of Directors
 
Our general partner’s non-employee directors are compensated for their service as directors under our general partner’s Non-Employee Director Compensation Plan. Our non-employee directors are directors that (i) are not an officer or employee of our general partner or any of its subsidiaries or affiliates, (ii) are not affiliated with or related to any party that receives compensation from our general partner or any of its subsidiaries and affiliates, and (iii) have not entered into an arrangement with our general partner or any of its subsidiaries and affiliates to receive compensation from any such entity other than in respect of his services as a member of the Board. In addition, other members of the Board that are not employees of our general partner can be approved by the Board for participation in such plan, effective as of January 1 of the calendar year following such approval.
 
Each non-employee director covered by the plan will receive an annual compensation package consisting of the following:
 
  •     a $50,000 cash retainer;
 
  •     a $50,000 annual unit grant; and
 
  •     where applicable, a committee chair retainer of $10,000 for each committee chaired.


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In addition, each non-employee director will receive per meeting fees of:
 
  •     $1,000 for Board meetings attended in person;
 
  •     where applicable, $500 for Board committee meetings attended in person; and
 
  •     $500 for telephonic Board meetings and committee meetings greater than one hour in length.
 
In addition, upon the closing of this offering, or, for non-employee directors who join us after the closing of this offering, upon their joining the Board, the Board may determine that such non-employee directors will receive a one-time grant of unrestricted common units. Furthermore, for 2011 and thereafter, each non-employee director may elect to receive the cash components, as outlined above, in the form of unrestricted common units granted under the LTIP representing an equivalent value at the date of issuance. Such elections must be made in advance of the year in which the compensation is earned or at the directors’ initial appointment for years beginning after 2010. The annual compensation package is paid to each non-employee director based on his or her service on the Board for the period beginning upon the date of his or her appointment to the Board. If a non-employee director’s service on the Board commences after the first day of a calendar year, such non-employee director will receive a prorated annual compensation package for such year. The annual Board membership retainer and, if applicable, committee chair retainer are paid in quarterly installments. For calendar year 2011 and thereafter, the annual unit grants will also be paid in quarterly installments of units having equivalent fair market value on the date of issuance. If board membership or committee chairmanship terminates during the year, amounts due on subsequent quarterly payment dates would not be paid. Units awarded to non-employee directors under the annual compensation package or upon first election to the Board, and any units issued upon a non-employee director’s election, with approval of the Compensation Committee, to receive units in lieu of cash compensation, are granted under the LTIP and vest on the date of grant. Cash distributions will be paid on these units from and after the time of their issuance. Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the Board or its committees. Each director will be indemnified by us for actions associated with being a director of our general partner to the fullest extent permitted under Delaware law.
 
Director Compensation Table for 2009
 
The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2009, as described above. None of our non-employee directors held any unvested units as of December 31, 2009.
 
                         
    Fees Earned or
       
Name
  Paid in Cash ($)   Unit Awards ($)(1)   Total ($)
 
Gerald A. Tywoniuk
  $ 30,000     $ 20,010     $ 50,010  
 
 
(1) The amount in this column represents unit awards made to directors under the LTIP in 2009. These awards were granted and vested on December 1, 2009 and had a fair market value of $17.43 per unit on such date.


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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
The following table sets forth certain information regarding the beneficial ownership of units following the consummation of this offering and the related transactions by:
 
  •     each person who is known to us to beneficially own more than 5% or more of such units to be outstanding;
 
  •     our general partner;
 
  •     each of the named directors and executive officers of our general partner; and
 
  •     all of the directors and executive officers of our general partner as a group.
 
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.
 
Our general partner is owned 33.7% by C&T Coal and 66.3% by AIM Oxford (both of which are reflected as 5% or more unitholders in the table below). C&T Coal is owned by Charles C. Ungurean and Thomas T. Ungurean, each a member of our management team, and AIM Oxford is owned by AIM Coal LLC and certain investment partnerships affiliated with AIM.
 
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of May 17, 2010, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
 
The percentage of units beneficially owned is based on a total of           common units and subordinated units outstanding immediately following this offering.
 
                                         
                Percentage of
  Percentage of
        Percentage of
  Subordinated
  Subordinated
  Total Units
    Common Units
  Common Units
  Units to be
  Units to be
  to be
    to be Beneficially
  to be Beneficially
  Beneficially
  Beneficially
  Beneficially
Name of Beneficial Owner
  Owned   Owned   Owned   Owned   Owned
 
AIM Oxford Holdings, LLC(1)(2)
                  %                   %           %
C&T Coal, Inc.(3)
            %             %     %
George E. McCown(2)
            %             %     %
Brian D. Barlow(2)
            %             %     %
Matthew P. Carbone(2)
            %             %     %
Gerald A. Tywoniuk(3)
            %             %     %
Charles C. Ungurean(3)(4)
            %             %     %
Thomas T. Ungurean(3)(4)
            %             %     %
Jeffrey M. Gutman(3)
            %             %     %
Gregory J. Honish(3)
            %             %     %
Michael B. Gardner(3)
            %             %     %
Denise M. Maksimoski(3)
            %             %     %
All directors and executive officers as a group (consisting of 10 persons)
            %             %     %
 
 
  * An asterisk indicates that the person or entity owns less than one percent.


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(1) AIM Oxford Holdings, LLC is governed by its sole manager, AIM Coal Management, LLC, a Delaware limited liability company. AIM Coal Management, LLC’s members consist of George E. McCown and Matthew P. Carbone, both directors of our general partner, and Robert B. Hellman, Jr. Messrs. McCown, Carbone and Hellman, in their capacity as members of AIM Coal Management, LLC, share voting and investment power with respect to the common and subordinated units owned by AIM Oxford Holdings, LLC.
 
(2) The address for this person or entity is 950 Tower Lane, Suite 800, Foster City, California 94404.
 
(3) The address for this person or entity is 41 South High Street, Suite 3450, Columbus, Ohio 43215.
 
(4) Charles C. Ungurean and Thomas T. Ungurean, as the shareholders of C&T Coal, Inc., share voting and investment power with respect to the common and subordinated units owned by C&T Coal, Inc.


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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
 
Immediately following the closing of this offering, C&T Coal will own           common units and           subordinated units representing a combined     % limited partner interest in us (or          common units and           subordinated units representing a combined     % limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full), and AIM Oxford will own           common units and           subordinated units representing a combined     % limited partner interest in us (or           common units and           subordinated units representing a combined     % limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). C&T Coal and AIM Oxford will own and control our general partner which owns a 2.0% general partner interest in us and all of our incentive distribution rights.
 
Distributions and Payments to Our General Partner and Its Affiliates
 
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and liquidation of Oxford Resource Partners, LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
 
Pre-IPO Stage
 
The consideration received by our general partner and its affiliates prior to or in connection with this offering
•              common units;
 
•              subordinated units;
 
•    all of our incentive distribution rights;
 
•    2.0% general partner interest; and
 
•    approximately $      million in cash and accounts receivable.
 
Post-IPO Stage
 
Distributions of available cash to our general partner and its affiliates We will initially make cash distributions 98% to the unitholders, including affiliates of our general partner, as the holders of an aggregate of           common units and all of the subordinated units and 2.0% to our general partner. If distributions exceed the minimum quarterly distribution and target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 48% of the distributions above the highest target distribution level.
 
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $      million on the 2.0% general partner interest and approximately $      million on their common units and subordinated units.
 
Payments to our general partner and its affiliates Our general partner will not receive a management fee or other compensation for its management of Oxford Resource Partners, LP. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these expenses.


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Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of Our General Partner.”
 
Liquidation Stage
 
Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
 
Ownership Interests of Certain Executive Officers and Directors of Our General Partner
 
Upon the closing of this offering, C&T Coal and AIM Oxford will continue to own 100% of our general partner. Charles C. Ungurean, the President and Chief Executive Officer 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, Brian D. Barlow, Matthew P. Carbone and George E. McCown serve on the board of directors of our general partner and are principals of AIM and have ownership interests in AIM.
 
In addition to the 2.0% general partner interest in us, our general partner owns 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 quarter, after the closing of our initial public offering. Upon the closing of this offering, C&T Coal will own           common units and subordinated units, and AIM Oxford will own           common units and           subordinated units.
 
Advisory Services Agreement
 
Upon our formation in August 2007, Oxford Mining Company entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C. and American Infrastructure MLP PE Management, L.L.C., which are affiliates of AIM, AIM Oxford and certain directors of our general partner. Our advisors performed financial and advisory services to us under this agreement, which will be terminated in connection with this offering in exchange for a one-time, non-recurring payment to our advisors of $      million. Our advisors received annual compensation in the amount of $250,000 plus a fee determined by a formula, taking into account the increase in our gross revenue over the prior year. During the year ended December 31, 2009 and the first quarter of 2010, we paid our advisors in excess of $307,000 and $77,000, respectively, for these services, as well as $1.0 million during the year ended December 31, 2009 in fees for services relating to an amendment to our existing credit facility. During 2008 we paid our advisors $225,000 for these services, and we did not pay our advisors for these services in 2007. We were also obligated to reimburse our advisors for expenses incurred by them in the performance of their services to us.
 
Administrative and Operational Services Agreement
 
On August 24, 2007, we entered into an administrative and operational services agreement with Oxford Mining Company and our general partner. Under the terms of the agreement, our general partner provides services to us and is reimbursed for all related costs incurred on our behalf. The services that our general partner provides include, among other things, general administrative and management services, human resources, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geologic services, risk management and insurance services. During the first quarter of 2010 and the years ended December 31, 2009, 2008 and 2007, we paid our general partner approximately $15.0 million, $45.2 million, $14.3 million and $139,000, respectively, for services, primarily related to payroll, performed under the agreement. Any party may terminate the


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administrative and operational services agreement by providing at least 30 days’ written notice to the other parties of its intention to terminate the agreement.
 
Contribution Agreements
 
In August 2007 we entered into a contribution and sale agreement with our general partner, C&T Coal, AIM Oxford, Charles C. Ungurean and Thomas C. Ungurean. Pursuant to the contribution and sale agreement, each of C&T Coal, Charles C. Ungurean and Thomas T. Ungurean (and any of their related parties) agreed not to directly or indirectly compete with us or to disseminate confidential information or trade secrets regarding us and our subsidiaries.
 
In March 2008 we entered into a contribution agreement with our general partner and AIM Oxford. Pursuant to this contribution agreement, we received a contribution of $8,820,000 from AIM Oxford as consideration for the issuance to AIM Oxford of 787,500 Class B common units. We also received a contribution of $180,000 from our general partner as consideration for the issuance to our general partner of approximately 16,071 general partner units.
 
In September 2008 we entered into a contribution agreement with our general partner, C&T Coal and AIM Oxford. Pursuant to this contribution agreement, we received a contribution of $686,000 from C&T Coal and a contribution of $1,274,000 from AIM Oxford as consideration for the issuance to C&T Coal and AIM Oxford of 61,250 Class B common units and 113,750 Class B common units, respectively. We also received a contribution of $40,000 from our general partner as consideration for the issuance to our general partner of approximately 3,571 general partner units.
 
In August 2009 we entered into a contribution agreement with C&T Coal and AIM Oxford. Pursuant to this contribution agreement, we received a contribution of $1,050,000 from C&T Coal and $1,950,000 from AIM Oxford as consideration for the issuance to C&T Coal and AIM Oxford of 35 deferred participation units and 65 deferred participation units, respectively.
 
In September 2009 we entered into a contribution and conversion agreement with our general partner, C&T Coal and AIM Oxford. Pursuant to the contribution and conversion agreement, we received a contribution of $1,469,993.91 from C&T Coal and $6,860,012.25 from AIM Oxford as consideration for the issuance to C&T Coal and AIM Oxford of 84,337 Class B common units and 393,575 Class B common units, respectively. We also received a contribution of $231,224.62 from our general partner as consideration for the issuance to our general partner of approximately 13,266 general partner units. In connection with the execution of the contribution and conversion agreement, C&T Coal and AIM Oxford elected to convert their deferred participation units into approximately 60,241 Class B common units and approximately 111,876 Class B common units, respectively.
 
Investors’ Rights Agreement
 
We entered into an investors’ rights agreement on August 24, 2007 with our general partner, C&T Coal, AIM Oxford, Charles C. Ungurean and Thomas C. Ungurean. Pursuant to such agreement and subject to certain restrictions, C&T Coal was granted certain demand and “piggyback” registration rights. Pursuant to the terms of the agreement, C&T Coal has the right to require us to file a registration statement for the public sale of all of the common and subordinated units it owns at any time after the offering. In addition and subject to certain restrictions, if we sell any common units in a registered underwritten offering, C&T Coal will have the right to include its common units in that offering; provided, however, that the managing underwriter or underwriters of any such offering will have the right to limit the number of common units to be included in such sale. We will pay all expenses relating to any demand or piggyback registration, except for fees and disbursements of any counsel retained by C&T Coal and any underwriter or brokers’ commission or discounts.
 
In addition, the investors’ rights agreement gives C&T Coal the right to designate a number of directors to the board of directors of our general partner proportionate to its percentage share of the total outstanding membership interests in our general partner. AIM Oxford has the right to designate the remaining members of the board of directors of our general partner. However, the number of directors C&T Coal has the right to


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appoint will be reduced in the event that the number of directors appointed by C&T Coal and the number of independent directors (as defined in our partnership agreement) are less than fifty percent of the members of the board. C&T Coal’s right to designate members of the board of directors of our general partner will terminate upon C&T Coal, Charles C. Ungurean and Thomas T. Ungurean ceasing to own in the aggregate at least 5% of our common units.
 
Tunnel Hill Partners, LP
 
The vast majority of the ownership interest in Tunnel Hill Partners, LP is directly or indirectly owned by T&C Holdco, LLC and AIM Tunnel Hill Holdings II, LLC. T&C Holdco is wholly-owned by Charles C. Ungurean and Thomas T. Ungurean. AIM Tunnel Hill Holdings II, LLC is indirectly owned by AIM.
 
We are a party to an environmental services agreement with Tunnell Hill Reclamation LLC, a wholly owned subsidiary of Tunnel Hill Partners, LP, pursuant to which we provide certain landfill operational services. Receipts for these services for the first quarter of 2010 and the years ended December 31, 2009 and 2008 were approximately $0.2 million, $0.7 million and $1.1 million, respectively. We had no such receipts for 2007.
 
In addition, pursuant to a mining agreement, Tunnell Hill Reclamation LLC has granted us access to certain properties for the purpose of conducting mining operations. As consideration for such access, we have authorized the construction by Tunnel Hill Reclamation LLC of future landfills or other waste disposal facilities on such properties.
 
Procedures for Review, Approval and Ratification of Related Person Transactions
 
The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.
 
The code of business conduct and ethics will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.
 
The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.


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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
 
Conflicts of Interest
 
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including C&T Coal and AIM Oxford), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.
 
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.
 
Our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:
 
  •     approved by the Conflicts Committee, although our general partner is not obligated to seek such approval;
 
  •     approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
 
  •     on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  •     fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to have an honest belief that he is acting in the best interests of the partnership.
 
Conflicts of interest could arise in the situations described below, among others.
 
AIM Oxford and AIM, affiliates of our general partner, may compete with us.
 
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. In addition, C&T Coal and its affiliates are prohibited from competing with us in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia and Virginia until August 2014. However, certain affiliates of our general partner, including AIM Oxford and AIM and its investment funds, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, AIM, through its investment funds and managed accounts, makes investments and purchases entities in various areas of the energy sector, including the coal industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.


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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, C&T Coal and AIM Oxford. 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. Therefore, AIM Oxford may compete with us for investment opportunities and may own an interest in entities that compete with us. Until August 2014, C&T Coal and its affiliates may only compete with us outside the six states referred to above.
 
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.
 
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of our general partner’s 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.
 
Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without those limitations, might constitute breaches of its fiduciary duty.
 
In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty. For example, our partnership agreement:
 
  •     provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith and with the honest belief that the decision was in our best interest;
 
  •     provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must either be (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) “fair and reasonable” to us, as determined by our general partner in good faith, provided 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 executive officers and directors will not be liable for monetary damages to us or our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its executive officers or directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was criminal.
 
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval
 
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought


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Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:
 
  •     the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;
 
  •     the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;
 
  •     the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;
 
  •     the negotiation, execution and performance of any contracts, conveyances or other instruments;
 
  •     the distribution of our cash;
 
  •     the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
 
  •     the maintenance of insurance for our benefit and the benefit of our partners;
 
  •     the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;
 
  •     the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;
 
  •     the indemnification of any person against liabilities and contingencies to the extent permitted by law;
 
  •     the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and
 
  •     the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.
 
Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in “good faith,” our general partner must have an honest belief that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.
 
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.
 
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
 
  •     the amount and timing of asset purchases and sales;
 
  •     cash expenditures and the amount of estimated reserve replacement expenditures;
 
  •     borrowings;
 
  •     the issuance of additional units; and
 
  •     the creation, reduction or increase of reserves in any quarter.
 
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the


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amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.
 
In addition, our general partner may use an amount, initially equal to $      million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Cash Distributions.”
 
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:
 
  •     enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or
 
  •     hastening the expiration of the subordination period.
 
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “How We Make Cash Distributions — Subordination Period.”
 
Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.
 
We will reimburse our general partner and its affiliates for expenses.
 
We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read “Certain Relationships and Related Party Transactions.”
 
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.
 
Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.
 
Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.
 
Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.
 
Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any


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affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.
 
Common units are subject to our general partner’s limited call right.
 
Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”
 
Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.
 
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
 
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the Conflicts Committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
 
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the Conflicts Committee or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
 
We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to


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our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “How We Make Cash Distributions — Distributions of Available Cash — General Partner Interest and Incentive Distribution Rights.”
 
Fiduciary Duties
 
Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify or eliminate, except for the contractual covenant of good faith and fair dealing, the fiduciary duties owed by the general partner to limited partners and the partnership.
 
Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. Without such modifications, such transactions could result in violations of our general partner’s state-law fiduciary duty standards. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner beneficial both to its owners, as well as to our unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:
 
State law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.
 
Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or our limited partners whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.


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Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders or that are not approved by the Conflicts Committee must be:
 
•    on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
•    “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
 
If our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.
 
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further 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 errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.
 
Rights and remedies of unitholders The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.
 
In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions of the partnership agreement, including the provisions discussed above. Please read “Description of the Common Units — Transfer of Common Units.” This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.


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Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “The Partnership Agreement — Indemnification.”


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DESCRIPTION OF THE COMMON UNITS
 
The Units
 
The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units and our general partner in and to partnership distributions, please read this section and “How We Make Cash Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”
 
Transfer Agent and Registrar
 
Duties
 
            will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by our unitholders:
 
  •     surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;
 
  •     special charges for services requested by a holder of a common unit; and
 
  •     other similar fees or charges.
 
There is no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of such person or entity.
 
Resignation or Removal
 
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
 
Transfer of Common Units
 
The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the proper completion, execution and delivery of a transfer application by the investor. Any later transfers of the common units will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a properly completed transfer application. By executing and delivering a transfer application, a transferee of common units:
 
  •     becomes the record holder of the transferred common units and is an assignee until admitted into our partnership as a limited partner;
 
  •     automatically requests admission as a limited partner in our partnership;
 
  •     executes and agrees to be bound by the terms and conditions of our partnership agreement;
 
  •     represents that such transferee has the capacity, power and authority to enter into the partnership agreement;
 
  •     grants powers of attorney to the executive officers of our general partner and any liquidator of us as specified in the partnership agreement; and


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  •     gives the consents, covenants, representations and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with this offering.
 
An assignee will become a limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a properly completed and duly executed transfer application has been received to be recorded on our books and records no less frequently than quarterly.
 
A transferee’s broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of common units as the absolute owner thereof. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
 
Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a properly completed transfer application obtains only:
 
  •     the right to transfer such common units to a purchaser or other transferee; and
 
  •     the right to transfer the right to seek admission as a limited partner in our partnership with respect to the transferred common units.
 
Thus, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:
 
  •     will not receive cash distributions;
 
  •     will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes;
 
  •     may not receive some federal income tax information or reports furnished to record holders of common units; and
 
  •     will have no voting rights;
 
unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders.
 
The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer such common units. The transferor does not have a duty to ensure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and deliver a properly completed transfer application to the transfer agent. Please read “The Partnership Agreement — Status as Limited Partner or Assignee.”
 
Until common units have been transferred on our books, we and the transfer agent may treat the record holder of such common units as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.


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THE PARTNERSHIP AGREEMENT
 
The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of this agreement upon request at no charge.
 
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
 
  •     with regard to certain actions taken prior to, or in connection with, the closing of this offering, please read “Summary — The Transactions”;
 
  •     with regard to distributions of available cash, please read “How We Make Cash Distributions”;
 
  •     with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;
 
  •     with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and
 
  •     with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”
 
Organization and Duration
 
We were organized in August 2007 and have a perpetual existence.
 
Purpose
 
Our purpose under the partnership agreement is limited to any business activities that are approved by our general partner and in any event that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
 
Although our general partner has the power to cause us, our operating company and its subsidiaries to engage in activities other than coal mining and marketing, our general partner may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. However, any decision by our general partner to cause us or our subsidiaries to invest in activities will be subject to its fiduciary duties as modified by our partnership agreement. In general, our general partner is authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
 
Power of Attorney
 
Each limited partner and each person who acquires a unit from a unitholder and executes and delivers a transfer application and certification, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance, or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.
 
Capital Contributions
 
Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”


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Voting Rights
 
The following matters require the limited partner vote specified below. Various matters require the approval of a “unit majority,” which means:
 
  •     during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, each voting as a separate class; and
 
  •     after the subordination period, the approval of a majority of the outstanding common units.
 
By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.
 
In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us and our limited partners.
 
Issuance of additional units No approval rights.
 
Amendment of our partnership agreement Certain amendments may be made by our general partner without the approval of our limited partners. Other amendments generally require the approval of a unit majority. Please read “— Amendment of Our Partnership Agreement.”
 
Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances. Please read “— Merger, Sale or Other Disposition of Assets.”
 
Continuation of our partnership upon dissolution Unit majority. Please read “— Termination and Dissolution.”
 
Withdrawal of our general partner No approval rights. Please read “— Withdrawal or Removal of Our General Partner.”
 
Removal of our general partner Not less than 80% of the outstanding common units and subordinated units, voting as a single class, including common units and subordinated units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”
 
Transfer of our general partner interest After 2020, our general partner may transfer all or any of its general partner interest in us without approval. Prior to such date, the approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for a transfer of the general partner interest. Please read “— Transfer of General Partner Interest.”
 
Transfer of incentive distribution rights No approval rights. Please read “— Transfer of Incentive Distribution Rights.”
 
Transfer of ownership interests in our general partner No approval required at any time. Please read “— Transfer of Ownership Interests in Our General Partner.”


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Limited Liability
 
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital they are obligated to contribute to us for their common units plus their share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:
 
  •     to remove or replace our general partner;
 
  •     to approve some amendments to our partnership agreement; or
 
  •     to take other action under our partnership agreement;
 
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.
 
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
 
Our subsidiaries conduct business in Kentucky and Ohio. Our subsidiaries may conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.
 
Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our membership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
 
Issuance of Additional Securities
 
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.


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It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.
 
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.
 
Our general partner’s 2.0% general partner interest is subject to dilution. If we issue additional partnership securities in the future, our general partner must either make additional capital contributions to us to maintain its 2.0% general partner interest or its interests will be effectively diluted. Our general partner can choose to contribute capital by foregoing its right to receive future distributions in an amount equal to the capital to be contributed. Our general partner will also have the option to make a capital contribution in order to maintain its 2.0% general partner interest by contributing to us common units with a current market value equal to the capital to be contributed. In addition, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities to the extent necessary to maintain its and its affiliates’ limited partner percentage interest in us, whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.
 
Amendment of Our Partnership Agreement
 
General
 
Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
 
Prohibited Amendments
 
No amendment may:
 
(1) enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
 
(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.
 
The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) and (2) above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the consummation of this offering, affiliates of our general partner will own     % of the outstanding common and subordinated units as a single class (or     % of the outstanding common and subordinated units as a single class, if the underwriters exercise their option to purchase additional common units in full).


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No Unitholder Approval
 
Our general partner may generally make amendments to the partnership agreement without the approval of any limited partner or assignee to reflect:
 
(1) a change in our name, the location of our principal place of business, our registered agent or our registered office;
 
(2) the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
 
(3) a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
 
(4) a change in our fiscal year or taxable year and related changes;
 
(5) an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed;
 
(6) an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;
 
(7) any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
 
(8) an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
 
(9) any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;
 
(10) mergers with, conveyances to or conversions to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or
 
(11) any other amendments substantially similar to any of the matters described above.
 
In addition, our general partner may make amendments to the partnership agreement without the approval of any limited partner or assignee if our general partner determines that those amendments:
 
(1) do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
 
(2) are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
 
(3) are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
 
(4) are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or


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(5) are required to effect the intent expressed in the contribution agreement, this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
 
Opinion of Counsel and Limited Partner Approval
 
Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under “— No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.
 
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.
 
Merger, Sale or Other Disposition of Assets
 
A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.
 
In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange, or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries’ assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries’ assets under a foreclosure or other realization upon those encumbrances without that approval.
 
If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The limited partners are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets, or any other transaction or event.
 
Our general partner may consummate any merger or consolidation without the approval of our limited partners if we are the surviving entity in the transaction, the transaction would not result in an amendment to our partnership agreement that the general partner could not adopt unilaterally, each of our units will be an identical unit of our partnership following the transaction, the units to be issued do not exceed 20% of our outstanding units immediately prior to the transaction and our general partner has received an opinion of counsel regarding certain limited liability and tax matters.


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Termination and Dissolution
 
We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
 
(1) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor general partner;
 
(2) the election of our general partner to dissolve us, if approved by the holders of a unit majority;
 
(3) the entry of a decree of judicial dissolution of our partnership; or
 
(4) at any time there are no limited partners, unless the partnership is continued without dissolution in accordance with the Delaware Act.
 
Upon a dissolution under clause (1), the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of a unit majority, subject to our receipt of an opinion of counsel to the effect that:
 
  •     the action would not result in the loss of limited liability of any limited partner; and
 
  •     neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).
 
Liquidation and Distribution of Proceeds
 
Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.
 
Withdrawal or Removal of Our General Partner
 
Our general partner may withdraw as general partner without obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest and incentive distribution rights in us without the approval of the limited partners. Please read “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights.”
 
Upon a voluntary withdrawal of our general partner after giving written notice to all partners, a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up, and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”
 
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 80% of all outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The


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ownership of more than 20% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, affiliates of our general partner will own     % of the outstanding units (or     % of the outstanding units, if the underwriters exercise their option to purchase additional common units in full).
 
Our partnership agreement also provides that if our general partner is removed as our general partner without cause and no units held by our general partner and its affiliates are voted in favor of that removal:
 
  •     the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
 
  •     any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •     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 based on the fair market value of the interests at the time.
 
In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
 
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
 
In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
 
Transfer of General Partner Interest
 
Prior to        2020, our general partner may not transfer all or any part of its general partner interests in us to another person. After        2020, our general partner may transfer all or any part of its general partner interest in us to another person without the approval of the unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.
 
Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.
 
Transfer of Ownership Interests in Our General Partner
 
At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.


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Transfer of Incentive Distribution Rights
 
Our general partner or any other holder of incentive distribution rights may transfer any or all of its incentive distribution rights without unitholder approval.
 
Change of Management Provisions
 
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.
 
If our general partner is removed without cause and no units held by our general partner and its affiliates are voted in favor of that removal, our partnership agreement provides that, among other things, (i) all outstanding subordinated units will immediately convert into common units, (ii) any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished and (iii) our general partner will have the right to convert its general partner interest and incentive distribution rights into common units or receive cash in exchange for those interests. Please read “— Withdrawal or Removal of Our General Partner.”
 
Limited Call Right
 
If at any time our general partner and its affiliates own more than 80% of the outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:
 
  •     the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and
 
  •     the current market price as of the date three days before the date the notice is mailed.
 
As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences — Disposition of Common Units.”
 
Meetings; Voting
 
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.
 
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are


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signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.
 
Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.
 
Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
 
Status as Limited Partner or Assignee
 
Except as described above under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.
 
An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee that has not become a limited partner at the written direction of the assignee. Please read “— Meetings; Voting.” Transferees who do not execute and deliver a transfer application and certification will not be treated as assignees or as record holders of common units, and will not receive cash distributions, federal income tax allocations, or reports furnished to holders of common units unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders. Please read “Description of the Common Units — Transfer of Common Units.”
 
Non-Citizen Assignees; Redemption
 
If we are or become subject to federal, state, or local laws or regulations that, in the determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, 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


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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 and subordinated units of any holder that our general partner concludes is not an eligible citizen or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the lesser of (i) their current market price and (ii) the price paid for each such unit by the unitholder. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.
 
Indemnification
 
Under our partnership agreement, we will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, or similar events:
 
(1) our general partner;
 
(2) any departing general partner;
 
(3) any person who is or was an affiliate of our general partner or any departing general partner;
 
(4) any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above or any of their subsidiaries;
 
(5) any person who is or was serving as a director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner or any of their affiliates; and
 
(6) any person designated by our general partner.
 
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.
 
Reimbursement of Expenses
 
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.
 
Books and Reports
 
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, we use the calendar year.
 
We will furnish or make available (by posting on our website or other reasonable means) to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.


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We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.
 
Right to Inspect Our Books and Records
 
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable demand and at its own expense, have furnished to him:
 
  •     a current list of the name and last known address of each partner;
 
  •     a copy of our tax returns;
 
  •     information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;
 
  •     copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;
 
  •     information regarding the status of our business and financial condition; and
 
  •     any other information regarding our affairs as is just and reasonable.
 
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.
 
Registration Rights
 
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units, or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Oxford Resources GP as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”


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UNITS ELIGIBLE FOR FUTURE SALE
 
After the sale of the common units offered by this prospectus, C&T Coal and AIM Oxford will hold an aggregate of           and           common units and           and           subordinated units, respectively (or           and           common units and           and           subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.
 
The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
 
  •     1% of the total number of the securities outstanding; or
 
  •     the average weekly reported trading volume of the common units for the four weeks prior to the sale.
 
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.
 
Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”
 
Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.
 
C&T Coal, AIM Oxford, our general partner and the executive officers and directors of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.


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MATERIAL FEDERAL INCOME TAX CONSEQUENCES
 
This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Oxford Resource Partners, LP and our operating subsidiaries.
 
The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, IRAs, real estate investment trusts (REITs) or mutual funds. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.
 
No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
 
All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.
 
For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).
 
Partnership Status
 
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.


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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the mining, production, transportation, storage and marketing of coal and certain other natural resources. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.
 
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:
 
  •     We will be classified as a partnership for federal income tax purposes; and
 
  •     Each of our operating subsidiaries will be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes.
 
In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied are:
 
  •     Neither we nor the operating subsidiaries has elected or will elect to be treated as a corporation; and
 
  •     For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and
 
We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.
 
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
 
If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.


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The discussion below is based on Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.
 
Limited Partner Status
 
Unitholders who have become limited partners of Oxford Resource Partners, LP will be treated as partners of Oxford Resource Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Oxford Resource Partners, LP for federal income tax purposes.
 
A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”
 
Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Oxford Resource Partners, LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Oxford Resource Partners, LP for federal income tax purposes.
 
Tax Consequences of Unit Ownership
 
Flow-Through of Taxable Income.  Subject to the discussion below under “— Entity-Level Collections,” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
 
Treatment of Distributions.  Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”
 
A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, depletion recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.


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Ratio of Taxable Income to Distributions.  We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2013, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:
 
  •     gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or
 
  •     we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.
 
Basis of Common Units.  A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Limitations on Deductibility of Losses.  The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholders’ tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.
 
In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for


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repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
 
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.
 
A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
 
Limitations on Interest Deductions.  The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
 
  •     interest on indebtedness properly allocable to property held for investment;
 
  •     our interest expense attributed to portfolio income; and
 
  •     the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
 
The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
 
Entity-Level Collections.  If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.
 
Allocation of Income, Gain, Loss and Deduction.  In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner,


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gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.
 
Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
 
An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
 
  •     his relative contributions to us;
 
  •     the interests of all the partners in profits and losses;
 
  •     the interest of all the partners in cash flow; and
 
  •     the rights of all the partners to distributions of capital upon liquidation.
 
Latham & Watkins LLP is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.
 
Treatment of Short Sales.  A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
 
  •     any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
 
  •     any cash distributions received by the unitholder as to those units would be fully taxable; and
 
  •     all of these distributions would appear to be ordinary income.
 
Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders


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desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Alternative Minimum Tax.  Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
 
Tax Rates.  Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
 
The recently enacted Patient Protection and Affordable Care Act of 2010, as amended by the Health Care and Education Reconciliation Act of 2010 is scheduled to impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
 
Section 754 Election.  We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “— Disposition of Common Units — Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets (“common basis”) and (ii) his Section 743(b) adjustment to that basis.
 
We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”


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We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” Latham & Watkins LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.
 
A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built — in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built — in loss or a basis reduction is substantial if it exceeds $250,000.
 
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
 
Tax Treatment of Operations
 
Accounting Method and Taxable Year.  We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his


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taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”
 
Initial Tax Basis, Depreciation and Amortization.  The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”
 
To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
 
If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”
 
The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.
 
Valuation and Tax Basis of Our Properties.  The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
 
Coal Income.  Section 631 of the Internal Revenue Code provides special rules by which gains or losses on the sale of coal may be treated, in whole or in part, as gains or losses from the sale of property used in a trade or business under Section 1231 of the Internal Revenue Code. Specifically, Section 631(c) provides that if the owner of coal held for more than one year disposes of that coal under a contract by virtue of which the owner retains an economic interest in the coal, the gain or loss realized will be treated under Section 1231 of the Internal Revenue Code as gain or loss from property used in a trade or business. Section 1231 gains and losses may be treated as capital gains and losses. Please read “— Sales of Coal Reserves.” In computing such gain or loss, the amount realized is reduced by the adjusted depletion basis in the coal, determined as described in “— Coal Depletion.” For purposes of Section 631(c), the coal generally is deemed to be disposed of on the day on which the coal is mined. Further, Treasury regulations promulgated under Section 631 provide that advance royalty payments may also be treated as proceeds from sales of coal to which Section 631 applies and, therefore, such payment may be treated as capital gain under Section 1231. However, if the right to mine the related coal expires or terminates under the contract that provides for the payment of advance royalty payments or such right is abandoned before the coal has been mined, we may, pursuant to the


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Treasury regulations, file an amended return that reflects the payments attributable to unmined coal as ordinary income and not as received from the sale of coal under Section 631.
 
Our royalties from coal leases generally will be treated as proceeds from sales of coal to which Section 631 applies. Accordingly, the difference between the royalties paid to us by the lessees and the adjusted depletion basis in the extracted coal generally will be treated as gain from the sale of property used in a trade or business, which may be treated as capital gain under Section 1231. Please read “— Sales of Coal Reserves.” Our royalties that do not qualify under Section 631(c) generally will be taxable as ordinary income in the year of sale.
 
Coal Depletion.  In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%.
 
Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Please read “— Tax Consequences of Unit Ownership — Alternative Minimum Tax.” Upon the disposition of the mineral property, a portion of the gain, if any, equal to the lesser of the deductions for depletion which reduce the adjusted tax basis of the mineral property plus deductible development and mining exploration expenses (discussed below), or the amount of gain recognized upon the disposition, will be treated as ordinary income to us. In addition, a corporate unitholder’s allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner’s allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.
 
Mining Exploration and Development Expenditures.  We will elect to currently deduct mining exploration expenditures that we pay or incur to determine the existence, location, extent or quality of coal deposits prior to the time the existence of coal in commercially marketable quantities has been disclosed.
 
Amounts we deduct for mine exploration expenditures must be recaptured and included in our taxable income at the time a mine reaches the production stage, unless we elect to reduce future depletion deductions by the amount of the recapture. A mine reaches the producing stage when the major part of the coal production is obtained from working mines other than those opened for the purpose of development or the principal activity of the mine is the production of developed coal rather than the development of additional coal for mining. This recapture is accomplished through the disallowance of both cost and percentage depletion deductions on the particular mine reaching the producing stage. This disallowance of depletion deductions continues until the amount of adjusted exploration expenditures with respect to the mine have been fully recaptured. This recapture is not applied to the full amount of the previously deducted exploration expenditures. Instead, these expenditures are reduced by the amount of percentage depletion, if any, that was lost as a result of deducting these exploration expenditures.
 
We generally elect to defer mine development expenses, consisting of expenditures incurred in making coal accessible for extraction, after the exploration process has disclosed the existence of coal in commercially marketable quantities, and deduct them on a ratable basis as the coal benefited by the expenses is sold.
 
Mine exploration and development expenditures are subject to recapture as ordinary income to the extent of any gain upon a sale or other disposition of our property or of your common units. See “— Disposition of Common Units.” Corporate unitholders are subject to an additional rule that requires them to capitalize a portion of their otherwise deductible mine exploration and development expenditures. Corporate unitholders, other than some S corporations, are required to reduce their otherwise deductible exploration expenditures by 30%. These capitalized mine exploration and development expenditures must be amortized over a 60-month period, beginning in the month paid or incurred, using a straight-line method and may not be treated as part of the basis of the property for purposes of computing depletion.


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When computing the alternative minimum tax, mine exploration and development expenditures are capitalized and deducted over a ten year period. Unitholders may avoid this alternative minimum tax adjustment of their mine exploration and development expenditures by electing to capitalize all or part of the expenditures and deducting them over ten years for regular income tax purposes. You may select the specific amount of these expenditures for which you wish to make this election.
 
Sales of Coal Reserves.  If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the mined coal sold are held by us:
 
  •     for sale to customers in the ordinary course of business (i.e., we are a “dealer” with respect to that property);
 
  •     for use in a trade or business within the meaning of Section 1231 of the Internal Revenue Code; or
 
  •     as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.
 
In determining dealer status with respect to coal reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property and sale in question.
 
We intend to hold our coal reserves for use in a trade or business and achieving long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales of coal reserves. Thus, the general partner does not believe we will be viewed as a dealer. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a “dealer” in coal reserves.
 
If we are not a dealer with respect to our coal reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Internal Revenue Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.
 
A unitholder’s distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Internal Revenue Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.
 
If we are not a dealer with respect to our coal reserves and that property is not used in a trade or business, the property will be a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code. Gain or loss recognized from the disposition of that property will be taxable as capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period of such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.
 
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mining exploration expenses or (2) the amount of gain recognized on the disposition, will be treated as ordinary income to us.
 
Deduction for U.S. Production Activities.  Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentage is currently 9% for qualified production activities income.
 
Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.
 
For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”
 
The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.
 
Disposition of Common Units
 
Recognition of Gain or Loss.  Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
 
Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.
 
Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2010 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation and depletion recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of


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a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
 
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
 
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
 
  •     a short sale;
 
  •     an offsetting notional principal contract; or
 
  •     a futures or forward contract with respect to the partnership interest or substantially identical property.
 
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
 
Allocations Between Transferors and Transferees.  In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
 
Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations;


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however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
 
A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
 
Notification Requirements.  A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.
 
Constructive Termination.  We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
 
Uniformity of Units
 
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”
 
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under


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Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “— Tax Consequences of Unit Ownership — Section 754 Election,” Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Tax-Exempt Organizations and Other Investors
 
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
 
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.
 
Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
 
In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
 
A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of


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that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.
 
Administrative Matters
 
Information Returns and Audit Procedures.  We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
 
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.
 
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names Oxford Resources GP, LLC as our Tax Matters Partner.
 
The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
 
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.


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Nominee Reporting.  Persons who hold an interest in us as a nominee for another person are required to furnish to us:
 
  •     the name, address and taxpayer identification number of the beneficial owner and the nominee;
 
  •     whether the beneficial owner is:
 
  •     a person that is not a U.S. person;
 
  •     a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
 
  •     a tax-exempt entity;
 
  •     the amount and description of units held, acquired or transferred for the beneficial owner; and
 
  •     specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
 
Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
 
Accuracy-Related Penalties.  An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
 
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
 
  •     for which there is, or was, “substantial authority”; or
 
  •     as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
 
If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.
 
A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.
 
No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or


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more than the correct valuation, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.
 
Reportable Transactions.  If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”
 
Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:
 
  •     accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;
 
  •     for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and
 
  •     in the case of a listed transaction, an extended statute of limitations.
 
We do not expect to engage in any “reportable transactions.”
 
Recent Legislative Developments
 
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, members of Congress have recently considered and are considering substantive changes to the existing federal income tax laws that could affect certain publicly traded partnerships. As previously and currently proposed, we do not believe any such legislation would affect our tax treatment as a partnership. However, the proposed legislation could be modified in a way that could affect us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.
 
On February 1, 2010, the White House released President Obama’s budget proposal for the fiscal year 2011 (the “Budget Proposal”). Among the changes contained in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences currently available 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.
 
Legislation has been introduced in the Senate and includes many of the proposals outlined in the Budget Proposal. It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the Budget Proposal or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to coal exploration and development and could negatively impact the value of an investment in our units.
 
State, Local, Foreign and Other Tax Considerations
 
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider


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their potential impact on his investment in us. We will initially own property or do business in Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. Each of these states imposes a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.
 
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.


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INVESTMENT IN OXFORD RESOURCE PARTNERS, LP BY EMPLOYEE BENEFIT PLANS
 
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. Among other things, consideration should be given to:
 
  •     whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;
 
  •     whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;
 
  •     whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences — Tax-Exempt Organizations and Other Investors;” and
 
  •     whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.
 
The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
 
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.
 
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.
 
The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:
 
(a) the equity interests acquired by the employee benefit plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;
 
(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or


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(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by the employee benefit plans referred to above that are subject to ERISA and IRAs and other similar vehicles that are subject to Section 4975 of the Internal Revenue Code.
 
Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.
 
In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.


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UNDERWRITING
 
Barclays Capital Inc. and Citigroup Global Markets Inc. are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:
 
         
    Number of
 
Underwriters
  Common Units  
 
Barclays Capital Inc. 
           
Citigroup Global Markets Inc.
       
         
Total
                
         
 
The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:
 
  •     the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;
 
  •     the representations and warranties made by us to the underwriters are true;
 
  •     there is no material change in our business or the financial markets; and
 
  •     we deliver customary closing documents to the underwriters.
 
Commissions and Expenses
 
The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.
 
                 
    No Exercise     Full Exercise  
 
Per Common Unit
  $           $        
                 
Total
  $       $  
                 
 
The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $      per common unit. After the offering, the representatives may change the offering price and other selling terms.
 
The expenses of the offering that are payable by us are estimated to be $     (excluding underwriting discounts and commissions).
 
Option to Purchase Additional Common Units
 
We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of          additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than           common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.


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Lock-Up Agreements
 
We, our subsidiaries, our general partner and its affiliates, including C&T Coal and AIM Oxford and the directors and executive officers of our general partner, have agreed that without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the Securities and Exchange Commission and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.
 
The 180-day restricted period described in the preceding paragraph will be extended if:
 
  •     during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or
 
  •     prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of material event unless such extension is waived in writing by Barclays Capital Inc.
 
Barclays Capital Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time. Barclays Capital Inc. does not have any present intention or any understandings, implicit or explicit, to release any of the common units or other securities subject to the lock-up agreements prior to the expiration of the lock-up period described above.
 
As described below under “— Directed Unit Program,” any participants in the Directed Unit Program will be subject to a 180-day lock up with respect to any common units sold to them pursuant to that program. This lock up will have similar restrictions and an identical extension provision as the lock-up agreement described above. Any common units sold in the Directed Unit Program to our general partner’s directors or officers will be subject to the lock-up agreement described above.
 
Offering Price Determination
 
Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:
 
  •     the history and prospects for the industry in which we compete;
 
  •     our financial information;
 
  •     the ability of our management and our business potential and earning prospects;
 
  •     the prevailing securities markets at the time of this offering; and


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  •     the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.
 
Indemnification
 
We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the Directed Unit Program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.
 
Directed Unit Program
 
At our request, the underwriters have established a Directed Unit Program under which they have reserved for sale at the initial public offering price up to           common units offered hereby for officers, directors, employees and certain friends and family of our sponsors, officers, directors and employees. The number of common units available for sale to the general public will be reduced by the number of directed common units purchased by participants in the program. Any directed common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby. Any participants in this program will be prohibited from selling, pledging or assigning any common units sold to them pursuant to this program for a period of 180 days after the date of this prospectus. This 180-day lock up period will be extended with respect to our issuance of an earnings release or if a material news or a material event relating to us occurs, in the same manner as described above under “— Lock-Up Agreements.”
 
Stabilization, Short Positions and Penalty Bids
 
The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:
 
  •     Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
 
  •     A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
 
  •     Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.
 
  •     Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
 
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market


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price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.
 
Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
 
Electronic Distribution
 
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
 
Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
 
New York Stock Exchange
 
We have applied to list our common units on the New York Stock Exchange under the symbol “OXF.” The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.
 
Discretionary Sales
 
The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.
 
Stamp Taxes
 
If you purchase common units offered by this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.
 
Relationships/FINRA Conduct Rules
 
An affiliate of Citigroup Global Markets Inc. has performed commercial banking services for us for which it has received customary fees and expenses. The underwriters and their affiliates may in the future perform investment banking, commercial banking and advisory services for us from time to time for which they may in the future receive customary fees and expenses. An affiliate of Citigroup Global Markets Inc. is a lender under our new credit facility and our existing credit facility and will receive a portion of the net proceeds from this offering pursuant to our repayment of the outstanding balance under our existing credit facility.
 
Because the Financial Industry Regulatory Authority, Inc., or FINRA, views the common units offered hereby as interests in a direct participation program, there is no conflict of interest between us and the underwriters under Rule 2720 of the National Association of Securities Dealers, Inc., or NASD, Conduct Rules and the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability


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with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
 
Selling Restrictions
 
Public Offer Selling Restrictions Under the Prospectus Directive
 
In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:
 
  •     to any legal entity that is authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;
 
  •     to any legal entity that has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;
 
  •     to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives; or
 
  •     in any other circumstances that do not require the publication of a prospectus pursuant to Article 3 of the Prospectus Directive,
 
provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.
 
For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state.
 
We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.
 
Selling Restrictions Addressing Additional United Kingdom Securities Laws
 
This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“Qualified Investors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.
 
Notice to Prospective Investors in Switzerland
 
This document, as well as any other material relating to the common units that are the subject of the offering contemplated by this prospectus, do not constitute an issue prospectus pursuant to Article 652a and/or 1156 of the Swiss Code of Obligations. The common units will not be listed on the SIX Swiss Exchange and, therefore, the documents relating to the common units, including, but not limited to, this document, do not


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claim to comply with the disclosure standards of the listing rules of SIX Swiss Exchange and corresponding prospectus schemes annexed to the listing rules of the SIX Swiss Exchange. The common units are being offered in Switzerland by way of a private placement, i.e., to a small number of selected investors only, without any public offer and only to investors who do not purchase the common units with the intention to distribute them to the public. The investors will be individually approached by the issuer from time to time. This document, as well as any other material relating to the common units, is personal and confidential and do not constitute an offer to any other person. This document may only be used by those investors to whom it has been handed out in connection with the offering described herein and may neither directly nor indirectly be distributed or made available to other persons without express consent of the issuer. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in (or from) Switzerland.


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VALIDITY OF THE COMMON UNITS
 
The validity of the common units offered hereby will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.
 
EXPERTS
 
The consolidated financial statements of Oxford Resource Partners, LP and subsidiaries for the years ended December 31, 2009 and 2008, the period from August 24, 2007 to December 31, 2007 and of Oxford Mining Company and subsidiaries (the predecessor) for the period from January 1, 2007 to August 23, 2007 have been included in this prospectus in reliance upon the report of Grant Thornton LLP an independent registered public accounting firm, appearing elsewhere herein and upon the authority of said firm as experts in accounting and auditing in giving said reports.
 
The combined financial statements for the carved-out surface mining operations of Phoenix Coal Inc. for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007 included in this prospectus have been audited by Ernst & Young LLP an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of said firm as experts in accounting and auditing.
 
The information included in this prospectus relating to the estimates of our proven and probable reserves associated with our surface mining operations in Ohio is derived from our internal estimates, which estimates were audited by John T. Boyd Company, an independent mining and geological consulting firm. The information included in this prospectus relating to 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 is derived from reserve reports prepared by John T. Boyd Company. This information is included in this prospectus upon the authority of said firm as an expert.
 
WHERE YOU CAN FIND MORE INFORMATION
 
We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates or from the SEC’s web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.
 
As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet will be located at http://www.oxfordresources.com, and 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.
 
We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make


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available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.
 
FORWARD-LOOKING STATEMENTS
 
Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “will,” “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of financial condition or of results of operations, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.


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INDEX TO FINANCIAL STATEMENTS
 
         
       
    F-2  
    F-5  
    F-6  
    F-7  
    F-8  
    F-10  
    F-11  
    F-12  
    F-13  
    F-14  
    F-25  
    F-26  
    F-27  
    F-28  
    F-29  
    F-30  
       
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
       
    F-55  
    F-56  
    F-57  
    F-58  
    F-59  
    F-60  


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OXFORD RESOURCE PARTNERS, LP
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
 
Introduction
 
Set forth below are the unaudited pro forma consolidated balance sheet of Oxford Resource Partners, LP as of March 31, 2010 and the unaudited pro forma consolidated statements of operations of Oxford Resource Partners, LP for the year ended December 31, 2009 and the three months ended March 31, 2010. References to “we,” “us” and “our” mean Oxford Resource Partners, LP and its consolidated subsidiaries, unless the context requires otherwise.
 
Our unaudited pro forma consolidated balance sheet, which presents the pro forma effects of the transactions described below under “— Pro Forma Consolidated Balance Sheet” (the “Offering Transactions”) as if such transactions occurred on March 31, 2010, has been derived from, and should be read in conjunction with, our unaudited historical financial statements included elsewhere in this prospectus. Our unaudited pro forma consolidated statements of operations for the year ended December 31, 2009, which present the pro forma effects of the Offering Transactions and the Phoenix Coal acquisition described below under “— Pro Forma Consolidated Statement of Operations” as if such transactions occurred on January 1, 2009, have been derived from, and should be read in conjunction with, our audited and unaudited historical financial statements included elsewhere in this prospectus and the audited combined statements of operations and comprehensive loss for the carved-out surface mining operations of Phoenix Coal Inc. included elsewhere in this prospectus. Our unaudited pro forma consolidated statements of operations for the quarter ended March 31, 2010 assume this offering and the transactions related to this offering occurred as of January 1, 2009. We have not made pro forma adjustments to our unaudited historical consolidated balance sheet as of March 31, 2010 for the Phoenix Coal acquisition because that acquisition occurred on September 30, 2009, and, therefore, the effects of that acquisition are already reflected in our unaudited historical consolidated balance sheet as of March 31, 2010.
 
Our unaudited pro forma consolidated financial statements are based on certain assumptions and do not purport to be indicative of the results that actually would have been achieved if the Offering Transactions and the Phoenix Coal acquisition, as applicable, had been completed on the dates set forth above. Moreover, they do not project our financial position or results of operations as of any future date or for any future period.
 
Pro Forma Consolidated Balance Sheet
 
Our unaudited pro forma consolidated balance sheet is derived from our unaudited historical condensed consolidated balance sheet as of March 31, 2010. The “Adjustments for Offering Transactions” column in our unaudited pro forma consolidated balance sheet contains the adjustments that we believe are appropriate to give effect to the Offering Transactions that will occur in connection with our initial public offering (the “Offering”) assuming a March 31, 2010 offering date. Please read “— Note 1. Pro Forma Consolidated Balance Sheet Adjustments.” The Offering Transactions include:
 
  •     our distribution of approximately $      million of cash and accounts receivable to Oxford Resources GP, LLC (our “General Partner”), C&T Coal, Inc. (“C&T Coal”), AIM Oxford Holdings, LLC (“AIM Oxford”), and the participants in our Long-Term Incentive Plan (our “LTIP”) that hold our common units pro rata;
 
  •     the split of our General Partner’s 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;
 
  •     the split of the common units held by participants in our LTIP resulting in those participants receiving           common units for each common unit they currently own, resulting in their ownership of           common units, representing an aggregate     % limited partner interest in us;


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OXFORD RESOURCE PARTNERS, LP
 
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
  •     the split of the Class B common units held by C&T Coal resulting in C&T Coal receiving           Class B common units for each Class B common unit it currently owns, resulting in its ownership of           Class B common units, representing an aggregate     % limited partner interest in us;
 
  •     the split of the Class B common units held by AIM Oxford resulting in AIM Oxford receiving           Class B common units for each Class B common unit it currently owns, resulting in its ownership of           Class B common units, representing an aggregate     % limited partner interest in us;
 
  •     the conversion of all of our Class B common units held by C&T Coal, 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 conversion of all of our Class B common units held by AIM Oxford, 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;
 
  •     our entry into a new credit facility;
 
  •     the issuance by us to the public of           common units, representing a     % limited partner interest in us;
 
  •     the use of the net proceeds from the Offering to:
 
  •     repay in full the outstanding balance under our existing credit facility;
 
  •     distribute approximately $      million to C&T Coal in respect of its limited partner interest in us;
 
  •     distribute approximately $      million to the participants in the LTIP that hold our common units in respect of their limited partner interests in us; and
 
  •     pay offering expenses of approximately $      million; and
 
  •     the use of the net proceeds from borrowings under our new credit facility of approximately $      to distribute approximately $      million to AIM Oxford in respect of its limited partner interest in us and to pay fees and expenses associated with our new credit facility of approximately $      million.
 
Pro Forma Consolidated Statement of Operations
 
On September 30, 2009, we acquired 100% of the active surface mining coal operations of Phoenix Coal. Our unaudited pro forma consolidated statements of operations are derived from our audited historical consolidated statement of operations for the year ended December 31, 2009, our unaudited condensed historical consolidated statement of operations for the three months ended March 31, 2010 and the audited combined statements of operations and comprehensive loss for the carved-out surface mining operations of Phoenix Coal Inc. for the nine-month period ended September 30, 2009.
 
The “Pro Forma Adjustments” column in our unaudited pro forma consolidated statements of operations for the year ended December 31, 2009 contains the adjustments that we believe are appropriate to present the Phoenix Coal acquisition on a pro forma basis assuming a January 1, 2009 acquisition date. Please read “— Note 2. Pro Forma Consolidated Statement of Operations Adjustments.” These adjustments include, among other things, the following:
 
  •     increases in revenue as a result of the amortization of below-market coal sales contracts during the period from January 1, 2009 to September 30, 2009 (the “Stub Period”);


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OXFORD RESOURCE PARTNERS, LP
 
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
  •     adjustments in depreciation, depletion and amortization expense, or DD&A expense, over the Stub Period due to a new fair value basis of assets as a result of change in control accounting and our leasing of equipment from a third party that was previously owned by Phoenix Coal; and
 
  •     various adjustments to apply our accounting policies to the Phoenix Coal financial statements during the Stub Period.
 
The “Adjustments for Offering Transactions” column in our unaudited pro forma consolidated statements of operations contains the adjustments that we believe are appropriate to give effect to the Offering Transactions that will occur in connection with the Offering assuming a January 1, 2009 offering date. Please read “— Note 2. Pro Forma Consolidated Statement of Operations Adjustments.” We have not made adjustments to give effect to the 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.


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          Adjustments for
       
          Offering
       
    Oxford Resource
    Transactions
    Pro Forma
 
    Partners, LP     (Note 1)     As Adjusted  
    (in thousands)  
 
ASSETS
                       
Cash and cash equivalents
  $ 1,290     $ 98,142 (a)   $ 34,128  
              (4,625 )(a)        
              (93,517 )(a)        
              (1,290 )(b)        
              150,000 (b)        
              (13,500 )(b)        
              (102,372 )(b)        
                         
Trade accounts receivable
    29,838       (27,838 )(b)     2,000  
Inventory
    10,390             10,390  
Advance royalties
    1,839             1,839  
Prepaid expenses and other current assets
    4,797       1,321 (a)     6,118  
                         
Total current assets
    48,154       6,321       54,475  
                         
Property, plant and equipment, net
    147,949             147,949  
Advance royalties
    6,832             6,832  
Other long-term assets
    9,982       3,304 (a)     11,816  
              (1,470 )(c)        
                         
Total assets
  $ 212,917     $ 8,155     $ 221,072  
                         
                         
LIABILITIES                        
Current portion of long-term debt
    4,115       (846 )(a)     3,269  
Accounts payable
    33,216             33,216  
Asset retirement obligation — current portion
    6,623             6,623  
Deferred revenue — current portion
                 
Accrued taxes other than income taxes
    1,526             1,526  
Accrued payroll and related expenses
    1,617             1,617  
Other current liabilities
    4,391             4,391  
                         
Total current liabilities
    51,488       (846 )     50,642  
                         
Long-term debt
    94,317       (92,671 )(a)     99,788  
              98,142 (a)        
Asset retirement obligations
    7,013             7,013  
Other long-term liabilities
    4,236             4,236  
                         
Total liabilities
  $ 157,054     $ 4,625     $ 161,679  
                         
                         
Commitments and Contingencies
                       
                         
PARTNERS’ CAPITAL                        
Limited Partners
                       
Common unitholders (6,582,039 units outstanding as of March 31, 2010)
    51,120       (28,543 )(b)     125,387  
              (100,315 )(b)        
              (1,440 )(c)        
              136,500 (b)        
              68,065 (b)        
Subordinated unitholders (           units outstanding as of March 31, 2010)
          (68,065 )(b)     (68,065 )
General partner (134,327 units outstanding as of March 31, 2010
    1,048       (2,642 )(b)     (1,624 )
              (30 )(c)        
                         
Total Oxford Resource Partners, LP partners’ capital
    52,168       3,530       55,698  
Noncontrolling interest
    3,695             3,695  
                         
Total partners’ capital
    55,863       3,530       59,393  
                         
Total liabilities and partners’ capital
  $ 212,917     $ 8,155     $ 221,072  
                         
 
See accompanying notes to unaudited pro forma consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP

Unaudited Pro Forma Consolidated Statement of Operations
Year Ended December 31, 2009
 
                                                 
                            Adjustments for
       
                Pro Forma
          Offering
       
    Oxford Resource
    Phoenix
    Adjustments
          Transactions
    Pro Forma as
 
    Partners, LP     Coal     (Note 2)     Pro Forma     (Note 2)     Adjusted  
    (in thousands)  
 
Revenues
                                               
Coal sales
  $ 254,171     $ 58,494     $ 4,556 (d)   $ 312,490     $     $ 312,490  
                      (4,731 )(e)                        
Transportation revenue
    32,490             4,731 (e)     37,221             37,221  
Royalty and non-coal revenue
    7,183                   7,183             7,183  
                                                 
Total revenues
    293,844       58,494       4,556       356,894             356,894  
Costs and expenses
                                               
Cost of coal sales (excluding DD&A, shown separately)
    170,698       54,531       1,464 (f)     214,662             214,662  
                      (15,031 )(e)                        
                      3,000 (g)                        
Cost of purchased coal
    19,487             10,305 (e)     29,792             29,792  
Cost of transportation
    32,490             4,731 (e)     37,221             37,221  
Depreciation, depletion and amortization
    25,902       5,800       (278 )(h)     31,424             31,424  
Selling, general and administrative expenses
    13,242       6,948       5,852 (e)     26,042       (307 )(k)     25,735  
Phoenix Coal selling expense
          5,852       (5,852 )(e)                  
Sales contract termination cost
          3,000       (3,000 )(g)                  
                                                 
Total costs and expenses
    261,819       76,131       1,191       339,141       (307 )     338,834  
                                                 
Income (loss) from operations
    32,025       (17,637 )     3,365       17,753       307       18,060  
Interest income
    35       4             39             39  
Interest expense
    (6,484 )     (2,601 )     (156 )(i)     (9,241 )     1,572 (l)     (7,669 )
Other income (expense)
          (5 )     5 (e)                  
Gain from purchase of business
    3,823                   3,823             3,823  
Taxes
          (16 )     16 (j)                  
                                                 
Net income (loss)
    29,399       (20,255 )     3,230       12,374       1,879       14,253  
Less: net income attributable to noncontrolling interest
    (5,895 )                 (5,895 )           (5,895 )
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ 23,504     $ (20,255 )   $ 3,230     $ 6,479     $ 1,879     $ 8,358  
                                                 
 
See accompanying notes to unaudited pro forma consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP

Unaudited Pro Forma Consolidated Statement of Operations
for the Three Months Ended March 31, 2010
 
                                         
                      Adjustments for
       
    Oxford Resource
    Pro Forma
          Offering
    Pro Forma as
 
    Partners, LP     Adjustments     Pro Forma     Transactions     Adjusted  
    (in thousands)  
 
Revenues
                                       
Coal sales
  $ 76,756             $ 76,756             $ 76,756  
Transportation revenue
    9,530               9,530               9,530  
Royalty and non-coal revenue
    1,774               1,774               1,774  
                                         
Total revenues
    88,060               88,060               88,060  
Costs and expenses
                                       
Cost of coal sales (excluding DD&A, shown separately)
    55,186               55,186               55,186  
Cost of purchased coal
    7,859               7,859               7,859  
Cost of transportation
    9,530               9,530               9,530  
Depreciation, depletion and amortization
    8,777               8,777               8,777  
Selling, general and administrative expenses
    3,535               3,535       (78 )(m)     3,457  
                                         
Total costs and expenses
    84,887               84,887       (78 )     84,809  
                                         
Income (loss) from operations
    3,173               3,173       78       3,251  
Interest income
    1               1               1  
Interest expense
    (1,833 )             (1,833 )     (183 )(n)     (2,016 )
                                         
Net income (loss)
    1,341               1,341       (105 )     1,236  
Less: net income attributable to noncontrolling interest
    (1,628 )             (1,628 )             (1,628 )
                                         
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (287 )   $           $ (287 )   $ (105 )   $ (392 )
                                         
 
See accompanying notes to unaudited pro forma consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP
 
 
NOTE 1.   PRO FORMA CONSOLIDATED BALANCE SHEET ADJUSTMENTS
 
(a) Reflects adjustments relating to the repayment of our existing credit facility and the entry into our new credit facility based on an assumed March 31, 2010 transaction date for the Offering Transactions. These adjustments are based on the following assumptions:
 
  •     the repayment of a total of $93.5 million in debt outstanding under our existing credit facility;
 
  •     total borrowings of $98.1 million under our new credit facility; and
 
  •     total fees relating to our new credit facility of $4.6 million, which amount will be capitalized.
 
(b) Reflects adjustments for the Offering Transactions not discussed in Note (a) above, based on an assumed March 31, 2010 transaction date for the Offering Transactions. These adjustments are based on the following assumptions:
 
  •     the distribution of $1.3 million in cash and $27.8 million in accounts receivable to our General Partner, C&T Coal, AIM Oxford and the participants in our LTIP, pro rata;
 
  •     gross proceeds of $150 million from the issuance and sale of           common units at an assumed initial offering price of           per unit (the midpoint of the range set forth on the cover page of this prospectus);
 
  •     estimated underwriting fees and commissions and offering expenses of $13.5 million;
 
  •     a total cash distribution of $102.4 million to our General Partner, C&T Coal, AIM Oxford and the participants in our LTIP, pro rata; and
 
  •     replenishment of working capital with remaining cash proceeds of $34.1 million.
 
(c) Reflects adjustments to write off deferred financing costs of $1.5 million that relate to our existing credit facility.
 
NOTE 2.   PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS ADJUSTMENTS
 
(d) Reflects the benefit of amortization during the Stub Period of the below-market coal sales contracts that we acquired in the Phoenix Coal acquisition. The amount was calculated based on the amortization we recognized in the fourth quarter of 2009 and the amount of coal shipped on these contracts during the Stub Period as compared to the fourth quarter of 2009.
 
(e) Reflects reclassifications to conform the statement of operations of Phoenix Coal to our basis of presentation.
 
(f) Reflects additional lease expense we would have incurred over the Stub Period as a result of our leasing, from a third party, equipment that was previously owned by Phoenix Coal. We executed this lease concurrently with the closing of the Phoenix Coal acquisition.
 
(g) Reflects the reclassification of sales contract termination costs incurred by Phoenix Coal into cost of coal sales.
 
(h) Reflects the net effect of the elimination of DD&A expense attributable to the operations we purchased from Phoenix Coal and the addition of DD&A expense we would have incurred based on a January 1, 2009 assumed acquisition date. Our net adjustment to DD&A expense is a decrease of $0.3 million and is attributable to the following:
 
  •     a decrease in our depletion expense due to lower fair market values assigned to coal reserves as compared to Phoenix Coal’s carrying value, partially offset by


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Table of Contents

OXFORD RESOURCE PARTNERS, LP
 
Notes to Unaudited Pro Forma Consolidated Financial Statements — (Continued)
 
 
NOTE 2.   PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS ADJUSTMENTS — (Continued)
 
  •     an increase in our depreciation expense due to higher fair market values assigned to equipment purchased as compared to Phoenix Coal’s carrying value.
 
(i) As a result of the Phoenix Coal acquisition, interest expense increased $0.2 million over the Stub Period. This increase would have been attributable to increased debt levels and higher interest rates applicable to our existing credit facility that we amended in connection with the acquisition. Our amortization of deferred financing expenses also increased over the Stub Period due to amendment fees paid to lenders as a result of the amendment to our existing credit facility. These items increased our interest expense by $2.8 million, which was partially offset by the elimination of the historical interest expense of Phoenix Coal of $2.6 million.
 
(j) Reflects the elimination of Phoenix Coal’s income taxes that we would not have incurred because of our status as a partnership that does not pay federal income taxes.
 
(k) Reflects the elimination of advisory fees of $0.3 million paid to affiliates of AIM Oxford that would not have been paid if we were a publicly traded partnership.
 
(l) Reflects a decrease in interest expense of $1.6 million to reflect a lower effective interest rate associated with our new credit facility, partially offset by higher amortization of deferred financing cost associated with our new credit facility.
 
(m) Reflects the elimination of advisory fees of $0.1 million paid in during the three months ended March 31, 2010 to affiliates of AIM Oxford that would not have been paid if we were a publicly traded partnership.
 
(n) Reflects an increase in interest expense of $0.2 million to reflect higher amortization of deferred financing cost associated with our new credit partially offset by a lower effective interest rate associated with our new credit facility.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
March 31, 2010 and December 31, 2009
(in thousands, except for unit information)
 
                 
    March 31,
    December 31,
 
    2010     2009  
 
ASSETS
Cash and cash equivalents
  $ 1,290     $ 3,366  
Trade accounts receivable
    29,838       24,403  
Inventory
    10,390       8,801  
Advance royalties
    1,839       1,674  
Prepaid expenses and other current assets
    4,797       1,424  
                 
Total current assets
    48,154       39,668  
Property, plant and equipment, net
    147,949       149,461  
Advance royalties
    6,832       7,438  
Other long-term assets
    9,982       6,796  
                 
Total assets
  $ 212,917     $ 203,363  
                 
 
LIABILITIES
Current portion of long-term debt
  $ 4,115     $ 4,113  
Accounts payable
    33,216       21,655  
Asset retirement obligation — current portion
    6,623       7,377  
Deferred revenue — current portion
          2,090  
Accrued taxes other than income taxes
    1,526       1,464  
Accrued payroll and related expenses
    1,617       2,045  
Other current liabilities
    4,391       5,714  
                 
Total current liabilities
    51,488       44,458  
Long-term debt
    94,317       91,598  
Asset retirement obligations
    7,013       5,966  
Other long-term liabilities
    4,236       4,229  
                 
Total liabilities
  $ 157,054     $ 146,251  
                 
Commitments and Contingencies
               
                 
PARTNERS’ CAPITAL
               
Limited Partners unitholders (6,582,039 and 6,570,396 units outstanding as of March 31, 2010 and December 31, 2009, respectively)
    51,120       53,960  
General Partner unitholders (134,327 and 132,909 units outstanding as of March 31, 2010 and December 31, 2009, respectively)
    1,048       1,085  
                 
Total Oxford Resource Partners, LP Capital
    52,168       55,045  
Noncontrolling interest
    3,695       2,067  
                 
Total partners’ capital
    55,863       57,112  
                 
Total liabilities and Partners’ capital
  $ 212,917     $ 203,363  
                 
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2010 and 2009
(in thousands, except for unit information)
 
                 
    Three Months Ended March 31,  
    2010     2009  
 
Revenues
               
Coal sales
  $ 76,756     $ 67,377  
Transportation revenue
    9,530       8,660  
Royalty and non-coal revenue
    1,774       2,402  
                 
Total revenue
    88,060       78,439  
                 
Costs and expenses
               
Cost of coal sales (excluding of depreciation, depletion, and amortization, shown separately)
    55,186       40,825  
Cost of purchased coal
    7,859       8,505  
Cost of transportation
    9,530       8,660  
Depreciation, depletion, and amortization
    8,777       5,688  
Selling, general and administrative expenses
    3,535       3,101  
                 
Total costs and expenses
    84,887       66,779  
                 
                 
Income from operations
    3,173       11,660  
Interest income
    1       11  
Interest expense
    (1,833 )     (1,123 )
                 
Net income
    1,341       10,548  
Less net income attributable to noncontrolling interest
    (1,628 )     (1,165 )
                 
Net (loss) income attributable to Oxford Resource Partners, LP unitholders
  $ (287 )   $ 9,383  
                 
Net (loss) income allocated to general partners
  $ (6 )   $ 187  
                 
Net (loss) income allocated to limited partners
  $ (281 )   $ 9,196  
                 
Basic (loss) earnings per limited partner unit
  $ (0.04 )   $ 1.56  
                 
Dilutive (loss) earnings per limited partner unit
  $ (0.04 )   $ 1.56  
                 
Weighted average number of limited partner units outstanding basic
    6,575,259       5,889,539  
                 
Weighted average number of limited partner units outstanding diluted
    6,575,259       5,900,217  
                 
Distributions paid per limited partner unit
  $ 0.42     $ 0.42  
                 
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
For the Three Months Ended March 31, 2010 and 2009
(in thousands, except for unit information)
 
                                                 
    Limited
    Limited
    General
    General
             
    Partner
    Partners’
    Partner
    Partner’s
    Noncontrolling
    Total Partners’
 
    Units     Capital     Units     Capital     Interest     Capital  
 
Balance at December 31, 2008
    5,889,484     $ 32,371       119,643     $ 653     $ 2,297     $ 35,321  
                                                 
Net income
            9,196               187       1,165       10,548  
Partners’ contributions
                                               
Partners’ distributions
            (2,473 )             (50 )     (1,470 )     (3,993 )
Unit based compensation
            109                               109  
Issuance of units to Long Term Incentive Plan participants upon vesting
    4,978                                          
                                                 
Balance at March 31, 2009
    5,894,462     $ 39,203       119,643     $ 790     $ 1,992     $ 41,985  
                                                 
Balance at December 31, 2009
    6,570,396     $ 53,960       132,909     $ 1,085     $ 2,067     $ 57,112  
                                                 
                                                 
Net income (loss)
            (281 )             (6 )     1,628       1,341  
Partners’ contributions
                    1,418       25               25  
Partners’ distributions
            (2,762 )             (56 )             (2,818 )
Unit based compensation
            304                               304  
Issuance of units to Long Term Incentive Plan participants upon vesting
    11,643       (101 )                           $ (101 )
                                                 
Balance at March 31, 2010
    6,582,039     $ 51,120       134,327     $ 1,048     $ 3,695     $ 55,863  
                                                 
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
(in thousands, except for unit information)
 
                 
    Three Months Ended March 31,  
    2010     2009  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (287 )   $ 9,383  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    8,777       5,688  
Interest rate swap or rate cap adjustment to market
    33       (466 )
Loan fee amortization
    168       110  
Non-cash compensation expense
    304       109  
Advanced royalty recoupment
    600       263  
Loss on disposal of property and equipment
    175       216  
Noncontrolling interest in subsidiary earnings
    1,628       1,165  
(Increase) in assets:
               
Accounts receivable
    (5,435 )     (1,668 )
Inventory
    (1,589 )     (1,450 )
Other assets
    (3,068 )     (604 )
Increase (decrease) in liabilities:
               
Accounts payable and other liabilities
    9,457       191  
Asset retirement obligation
    293       531  
Provision for below-market contracts and deferred revenue
    (2,715 )     (2,966 )
                 
Net cash provided by operating activities
    8,341       10,502  
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Purchase of mineral rights and land
    (2,116 )     (20 )
Mine development costs
    (775 )     (179 )
Royalty advances
    (144 )     (149 )
Purchase of property and equipment
    (4,995 )     (6,715 )
Proceeds from sale of property and equipment
    1,248       21  
Change in restricted cash
    (3,498 )     (440 )
                 
Net cash used in investing activities
    (10,280 )     (7,482 )
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Proceeds from borrowings
          6,650  
Payments on borrowings
    (344 )     (215 )
Capital contributions from partners
    25        
Advances on line of credit
    3,000        
Distributions to noncontrolling interest
          (1,470 )
Distributions to partners
    (2,818 )     (2,523 )
                 
Net cash (used in) provided by financing activities
    (137 )     2,442  
Net increase/(decrease) in cash
    (2,076 )     5,462  
CASH AND CASH EQUIVALENTS, beginning of period
    3,366       15,179  
                 
CASH AND CASH EQUIVALENTS, end of period
  $ 1,290     $ 20,641  
                 
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
 
The accompanying interim unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring accruals) that, in the opinion of management, are necessary for a fair presentation of the financial results. All such adjustments reflected in the unaudited interim condensed consolidated financial statements are considered to be of a normal and recurring nature. The results of the operations for the three-month period ended March 31, 2010 and 2009 are not necessarily indicative of the results to be expected for the whole year. Accordingly, these unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2009 contained herein.
 
NOTE 1:   ORGANIZATION AND PRESENTATION
 
Significant Relationships Referenced in Notes to Consolidated Financial Statements
 
  •     “We,” “us,” “our,” or the “Partnership” means the business and operations of Oxford Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries.
 
  •     “ORLP” means Oxford Resource Partners, LP, individually as the parent entity, and not on a consolidated basis.
 
  •     Our “GP” means Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP.
 
Organization
 
We are a low cost producer of high value steam coal. 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. These coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company-Kentucky, LLC and Harrison Resources, LLC (“Harrison Resources”).
 
We are managed by our GP and all executives, officers and employees who provide services to us are employees of our GP. Charles Ungurean, the President and Chief Executive Officer of our GP and a member of our GP’s board of directors, and Thomas Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our GP, are the co-owners of C&T Coal, Inc. (“C&T Coal”). Prior to our acquisition of Oxford, C&T Coal owned 100% of the outstanding ownership interest in Oxford Mining Company (“Predecessor” or “Oxford”).
 
We were formed in August 2007 to acquire all of the ownership interests in Oxford. On August 24, 2007, a contribution agreement was executed which resulted in C&T Coal and AIM Oxford Holdings, LLC (“AIM Oxford”) holding a 34.3% and 63.7% limited partner interest in ORLP, respectively, and our GP owning a 2% general partner interest. Also at that time, the members of our GP were AIM Oxford with a 65% ownership interest and C&T Coal with a 35% ownership interest. After taking into account their indirect ownership of ORLP through our GP, AIM Oxford held a 65% total interest in ORLP and C&T Coal held a 35% total interest in ORLP.
 
Subsequent to our formation, AIM Oxford and C&T Coal made several capital contributions for various purposes including purchasing property, plant and equipment and acquiring the surface mining operations of Phoenix Coal Corporation (“Phoenix Coal”). The capital contributions were not all in direct proportion to AIM Oxford’s and C&T Coal’s initial limited partner interests in us. As a result of the disproportionate capital contributions, AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of March 31, 2010, is 64.26% and 32.70%, respectively, with 2.00% and 1.04% interests being owned by our GP and participants in the Partnership’s Long-Term Incentive Plan (“LTIP”), respectively. AIM Oxford and C&T Coal own 66.27% and 33.73%, respectively, in the GP.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 1:   ORGANIZATION AND PRESENTATION — (Continued)
 
Basis of Presentation and Significant Accounting Policies
 
The accompanying unaudited condensed consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) for interim financial information and Rule 10-01 of Regulation S-X under the Securities Exchange Act of 1934. We own a 51% interest in Harrison Resources and are therefore deemed to have control. As a result, we consolidate all of Harrison Resources’ accounts with all material intercompany transactions and balances being eliminated in our consolidated financial statements. The 49% portion of Harrison Resources that we do not own is reflected as “Noncontrolling interest” in the consolidated balance sheet.
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Significant Accounting Policies
 
Our significant accounting policies are discussed in the Note 2 of the notes to our audited 2009 consolidated financial statements located on page F-32.
 
New Accounting Standards Issued and Adopted
 
In August 2009, the FASB issued ASU 2009-05, Measuring Liabilities at Fair Value. The amendment provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the alternative valuation methods outlined in the guidance. It also clarifies that restrictions preventing the transfer of a liability should not be considered as a separate input or adjustment in the measurement of its fair value. This amendment was effective as of the beginning of interim and annual reporting periods that begin after August 27, 2009. The adoption of this guidance did not impact our consolidated financial statements.
 
In June 2009, the FASB amended guidance for the consolidation of a variable interest entity (“VIE”). This guidance updated the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. This standard also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, reconsideration was required only when specific events had occurred. This guidance also requires enhanced disclosure about an enterprise’s involvement with a VIE. The provisions of these updates are effective as of the beginning of interim and annual reporting periods that begin after November 15, 2009. The adoption of this standard did not impact our consolidated financial statements.
 
In January 2010, the FASB issued guidance on improving disclosures about fair value measurements. This guidance requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. We adopted this guidance effective January 1, 2010 except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of this guidance did not have a material effect on our consolidated financial position, results of operations or cash flows and the adoption of the level 3 reconciliation disclosures is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 3:   ACQUISITION
 
On September 30, 2009, we acquired 100% of the active western Kentucky surface mining coal operations of Phoenix Coal. This acquisition provided us an entry into the Illinois Basin and consisted of four active surface coal mines and coal reserves of 20 million tons, as well as mineral rights, working capital and various coal sales and purchase contracts. The application of purchase accounting requires that the total purchase price be allocated to the fair value of assets acquired and liabilities assumed based on the fair values of the assets and the liabilities at the acquisition date. As part of the acquisition agreement, we agreed to make additional payments of up to $1,000,000 in two installments to Phoenix Coal if Phoenix Coal secured specific surface and mineral rights by certain dates, the last of which will expire on June 30, 2010. During the fourth quarter of 2009, we paid $500,000 to Phoenix Coal for obtaining the surface rights pertaining to certain coal leases. The remaining $500,000 contingent payment was paid to Phoenix Coal in January 2010 for achieving specified objectives as to arrangements for additional coal leases in western Kentucky.
 
In connection with the closing of our Phoenix Coal acquisition, we entered into an escrow agreement with Phoenix Coal. The purpose of the escrow agreement is to provide a source of funding for any indemnification claims we make against Phoenix Coal for breaches of covenants and warranties as the seller under the terms of the acquisition agreement. To date, there have been no indemnification claims against the escrow. The escrow was funded with $3,300,000. The escrow agreement provides for the release to Phoenix Coal of portions of the escrow fund including earnings thereon at periodic intervals, with one-third of the escrow fund amount being released to Phoenix Coal on March 31, 2010, September 30, 2010, and March 31, 2011. All amounts are offset for any indemnification claims. Pursuant to such release provisions, the escrow agent released one-third of the then escrow fund amount, or $1,100,000, to Phoenix Coal at the end of March 2010.
 
We also assumed a contract with a third party to pay a contingent fee if the third party was able to arrange to lease or purchase, on our behalf, a specified amount of coal reserves by July 31, 2010. The contract called for a payment of $1,000,000; however, we concluded that the fair value of the contingent liability was $625,000 using a probability weighted average of the likely outcomes. That amount was recorded as a liability with a corresponding asset in the consolidated balance sheet under the caption of “Property, plant and equipment, net.”
 
The following unaudited pro forma financial information reflects the consolidated results of operations as if the Phoenix Coal acquisition had occurred at the beginning of 2009. The pro forma information includes adjustments primarily for depreciation, depletion and amortization based upon fair values of property, plant and equipment and mineral rights, the lease of $11.1 million of equipment, and interest expense for acquisition debt and additional capital contributions. The pro forma financial information is not necessarily indicative of results that actually would have occurred if we had assumed operation of these assets on the date indicated nor are they indicative of future results.
 
         
    For the Quarter Ended
    March 31, 2009
    (Unaudited)
 
Revenue
  $ 97,910,000  
Net income attributable to Oxford Resource Partners, LP unitholders
    1,991,000  


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 4:   INVENTORY
 
Inventory consisted of the following:
 
                 
    March 31, 2010     December 31, 2009  
 
Coal
  $ 5,874,000     $ 4,759,000  
Fuel
    1,513,000       1,264,000  
Supplies and spare parts
    3,003,000       2,778,000  
                 
Total
  $ 10,390,000     $ 8,801,000  
                 
 
NOTE 5:   PROPERTY, PLANT AND EQUIPMENT, NET
 
Property, plant and equipment, net of accumulated depreciation, depletion and amortization consisted of the following:
 
                 
    March 31, 2010     December 31, 2009  
 
Property, plant and equipment, gross
               
Land
  $ 3,374,000     $ 3,374,000  
Coal reserves
    41,959,000       39,905,000  
Mine development costs
    9,381,000       8,606,000  
                 
Total Property
    54,714,000       51,885,000  
                 
Buildings and tipple
    2,042,000       2,025,000  
Machinery and equipment
    136,745,000       133,667,000  
Vehicles
    4,018,000       3,913,000  
Furniture and fixtures
    869,000       690,000  
Railroad sidings
    160,000       160,000  
Total property, plant and equipment, gross
    198,548,000       192,340,000  
Less: accumulated depreciation, depletion and amortization
    50,599,000       42,879,000  
                 
Total property, plant and equipment, net
  $ 147,949,000     $ 149,461,000  
                 
 
The amounts of depreciation expense related to owned and leased fixed assets, depletion expense related to owned and leased coal reserves, and amortization expense related to mine development costs for the respective periods are set forth below:
 
                 
    Quarter Ended
  Quarter Ended
    March 31, 2010   March 31, 2009
 
Expense type:
               
Depreciation
  $ 6,950,000     $ 3,597,000  
Depletion
    1,329,000       1,571,000  
Amortization
    413,000       420,000  
 
NOTE 6:   OPERATING LEASES
 
We lease certain equipment under non-cancelable lease agreements that expire on various dates through 2015. Generally the lease agreements are for a period of four years. As of March 31, 2010, aggregate lease


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 6:   OPERATING LEASES — (Continued)
 
payments that are required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are set forth below:
 
         
For the years ending December 31, 2010
  $ 6,270,000  
2011
    7,866,000  
2012
    6,283,000  
2013
    3,405,000  
2014
    1,206,000  
Thereafter
    121,000  
 
For the quarters ended March 31, 2010 and 2009, we incurred lease expenses of approximately $2,236,000 and $1,118,000 respectively.
 
We also entered into various coal reserve lease agreements under which future royalty payments are due based on production. Such payments are capitalized as advance royalties at the time of payment, and amortized into royalty expense based on the stated recoupment rate.
 
NOTE 7:   ASSET RETIREMENT OBLIGATION
 
At March 31, 2010, we had recorded asset retirement obligation liabilities of $13.6 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with absolute certainty as of March 31, 2010, we estimate that the aggregate undiscounted cost of final mine closure is approximately $15.2 million.
 
The following table presents the activity affecting the asset retirement obligation for the respective periods:
 
                 
    March 31, 2010     December 31, 2009  
 
Beginning balance
  $ 13,343,000     $ 9,292,000  
Accretion expense
    233,000       650,000  
Payments
    (354,000 )     (3,358,000 )
Revisions in estimated cash flows
    414,000       3,802,000  
Additions due to acquisition
          2,957,000  
                 
Total asset retirement obligation
  $ 13,636,000     $ 13,343,000  
Current portion
    6,623,000       7,377,000  
                 
Noncurrent liability
  $ 7,013,000     $ 5,966,000  
                 
 
NOTE 8:   FAIR VALUE OF FINANCIAL INSTRUMENTS
 
Fair value measures are classified into a three-tiered fair value hierarchy, which prioritizes the inputs used in measuring fair values as follows:
 
  •     Level 1 — Observable inputs such as quoted prices in active markets.
 
  •     Level 2 — Inputs, other than quoted prices in active markets, that are observable either directly or indirectly.
 
  •     Level 3 — Unobservable inputs in which there is little or no market data, which require a reporting entity to develop its own assumptions.


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Table of Contents

 
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 8:   FAIR VALUE OF FINANCIAL INSTRUMENTS — (Continued)
 
Assets and liabilities measured at fair value are based on one or more of the following valuation techniques:
 
  •     Market approach (Level 1) — Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
 
  •     Cost approach (Level 2) — Amount that would be required to replace the service capacity of an asset (replacement cost).
 
  •     Income approach (Level 3) — Techniques to convert future amounts to a single present amount based on market expectations (including present-value techniques, option-pricing and excess earning models).
 
The financial instruments measured at fair value on a recurring basis are summarized below:
 
                         
    Fair Value Measurements at March 31, 2010
    Quoted Prices in
      Significant
    Active Markets for
  Significant Other
  Unobservable
    Identical Liabilities
  Observable Inputs
  Inputs
Description
  (Level 1)   (Level 2)   (Level 3)
 
Interest rate cap agreement
  $     $ 1,000     $  
 
                         
    Fair Value Measurements at December 31, 2009
    Quoted Prices in
      Significant
    Active Markets for
  Significant Other
  Unobservable
    Identical Liabilities
  Observable Inputs
  Inputs
Description
  (Level 1)   (Level 2)   (Level 3)
 
Interest rate cap agreement
  $     $ 34,000     $  
 
We estimated the fair value of the interest rate cap agreement using calculations based on market rates.
 
The following methods and assumptions were used to estimate the fair values of financial instruments for which the fair value option was not elected:
 
Cash and cash equivalents, trade accounts receivable and accounts payable:  The carrying amount reported in the balance sheets for cash and cash equivalents, trade accounts receivable and accounts payable approximates its fair value due to the short maturity of these instruments.
 
Fixed rate debt:  The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.
 
Variable rate debt:  The fair value of variable rate debt is estimated using discounted cash flow analyses, based on our best estimates of market rate for instruments with similar cash flows.
 
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
 
                                 
    March 31, 2010   December 31, 2009
    Carrying
      Carrying
   
    Amount   Fair Value   Amount   Fair Value
 
Fixed rate debt
  $ 4,914,000     $ 4,980,000     $ 4,982,000     $ 4,952,000  
Variable rate debt
  $ 93,518,000     $ 93,518,000     $ 90,729,000     $ 90,729,000  


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 9:   LONG-TERM INCENTIVE PLAN
 
Under our LTIP, we recognize compensation expense over the vesting period of the units, which is generally four years for each award. For the quarters ended March 31, 2010 and 2009, our gross LTIP expense was approximately $304,000 and $109,000, respectively, which is included in selling, general and administrative expenses in our consolidated statements of operations. As of March 31, 2010 and December 31, 2009, approximately $1,185,000 and $840,000, respectively, of cost remained unamortized which we expect to recognize over a remaining weighted average period of 1 years.
 
The following table summarizes additional information concerning our unvested LTIP units:
 
                 
        Weighted
        Average
        Grant
        Date Fair
    Units   Value
 
Unvested balance at December 31, 2009
    79,050     $ 11.79  
Granted
    37,221       17.43  
Issued
    (11,643 )     14.77  
Surrendered
    (5,087 )     14.21  
                 
Unvested balance at March 31, 2010
    99,541       13.43  
                 
 
The value of LTIP units vested during the quarters ended March 31, 2010 and 2009 was $244,000 and $83,000, respectively.
 
NOTE 10:   EARNINGS PER UNIT
 
For purposes of our earnings per unit calculation, we have applied the two-class method. The classes of units are our limited partner and general partner units. All outstanding units share pro rata in income allocations and distributions and our general partner has sole voting rights. Limited partner units have been separated into Class A and Class B to prepare for a potential transaction such as an initial public offering.
 
Limited Partner Units:  Basic earnings per unit are computed by dividing net income attributable to limited partners by the weighted average units outstanding during the reporting period. Diluted earnings per unit are computed similar to basic earnings per unit except that the weighted average units outstanding and net income attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to LTIP units upon vesting. In years of a loss, the phantom units are not included in the earnings per unit calculation.
 
General Partner Units:  Basic earnings per unit are computed by dividing net income attributable to our GP by the weighted average units outstanding during the reporting period. Diluted earnings per unit for our GP are computed similar to basic earnings per unit except that the net income attributable to the general partner units is adjusted for the dilutive impact of the phantom units.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 10:   EARNINGS PER UNIT — (Continued)
 
The computation of basic and diluted earnings per unit under the two-class method for limited partner units and general partner units is presented below:
 
                 
    Quarter Ended March 31,  
    2010     2009  
    (in thousands
 
    except unit amounts)  
 
Limited partner units
               
Average units outstanding:
               
Basic
    6,575,259       5,889,539  
Effect of unit-based awards
    n/a       10,678  
                 
Diluted
    6,575,259       5,900,217  
                 
Net income attributable to limited partners
               
Basic
  $ (281 )   $ 9,196  
Diluted
    (281 )     9,197  
Earnings per limited partner unit
               
Basic
  $ (0.04 )   $ 1.56  
Diluted
    (0.04 )     1.56  
General partner units
               
Average units outstanding:
               
Basic and diluted
    133,053       119,643  
Net income attributable to general partner
               
Basic
  $ (6 )   $ 187  
Diluted
    (6 )     186  
Earnings per general partner unit
               
Basic
  $ (0.04 )   $ 1.56  
Diluted
    (0.04 )     1.56  
 
NOTE 11:   COMMITMENTS AND CONTINGENCIES
 
Coal Sales Contracts
 
We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Most of these prices are subject to pass through or inflation adjusters that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. The remaining life of our long-term contracts ranges from one to nine years.
 
Purchase Commitments
 
We use independent contractors to mine some of our coal at a few of our mines. We also purchase coal from third parties in order to meet quality or delivery requirements under our customer agreements. We assumed one long-term purchase agreement as a result of the Phoenix Coal acquisition. Under this agreement, we are committed to purchase a certain volume of coal until the coal reserves covered by the contract are depleted. Based on the proven and probable coal reserves in place at March 31, 2010, we expect this contract to continue beyond five years. Additionally, we buy coal on the spot market, and the cost of that coal is


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 11:   COMMITMENTS AND CONTINGENCIES — (Continued)
 
dependent upon the market price and quality of the coal. Supply disruptions could impair our ability to fill customer orders or require us to purchase coal from other sources at a higher cost to us in order to satisfy these orders.
 
Transportation
 
We depend upon barge, rail, and truck transportation systems to deliver our coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments. We entered into a long-term transportation contract on April 1, 2006 for rail services, and that agreement has been amended and extended through March 31, 2011.
 
Defined Contribution Pension Plan and 401(k) Plan
 
At March 31, 2010, we had an obligation to pay our GP for the purpose of funding our GP’s commitments to the money purchase pension plan and 401(k) plan in the amount of $2,031,000. Of this amount, $1,522,000 relates to plan year 2009 and is expected to be paid by September 2010 with the remainder relating to plan year 2010 that will be paid by September 2011.
 
Security for Reclamation and Other Obligations
 
As of March 31, 2010, we had $32,359,000 in surety bonds and $14,000 in cash bonds outstanding to secure certain reclamation obligations. Additionally, as of March 31, 2010, we had letters of credit outstanding in support of these surety bonds of $7,525,000 and also a letter of credit of $1,320,000 guaranteeing an operating lease. Further, as of March 31, 2010, we had certain road bonds of $645,000 outstanding and performance bonds outstanding of $12,330,000. Our management believes these bonds and letters of credit will expire without any claims or payments thereon and thus any subrogation or other rights with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.
 
Legal
 
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes these claims will not have a material adverse effect on our financial position, liquidity or operations.
 
Guarantees
 
Our GP and the Partnership guarantee certain obligations of our subsidiaries. Our management believes that these guarantees will expire without any liability to the guarantors, and therefore any indemnification or subrogation commitments with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.
 
NOTE 12:   CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
 
We have a credit policy that establishes procedures to determine creditworthiness and credit limits for trade customers. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established.
 
We market our coal principally to electric utilities, municipalities and electric cooperatives and industrial customers in Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. As of March 31, 2010 and December 31, 2009, accounts receivable from electric utilities totaled $23.4 million and $18.2 million or 78%


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 12:   CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS — (Continued)
 
and 75% of total trade receivables, respectively. Four customers individually accounted for greater than 10% of coal sales (including sales through brokers) for the quarter ended March 31, 2010 which, in the aggregate, represented approximately 63% of coal sales for the quarter. Three customers individually accounted for greater than 10% of coal sales which, in the aggregate, represented approximately 69% of coal sales (including sales through brokers) for the quarter ended March 31, 2009. Accounts receivable attributable to four customers totaled approximately 71% and 59% of consolidated accounts receivable at March 31, 2010 and December 31, 2009, respectively.
 
NOTE 13:   RELATED PARTY TRANSACTIONS
 
In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (“Services Agreement”) with our GP. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Pursuant to the Services Agreement, we reimbursed our GP for costs primarily related to payroll for all the periods after August 24, 2007, of which $4,260,000 and $2,504,000 were included in our accounts payable at March 31, 2010 and December 31, 2009, respectively. These amounts include amounts payable for funding the money purchase pension plan and 401(k) plan for plan years 2009 and 2010, respectively.
 
Also in connection with our formation in August 2007, Oxford Mining entered into an advisory services agreement (“Advisory Agreement”) with certain affiliates of AIM Oxford. The Advisory Agreement runs for a term of ten years until August 2017, subject to earlier termination at any time by the AIM Oxford affiliates. Under the terms of the Advisory Agreement, the AIM Oxford affiliates have duties as financial and management advisors to Oxford Mining, including providing services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services for the operation and growth of Oxford Mining. These services consist of advisory services of a type customarily provided by sponsors of U.S. private equity firms to companies in which they have substantial investments. Such services are rendered at the reasonable request of Oxford Mining. The basic annual fees under the Advisory Agreement were $250,000 for 2008, and for 2009 and each year thereafter increase based on the percentage increase in gross revenues. Further fees are payable for additional significant services requested. Pursuant to the Advisory Agreement, advisory fees were paid to AIM Oxford affiliates of $77,000 and $63,000 for the quarters ended March 31, 2010 and 2009, respectively.
 
Contract services were provided to Tunnell Hill Reclamation, LLC, a company with common owners, in the amount of $206,000 and $72,000 for the quarters ended March 31, 2010 and March 31, 2009, respectively. Accounts receivable were $87,000 and $70,000 from Tunnell Hill at March 31, 2010 and December 31, 2009, respectively. We have concluded that Tunnell Hill Reclamation, LLC does not represent a variable interest entity.
 
We had no accounts receivable from employees and owners at March 31, 2010 and $28,000 at December 31, 2009.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)
 
NOTE 14:   SUPPLEMENTAL CASH FLOW INFORMATION
 
                 
    For the Quarters Ended
    March 31,
    2010   2009
 
Cash paid for:
               
Interest
  $ 1,711,000     $ 1,443,000  
Noncash investing activities:
               
Purchases of mineral rights and land financed through accounts payable
          1,296,000  
Mine development costs financed through accounts payable
          225,000  
Purchases of property and equipment financed through accounts payable
    3,074,000       3,637,000  
Purchase of coal reserves by note payable
          1,387,000  
Noncash financing activities:
               
Market value of common units vested in LTIP
    288,000       83,000  
 
NOTE 15:   SEGMENT INFORMATION
 
We operate in one business segment. We operate surface coal mines in Northern Appalachia and the Illinois Basin and sell high value steam coal to utilities, industrial customers or other coal-related organizations primarily in the eastern United States. Our operating and executive management reviews and bases its decisions upon consolidated reports. All three of our operating subsidiaries participate primarily in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to our customers. The operating companies share customers and a particular customer may receive coal from any one of the operating subsidiaries.
 
NOTE 16:   SUBSEQUENT EVENTS
 
The following represents material events that have occurred subsequent to March 31, 2010 through May 17, 2010, the date these financial statements were issued.
 
Our subsidiary Harrison, paid a $3,000,000 distribution in April 2010 of which we and the non-controlling interest holder received $1,530,000 and $1,470,000, respectively.
 
We also made a quarterly distribution to our unitholders of $2,834,000 in May 2010.
 
In May 2010 we borrowed $3,000,000 on the revolving credit facility.


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Report of Independent Registered Public Accounting Firm
 
To the Board of Directors of Oxford Resources GP, LLC (which is the General Partner of Oxford
Resource Partners, LP) and the General Partner and Limited Partners of Oxford Resource Partners, LP:
 
We have audited the accompanying consolidated balance sheets of Oxford Resource Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, partners’ capital and shareholders’ equity and cash flows of Oxford Resource Partners, LP and subsidiaries for the years ended December 31, 2009 and 2008 and the period from August 24, 2007 (inception) to December 31, 2007 and of Oxford Mining Company and subsidiaries (the “Predecessor”) for the period from January 1, 2007 through August 23, 2007. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, and assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oxford Resource Partners, LP and subsidiaries as of December 31, 2009 and 2008, and the results of operations and cash flows of Oxford Resource Partners, LP and subsidiaries for the years ended December 31, 2009 and 2008, the period from August 24, 2007 (inception) to December 31, 2007 and of the Predecessor for the period from January 1, 2007 through August 23, 2007 in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Note 2, the Partnership changed its method of accounting and reporting for noncontrolling interests in subsidiaries in 2009 for all periods presented due to the adoption of Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, codified in FASB ASC 810 — Consolidation.
 
/s/ GRANT THORNTON LLP
 
Cleveland, Ohio
March 24, 2010


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
(in thousands, except for unit information)
 
                 
    December 31,
    December 31,
 
    2009     2008  
 
ASSETS
Cash and cash equivalents
  $ 3,366     $ 15,179  
Trade accounts receivable
    24,403       21,528  
Inventory
    8,801       5,134  
Advance royalties
    1,674       1,509  
Prepaid expenses and other current assets
    1,424       787  
                 
Total current assets
    39,668       44,137  
Property, plant and equipment, net
    149,461       112,446  
Advance royalties
    7,438       8,126  
Other long-term assets
    6,796       6,588  
                 
Total assets
  $ 203,363     $ 171,297  
                 
 
LIABILITIES
Current portion of long-term debt
  $ 4,113     $ 2,535  
Accounts payable
    21,655       22,654  
Asset retirement obligation — current portion
    7,377       4,749  
Deferred revenue — current portion
    2,090       13,250  
Accrued taxes other than income taxes
    1,464       1,117  
Accrued payroll and related expenses
    2,045       326  
Other current liabilities
    5,714       3,360  
                 
Total current liabilities
    44,458       47,991  
Long-term debt
    91,598       81,442  
Asset retirement obligations
    5,966       4,543  
Other long-term liabilities
    4,229       2,000  
                 
Total liabilities
  $ 146,251     $ 135,976  
Commitments and Contingencies (Note 17)
               
                 
PARTNERS’ CAPITAL                
Limited partners (6,570,369 and 5,889,484 units outstanding as of December 31, 2009 and 2008, respectively)
    53,960       32,371  
General partner (132,909 and 119,643 units outstanding as of December 31, 2009 and 2008, respectively)
    1,085       653  
                 
Total Oxford Resource Partners, LP partners’ capital
    55,045       33,024  
Noncontrolling interest
    2,067       2,297  
                 
Total partners’ capital
    57,112       35,321  
                 
Total liabilities and partners’ capital
  $ 203,363     $ 171,297  
                 
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
(in thousands, except for unit information)
 
                                 
          Oxford Mining
 
    Oxford Resource Partners, LP
    Company
 
    (Successor)     (Predecessor)  
          Period from
    Period from
 
    Years Ended
    August 24
    January 1
 
    December 31,     to December 31,     to August 23,  
    2009     2008     2007     2007  
 
Revenues
                               
Coal sales
  $ 254,171     $ 193,699     $ 61,324     $ 96,799  
Transportation revenue
    32,490       31,839       10,204       18,083  
Royalty and non-coal revenue
    7,183       4,951       1,407       3,267  
                                 
Total revenues
    293,844       230,489       72,935       118,149  
Costs and expenses
                               
Cost of coal sales (excluding depreciation, depletion, and amortization, shown separately)
    170,698       151,421       40,721       70,415  
Cost of purchased coal
    19,487       12,925       9,468       17,494  
Cost of transportation
    32,490       31,839       10,204       18,083  
Depreciation, depletion, and amortization
    25,902       16,660       4,926       9,025  
Selling, general and administrative expenses
    13,242       9,577       2,114       3,643  
                                 
Total costs and expenses
    261,819       222,422       67,433       118,660  
                                 
Income (loss) from operations
    32,025       8,067       5,502       (511 )
Interest income
    35       62       55       26  
Interest expense
    (6,484 )     (7,720 )     (3,498 )     (2,386 )
Gain from purchase of business
    3,823                    
                                 
Net income (loss)
    29,399       409       2,059       (2,871 )
Less: net income attributable to noncontrolling interest
    (5,895 )     (2,891 )     (537 )     (682 )
                                 
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ 23,504     $ (2,482 )   $ 1,522     $ (3,553 )
                                 
Net income (loss) allocated to general partner
  $ 467     $ (50 )   $ 30          
                                 
Net income (loss) allocated to limited partners
  $ 23,037     $ (2,432 )   $ 1,492          
                                 
Basic earnings per limited partner unit
  $ 3.80     $ (0.44 )   $ 0.30          
                                 
Diluted earnings per limited partner unit
  $ 3.79     $ (0.44 )   $ 0.30          
                                 
Weighted average number of limited partner units outstanding basic
    6,061,072       5,554,395       4,900,000          
                                 
Weighted average number of limited partner units outstanding diluted
    6,084,508       5,554,395       4,901,956          
                                 
Distributions paid per limited partner unit
  $ 2.17     $ 2.21     $          
                                 
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL AND SHAREHOLDERS’ EQUITY
Years ended December 31, 2009 and 2008 and the periods from inception to December 31, 2007 and
from January 1, 2007 to August 23, 2007
(in thousands, except for unit information)
 
                                                         
          Capital in
    Retained
    Common
    Total
             
    Common
    Excess of
    Earnings
    Stock In
    Shareholders’
    Noncontrolling
    Total
 
Predecessor
  Stock     Par Value     (Deficit)     Treasury     Equity     Interest     Equity  
 
Balance at December 31, 2006
  $ 2     $ 44     $ 10,252     $ (2,077 )   $ 8,221     $     $ 8,221  
Proceeds from the sale of minority interest
                                            980       980  
Net loss
                    (3,553 )             (3,553 )     682       (2,871 )
Shareholders’ distributions
                    (16,339 )             (16,339 )     (343 )     (16,682 )
                                                         
Balance at August 23, 2007
  $ 2     $ 44     $ (9,640 )   $ (2,077 )   $ (11,671 )   $ 1,319     $ (10,352 )
                                                         
 
                                                         
    Limited
    Limited
    General
    General
                Total
 
    Partner
    Partners’
    Partner
    Partner’s
    Total
    Noncontrolling
    Partners’
 
Successor
  Units     Capital     Units     Capital     Units     interest     Capital  
 
Balance at August 24, 2007
        $           $           $     $  
Partners’ contributions
    4,900,000       54,880       100,000       1,120       5,000,000       1,319       57,319  
Predecessor basis adjustment
            (20,465 )             (417 )                     (20,882 )
Net income
            1,492               30               537       2,059  
Unit-based compensation
            25                                       25  
                                                         
Balance at December 31, 2007
    4,900,000     $ 35,932       100,000     $ 733       5,000,000     $ 1,856     $ 38,521  
                                                         
Net income (loss)
            (2,432 )             (50 )             2,891       409  
Partners’ contributions
    962,500       10,780       19,643       220       982,143               11,000  
Partners’ distributions
            (12,253 )             (250 )             (2,450 )     (14,953 )
Unit-based compensation
            468                                       468  
Issuance of units to LTIP participants
    26,984       (124 )                     26,984               (124 )
                                                         
Balance at December 31, 2008
    5,889,484     $ 32,371       119,643     $ 653       6,009,127     $ 2,297     $ 35,321  
                                                         
Net income
            23,037               467               5,895       29,399  
Partners’ contributions
    650,029       11,329       13,266       231       663,295               11,560  
Partners’ distributions
            (13,141 )             (266 )             (6,125 )     (19,532 )
Unit-based compensation
            472                                       472  
Issuance of units to LTIP participants
    30,883       (108 )                     30,883               (108 )
                                                         
Balance at December 31, 2009
    6,570,396     $ 53,960       132,909     $ 1,085       6,703,305     $ 2,067     $ 57,112  
                                                         
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
(in thousands)
 
                                 
          Oxford Mining
 
    Oxford Resource Partners, LP
    Company
 
    (Successor)     (Predecessor)  
          Period from
    Period from
 
    Years Ended
    August 24 to
    January 1
 
    December 31     December 31     to August 23  
    2009     2008     2007     2007  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                               
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ 23,504     $ (2,482 )   $ 1,522     $ (3,553 )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
                               
Depreciation, depletion, and amortization
    25,902       16,660       4,926       9,025  
Interest rate swap adjustment to market
    (1,681 )     574       1,107        
Loan fee amortization
    530       398       131       148  
Loss on debt extinguishment
    1,252                    
Non-cash compensation expense
    472       468       25        
Advanced royalty recoupment
    1,390       1,020       261       695  
Loss (gain) on disposal of property and equipment
    1,177       (1,407 )     (9 )     (25 )
(Gain) on acquisition
    (3,823 )                  
Noncontrolling interest in subsidiary earnings
    5,895       2,891       537       682  
(Increase) decrease in assets:
                               
Accounts receivable
    (2,875 )     (3,906 )     834       (1,785 )
Inventory
    (2,062 )     (479 )     358       (847 )
Other assets
    (2,807 )     (494 )     (4,368 )     (167 )
Increase (decrease) in liabilities:
                               
Accounts payable and other liabilities
    3,055       6,761       (11,388 )     10,386  
Asset retirement obligation
    1,094       1,509       (454 )     3,178  
Provision for below-market contracts and deferred revenue
    (13,840 )     12,479       (2,001 )     (103 )
                                 
Net cash provided by (used in) operating activities
    37,183       33,992       (8,519 )     17,634  
CASH FLOWS FROM INVESTING ACTIVITIES:
                               
Phoenix Coal acquisition
    (18,275 )                  
Purchase of mineral rights and land
    (2,705 )     (197 )     (20,010 )     (1,919 )
Mine development costs
    (2,346 )     (1,476 )     (312 )     (2,285 )
Royalty advances
    (629 )     (853 )     (88 )     (1,201 )
Purchase of property and equipment
    (25,657 )     (25,321 )     (77,114 )     (11,305 )
Proceeds from sale of property and equipment
    88       3,972              
Change in restricted cash
    (4 )     (67 )     (1,221 )      
Payments received — notes receivable
                      91  
                                 
Net cash used in investing activities
    (49,528 )     (23,942 )     (98,745 )     (16,619 )
CASH FLOWS FROM FINANCING ACTIVITIES:
                               
Proceeds from borrowings
    6,650       14,800       69,999       6,445  
Payments on borrowings
    (2,646 )     (5,853 )     (175 )     (6,964 )
Capital contributions from partners
    11,560       11,000       36,400        
Proceeds from sale of minority interest
                      980  
Advances on line of credit
    7,500       16,850       3,490        
Payments on line of credit
    (3,000 )     (17,350 )     (2,990 )     (13 )
Distributions to noncontrolling interest
    (6,125 )     (2,450 )           (343 )
Distributions to partners
    (13,407 )     (12,503 )            
Payments to shareholders of predecessor
                      (339 )
                                 
Net cash provided by (used in) financing activities
    532       4,494       106,724       (234 )
Net increase/(decrease) in cash
    (11,813 )     14,544       (540 )     781  
CASH AND CASH EQUIVALENTS, beginning of period
    15,179       635       1,175       394  
                                 
CASH AND CASH EQUIVALENTS, end of period
  $ 3,366     $ 15,179     $ 635     $ 1,175  
                                 
 
See accompanying notes to consolidated financial statements.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
NOTE 1:   ORGANIZATION AND PRESENTATION
 
Significant Relationships Referenced in Notes to Consolidated Financial Statements
 
  •     “We,” “us,” “our,” “Successor” or the “Partnership” means the business and operations of Oxford Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries.
 
  •     “ORLP” means Oxford Resource Partners, LP, individually as the parent entity, and not on a consolidated basis.
 
  •     Our “GP” means Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP.
 
Organization
 
We are a low cost producer of high value steam coal. 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. These coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company-Kentucky, LLC and Harrison Resources, LLC (“Harrison Resources”).
 
We are managed by our GP and all executives, officers and employees who provide services to us are employees of our GP. Charles Ungurean, the President and Chief Executive Officer of our GP and a member of our GP’s board of directors, and Thomas Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our GP, are the co-owners of C&T Coal, Inc. (“C&T Coal”). Prior to our acquisition of Oxford, C&T Coal owned 100% of the outstanding ownership interest in Oxford Mining Company (“Predecessor” or “Oxford”).
 
We were formed in August 2007 to acquire all of the ownership interests in Oxford. On August 24, 2007, AIM Oxford Holdings, LLC (“AIM Oxford”) contributed total consideration to us of $36.4 million in cash, and C&T Coal contributed 100% of its ownership interest in Oxford to us for a distribution of $20.4 million in cash and $16.0 million of working capital which was distributed prior to this transaction and therefore is not reflected in the table below. Contemporaneously, we entered into a credit facility and the initial borrowings were used to pay in full Oxford’s existing debt and to pay transaction cost and replenish working capital. The transaction costs were $9.0 million.
 
The purchase consideration was comprised of the following:
 
         
AIM Oxford capital contributions
  $ 36,400,000  
Long-term bank borrowing
    70,000,000  
Revolver borrowing
    2,990,000  
Deemed value of C&T Coal’s retained interest
    19,600,000  
         
Subtotal
    128,990,000  
         
Less:
       
Cash on hand
    1,034,000  
Distribution to C&T Coal
    20,400,000  
         
Net purchase consideration
  $ 107,556,000  
         
 
At that time, C&T Coal and AIM Oxford held a 34.3% and 63.7% limited partner interest in ORLP, respectively, and our GP owned a 2% general partner interest. Also at that time, the members of our GP were AIM Oxford with a 65% ownership interest and C&T Coal with a 35% ownership interest. After taking into


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 1:   ORGANIZATION AND PRESENTATION — (Continued)
 
account their indirect ownership of ORLP through our GP, AIM Oxford held a 65% total interest in ORLP and C&T Coal held a 35% total interest in ORLP.
 
The acquisition of Oxford was accounted for under the purchase method of accounting as prescribed by Statement of Financial Accounting Standards (“SFAS”) 141, Business Combinations, and we have included all operating assets and liabilities of Oxford except for bank debt that was paid in full as part of the transaction. The purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values at the transaction date. The estimated fair values of long-lived tangible and intangible assets were determined primarily through third-party appraisals. Due to C&T Coal’s limited partner interest in the Partnership and its ownership interest in our GP, the purchase accounting fair value adjustments are limited to the newly acquired 65% total interest purchased by AIM Oxford pursuant to Emerging Issues Task Force Abstract (“EITF”) 88-16, Basis in Leveraged Buyout Transactions.
 
The following is a summary of the fair values of the assets acquired and liabilities assumed as of the date of acquisition:
 
         
Net working capital
  $ 5,195,000  
Property and equipment
    77,617,000  
Intangibles
    4,976,000  
Mineral rights
    19,730,000  
Coal sales contracts
    (2,726,000 )
Other
    2,764,000  
         
Total
  $ 107,556,000  
         
 
Subsequent to our formation, AIM Oxford and C&T Coal made several capital contributions for various purposes including purchasing property, plant and equipment and acquiring the surface mining operations of Phoenix Coal Corporation (“Phoenix Coal”). See Note 3. The capital contributions were not all in direct proportion to AIM Oxford’s and C&T Coal’s initial limited partner interests in us. As a result of the disproportionate capital contributions, AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of December 31, 2009, is 64.39% and 32.77%, respectively, with 1.98% and 0.86% interests being owned by our GP and participants in the Partnership’s Long-Term Incentive Plan (“LTIP”), respectively. AIM Oxford and C&T Coal own 66.27% and 33.73%, respectively, in the GP.
 
Basis of Presentation and Principles of Consolidation
 
The accompanying consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”). We have included the accounts of our Predecessor and its subsidiaries for the eight month period ended August 23, 2007 in the consolidated statements of operations, cash flows and shareholders’ equity.
 
We own a 51% interest in Harrison Resources and are therefore deemed to have control. As a result, we consolidate all of Harrison Resources’ accounts with all material intercompany transactions and balances being eliminated in our consolidated financial statements. The 49% portion of Harrison Resources that we do not own is reflected as “Noncontrolling interest” in the consolidated balance sheet. See Note 16.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Use of Estimates
 
In order to prepare financial statements in conformity with US GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities (if any) at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. The most significant areas requiring the use of management estimates and assumptions relate to units-of-production amortization calculations, asset retirement obligations, useful lives for depreciation of fixed assets and estimates of fair values for asset impairment purposes. The estimates and assumptions that we use are based upon our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
 
Cash and Cash Equivalents
 
Cash and cash equivalents consist of all unrestricted cash balances and highly liquid investments that have an original maturity of three months or less. Financial instruments and related items, which potentially subject us to concentrations of credit risk, consist primarily of cash, cash equivalents and trade receivables. We place our cash and temporary cash investments with high credit quality institutions. At times, such investments may be in excess of the FDIC insurance limit. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk relating to our cash and cash equivalents.
 
Restricted Cash
 
We had restricted cash and cash equivalents related to Harrison Resources of $1,877,000 and $1,873,000 at December 31, 2009 and 2008, respectively, which are included in the balance sheet caption “Other long-term assets” due to their anticipated release from restriction. Harrison Resources’ cash, which is deemed to be restricted due to the limitations of its use for Harrison Resources’ operations, primarily relates to funds set aside for future reclamation obligations. See Note 16.
 
Allowance for Doubtful Accounts
 
We establish an allowance for losses on trade receivables when it is probable that all or part of the outstanding balance will not be collected. Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary. There was no allowance for doubtful accounts at December 31, 2009 and 2008.
 
Inventory
 
Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing, or shipment to customers. Inventory also consists of supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes certain operating expenses and operating overhead. The stripping costs incurred in the production phase of a mine are variable production costs included in the costs of the inventory produced during the period that the stripping costs were incurred.
 
Property, Plant and Equipment
 
Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)
 
productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets based on the following schedule:
 
     
Buildings and tipple
  25-39 years
Machinery and equipment
  7-12 years
Vehicles
  5-7 years
Furniture and fixtures
  3-7 years
Railroad siding
  7 years
 
We acquire our reserves through purchases or leases of coal reserves. Coal reserves are recorded at fair value under purchase accounting at our formation date of August 24, 2007 or as part of the Phoenix Coal acquisition. See Note 3. We deplete our reserves using the units-of-production method, without residual value, on the basis of tonnage mined in relation to estimated recoverable tonnage. At December 31, 2009 and 2008, all of our reserves were attributed to mine complexes engaged in mining operations or leased to third parties. We believe that the carrying value of these reserves will be recovered. Residual surface values are classified as land and not depleted.
 
Exploration expenditures are charged to operating expense as incurred and include costs related to locating coal deposits and the drilling and evaluation costs incurred to assess the economic viability of such deposits. Costs incurred in areas outside the boundary of known coal deposits and areas with insufficient drilling spacing to qualify as proven and probable reserves are also expensed as exploration costs.
 
Once management determines there is sufficient evidence that the expenditure will result in a future economic benefit to the Partnership, the costs are capitalized as mine development costs. Capitalization of mine development costs continues until the mine’s production reaches intended operating levels. Amortization of these mine development costs is then initiated using the units-of-production method based upon the estimated recoverable tonnage.
 
Financial Instruments and Derivative Financial Instruments
 
Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, fixed rate debt, variable rate debt, an interest rate swap agreement and an interest rate cap agreement. We do not hold or issue financial instruments or derivative financial instruments for trading purposes.
 
We used an interest rate swap agreement to partially reduce risks related to floating rate financing agreements that are subject to changes in the market rate of interest. Terms of the interest rate swap agreement required us to receive a variable interest rate and pay a fixed interest rate. Our interest rate swap agreement and its variable rate financings were based upon the three-month London Interbank Offered Rate (“LIBOR”). We currently have an interest rate cap agreement that sets an upper limit on LIBOR that we would have to pay under the terms of our existing credit facility. We did not elect hedge accounting for either agreement and so changes in market value on these derivatives are included in interest expense on the consolidated statements of operations.
 
We measure our derivatives (interest rate swap agreement or interest rate cap agreement) at fair value on a recurring basis using significant observable inputs, which are Level 2 inputs as defined in the fair value hierarchy. See Note 12.
 
Our risk management policy is to purchase up to 75% of our diesel fuel gallons on fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and therefore are not accounted for as derivatives. We take physical delivery of all the fuel under these forward contracts and such contracts have a term of one year or less.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)
 
Advance Royalties
 
A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable through a reduction in royalties payable on future production. Amortization of leased coal interests is computed using the units-of-production method over estimated recoverable tonnage.
 
Long-Lived Assets
 
We follow authoritative guidance that requires projected future cash flows from use and disposition of assets to be compared with the carrying amounts of those assets when impairment indicators are present. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount of the assets, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. No impairment losses were recognized during any of the years or periods presented.
 
Identifiable Intangible Assets and Liabilities
 
Identifiable intangible assets are recorded in other assets in the accompanying consolidated balance sheets. We capitalize costs incurred in connection with borrowings or the establishment of credit facilities. These costs are amortized as an adjustment to interest expense over the life of the borrowings or term of the credit facility using the interest method.
 
We also have recorded intangible assets and liabilities at fair value associated with certain customer relationships and below-market coal sales contracts, respectively. These balances arose from the use of purchase accounting for business combinations and so the assets and liabilities were adjusted to fair value. These intangible assets are being amortized over their expected useful lives. See the “Coal Sales Contracts” section of Note 2 and Note 7 for further details.
 
Asset Retirement Obligation
 
Our asset retirement obligations, or AROs, arise from the Surface Mining Control and Reclamation Act of 1977 (SMCRA) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our AROs are recorded initially at fair value. It has been our practice, and we anticipate that it will continue to be our practice, to perform a substantial portion of the reclamation work using internal resources. Hence the estimated costs used in determining the carrying amount of our AROs may exceed the amounts that are eventually paid for reclamation costs if the reclamation work was performed using internal resources.
 
To determine the fair value of our AROs, we calculate on a mine by mine basis the present value of estimated reclamation cash flows. This process requires us to estimate the current disturbed acreage subject to reclamation, estimates of future reclamation costs and assumptions regarding the mine’s productivity. These cash flows are discounted at the credit-adjusted, risk free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives of our mines.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)
 
When the liability is initially recorded for the costs to open a new mine site, the offset is recorded to the producing mine asset. Over time, the ARO liability is accreted to its present value, and the capitalized cost is depreciated over the units-of-production for the related mine. The liability is also increased as additional land is disturbed during the mining process. The timeline between digging the mining pit and extracting the coal is relatively short; therefore, much of the liability created for active mining is expensed within a month or so of establishment because the related coal has been extracted. If the assumptions used to estimate the ARO do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than currently estimated. We review our entire reclamation liability at least annually and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from revisions to cost estimates and the quantity of disturbed acreage during the current year. At December 31, 2009, we had recorded ARO liabilities of $13.3 million, including amounts reported as current liabilities. On an aggregate undiscounted basis, we estimate the cost of final mine closure to be approximately $15.5 million.
 
Income Taxes
 
Prior to being contributed to us in August 2007, Oxford elected to be recognized as an “S” Corporation under the provisions of the Internal Revenue Code, which provides that, in lieu of federal and state income taxes, the shareholders were taxed on their proportionate share of Oxford’s income, deductions, losses and credits. Therefore, no provision or liability for federal or state income taxes was presented in Oxford’s financial statements.
 
As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income for financial statement purposes may differ significantly from taxable income reportable to our unitholders as a result of timing or permanent differences between financial reporting under US GAAP and the regulations promulgated by the Internal Revenue Service.
 
Authoritative accounting guidance on accounting for uncertainty in income taxes establishes the criterion that an individual tax position is required to meet for some or all of the benefits of that position to be recognized in our financial statements. On initial application, the uncertain tax position guidance has been applied to all tax positions for which the statute of limitations remains open. Only tax positions that meet the more-likely-than-not recognition threshold at the adoption date are recognized or will continue to be recognized.
 
Revenue Recognition
 
Revenue from coal sales is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales contract. Under the typical terms of these contracts, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, or truck.
 
On September 29, 2008, we executed and received a prepayment from one of our customers of $13,250,000 toward its future coal deliveries in 2009. This amount was classified as deferred revenue and recognized as revenue as we delivered the coal in accordance with the terms of the arrangement. As of December 31, 2009, $2,090,000 of the prepayment remains on our balance sheet as deferred revenue. We expect this balance will be fully recognized as revenue in 2010.
 
Freight and handling costs paid to third-party carriers and invoiced to customers are recorded as cost of transportation and transportation revenue, respectively.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)
 
Royalty and non-coal revenue consists of coal royalty income, service fees for providing landfill earth moving services, commissions that we receive from a third party who sells limestone that we recover during our coal mining process, service fees for operating a coal unloading facility and fees that we receive for trucking ash for two municipal utility customers. Revenues are recognized when earned or when services are performed. Royalty revenue relates to the overriding royalty we receive on our underground coal reserves that we sublease to a third party mining company. Prior to June 2008, we did not receive any royalties because we had purchased the output of this mine thus no royalty was due to us. Starting in June 2008, our sublessee began selling the coal production for its own account which entitled us to start receiving royalty revenue. For the years ended 2009 and 2008, we received royalties of $4,513,000 and $1,289,000, respectively.
 
Coal Sales Contracts
 
Our below-market coal sales contracts were acquired through the Phoenix Coal acquisition and in connection with our acquisition of Oxford in 2007 for which the prevailing market price for coal specified in the agreement was in excess of the agreement price. The fair value was based on discounted cash flows resulting from the difference between the below-market agreement price and the prevailing market price at the date of acquisition. The difference between the below-market agreements cash flows and the cash flows at the prevailing market price is amortized into coal sales on the basis of tons shipped over the term of the respective contract.
 
Unit-Based Compensation
 
We account for unit-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Unit-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense on a straight-line basis over the corresponding vesting period. The fair value of our LTIP units is determined based on the sale price of our limited partner units in arm’s-length transactions. The unit price fair value was increased in September 2009 in connection with the Phoenix Coal acquisition where additional units were purchased by C&T Coal and AIM Oxford disproportionately to their respective ownership interests to help fund the acquisition. This resulted in C&T Coal’s previous ownership interest being diluted. We verified the reasonableness of the new valuation of our units using traditional valuation techniques for publicly traded partnerships. See Note 13.
 
Earnings Per Unit
 
For purposes of our earnings per unit calculation, we have applied the two class method. The classes of units are our limited partner and general partner units. All outstanding units share pro rata in income allocations and distributions and our general partner has sole voting rights. Limited partner units have been separated into Class A and Class B to prepare for a potential transaction such as an initial public offering.
 
Limited Partner Units:  Basic earnings per unit are computed by dividing net income attributable to limited partners by the weighted average units outstanding during the reporting period. Diluted earnings per unit are computed similar to basic earnings per unit except that the weighted average units outstanding and net income attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to LTIP units upon vesting. In years of a loss, the phantom units are not included in the earnings per unit calculation.
 
General Partner Units:  Basic earnings per unit are computed by dividing net income attributable to our GP by the weighted average units outstanding during the reporting period. Diluted earnings per unit for our GP are computed similar to basic earnings per unit except that the net income attributable to the general partner units is adjusted for the dilutive impact of the phantom units.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)
 
The computation of basic and diluted earnings per unit under the two-class method for limited partner units and general partner units is presented below:
 
                         
    Oxford Resource Partners, LP
            Period from
    Years Ended December 31,   August 24 to
    2009   2008   December 31, 2007
    (in thousands except unit amounts)
 
Limited partner units
                       
Average units outstanding:
                       
Basic
    6,061,072       5,554,395       4,900,000  
Effect of unit-based awards
    23,436       n/a       1,956  
                         
Diluted
    6,084,508       5,554,395       4,901,956  
                         
Net income attributable to limited partners
                       
Basic
  $ 23,037     $ (2,432 )   $ 1,492  
Diluted
    23,038       (2,432 )     1,492  
Earnings per limited partner unit
                       
Basic
  $ 3.80     $ (0.44 )   $ 0.30  
Diluted
    3.79       (0.44 )     0.30  
General partner units
                       
Average units outstanding:
                       
Basic and diluted
    123,023       113,241       100,000  
Net income attributable to general partner
                       
Basic
  $ 467     $ (50 )   $ 30  
Diluted
    466       (50 )     30  
Earnings per general partner unit
                       
Basic
  $ 3.80     $ (0.44 )   $ 0.30  
Diluted
    3.79       (0.44 )     0.30  
 
New Accounting Standards Issued and Adopted
 
In June 2009, the FASB issued a new standard establishing the FASB Accounting Standards Codification (“Codification”) as the sole source of authoritative generally accepted accounting principles. The Codification reorganized existing U.S. accounting and reporting standards issued by the FASB and other related private sector standard setters into a single source of authoritative accounting principles arranged by topic. The Codification supersedes all existing U.S. accounting standards; all other accounting literature not included in the Codification (other than Securities and Exchange Commission guidance for publicly traded companies) is considered non- authoritative. This standard is effective for interim and annual reporting periods ending after September 15, 2009. The Codification does not change existing US GAAP.
 
In September 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-06, Implementation Guidance on Accounting for Uncertainty in Income Taxes and Disclosure Amendments for Nonpublic Entities. This update addresses the need for additional implementation guidance on accounting for uncertainty in income taxes for all entities. The update clarifies that an entity’s tax status as a pass through or tax-exempt not-for-profit entity is a tax position subject to recognition requirements of the standard and therefore must use the recognition and measurement guidance when assessing their tax positions. The ASU 2009-06 updates are effective for interim and annual periods ending after September 15, 2009. The adoption of the guidance in


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)
 
ASU 2009-06 during the third quarter of 2009 did not have a material impact on our consolidated financial statements.
 
In May 2009, the FASB issued new guidance for accounting for subsequent events that established the accounting for and disclosure of events that occur subsequent to the balance sheet date but before financial statements are issued or are available to be issued. The standard provides guidance on management’s assessment of subsequent events and incorporates this guidance into accounting literature. The standard is effective prospectively for interim and annual periods ending after June 15, 2009. We adopted this standard for the year ended December 31, 2009 and the adoption did not impact our consolidated financial statements. See Note 22.
 
In December 2007, the FASB issued revised guidance on business combinations. This new guidance establishes principles and requirements for the acquirer of a business to recognize and measure in its financial statements. This amendment applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets, liabilities, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100% ownership in the acquiree. The amendment also requires expensing acquisition-related costs as incurred and establish disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. This guidance is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008. We have recorded the acquisition of the surface coal mining assets of Phoenix Coal dated September 30, 2009 under this revised guidance. See Note 3. The impact of adoption was to expense $379,000 of previously capitalized acquisition costs as of January 1, 2009.
 
In December 2007, the FASB issued new guidance on the accounting for noncontrolling ownership interests in a subsidiary and for the deconsolidation of a subsidiary. The guidance requires that noncontrolling ownership interests in consolidated subsidiaries be presented in the consolidated balance sheet within partners’ capital as a separate component from the parent’s equity as opposed to mezzanine equity. Consolidated net income will now be disclosed as the amount attributable to both the parent and the noncontrolling interests. The guidance also provides for changes in the parent’s ownership interest in a subsidiary, including transactions where control is retained and where control is relinquished; it also requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent owners and the interests of the noncontrolling owners of a subsidiary. This guidance requires retrospective application to all periods presented, as included in our consolidated financial statements.
 
New Accounting Standards Issued and Not Yet Adopted
 
In August 2009, the FASB issued ASU 2009-05, Measuring Liabilities at Fair Value. The amendment provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the alternative valuation methods outlined in the guidance. It also clarifies that restrictions preventing the transfer of a liability should not be considered as a separate input or adjustment in the measurement of its fair value. This amendment was effective as of the beginning of interim and annual reporting periods that begin after August 27, 2009. The adoption of this guidance did not impact our consolidated financial statements.
 
In June 2009, the FASB amended guidance for the consolidation of a variable interest entity (“VIE”). This guidance updated the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. This standard also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, reconsideration was required only when specific events had occurred. This


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 2:   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (Continued)
 
guidance also requires enhanced disclosure about an enterprise’s involvement with a VIE. The provisions of these updates are effective as of the beginning of interim and annual reporting periods that begin after November 15, 2009. We do not believe that this standard will have a material impact on our consolidated financial statements.
 
NOTE 3:   ACQUISITION
 
On September 30, 2009, we acquired 100% of the active western Kentucky surface mining coal operations of Phoenix Coal. This acquisition provided us an entry into the Illinois Basin and consisted of four active surface coal mines and coal reserves of 20 million tons, as well as mineral rights, working capital and various coal sales and purchase contracts. The application of purchase accounting requires that the total purchase price be allocated to the fair value of assets acquired and liabilities assumed based on the fair values of the assets and the liabilities at the acquisition date. The following table summarizes the fair values of the assets acquired and the liabilities assumed at the date of acquisition:
 
         
Net working capital
  $ 1,594,000  
Mineral rights and land
    10,264,000  
Property, plant and equipment, net
    20,519,000  
Other assets
    404,000  
Coal sales contracts
    (6,600,000 )
Other liabilities
    (4,083,000 )
         
Net assets acquired
  $ 22,098,000  
         
 
The purchase price of $18,275,000 was less than the fair value of the net assets acquired of $22,098,000, and as a result we recorded a gain of $3,823,000 included in other operating income in the consolidated statements of operations for the year ended December 31, 2009. Phoenix Coal’s surface coal mining operations had previously operated at a loss and its management and board of directors elected to exit the surface mining business to focus on maximizing the value of its underground reserves.
 
As part of the acquisition agreement, we agreed to make additional payments of up to $1,000,000 in two installments to Phoenix Coal if Phoenix Coal secured specific surface and mineral rights by certain dates, the last of which will expire on June 30, 2010. During the fourth quarter of 2009, we paid $500,000 to Phoenix Coal for obtaining the surface rights pertaining to certain coal leases. The remaining $500,000 contingent payment was paid to Phoenix Coal in January 2010 for obtaining the mineral rights and is discussed further in our subsequent events Note 22. At the closing date, we concluded that the fair value of the contingent liability was $1,000,000 as the payment was deemed probable.
 
We also assumed a contract with a third party to pay a contingent fee if the third party was able to arrange to lease or purchase, on our behalf, a specified amount of coal reserves by July 31, 2010. The contract called for a payment of $1,000,000; however, we concluded that the fair value of the contingent liability was $625,000 using a probability weighted average of the likely outcomes. That amount was recorded as a liability with a corresponding asset in the consolidated balance sheet under the caption of “Property, plant and equipment, net.”
 
For the fourth quarter of 2009, our surface coal mine operations that we acquired from Phoenix Coal reported total revenue of $22.5 million and a net loss from operations of approximately $1.9 million. As a result of recording a gain of $3.8 million relating to the acquisition, the net income of these operations for the quarter was approximately $1.9 million, excluding general and administrative overhead expenses which are not allocated among subsidiaries.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 3:   ACQUISITION — (Continued)
 
The following unaudited pro forma financial information reflects the consolidated results of operations as if the Phoenix Coal acquisition had occurred at the beginning of each year presented below. The pro forma information includes adjustments primarily for depreciation, depletion and amortization based upon fair values of property, plant and equipment and mineral rights, the lease of $11.1 million of equipment, and interest expense for acquisition debt and additional capital contributions. The pro forma financial information is not necessarily indicative of results that actually would have occurred if we had assumed operation of these assets on the date indicated nor is it indicative of future results.
 
                 
    Pro Forma Results
    for the Year Ended
    December 31,
    2009   2008
    (Unaudited)
 
Revenue
  $ 356,894,000     $ 313,118,000  
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
    6,479,000       (21,711,000 )
 
NOTE 4:   INVENTORY
 
Inventory consisted of the following at December 31:
 
                 
    2009     2008  
 
Coal
  $ 4,759,000     $ 2,462,000  
Fuel
    1,264,000       1,053,000  
Supplies and spare parts
    2,778,000       1,619,000  
                 
Total
  $ 8,801,000     $ 5,134,000  
                 
 
NOTE 5:   PROPERTY, PLANT AND EQUIPMENT, NET
 
Property, plant and equipment, net of accumulated depreciation, depletion and amortization consisted of the following at December 31:
 
                 
    2009     2008  
 
Property, plant and equipment — gross
               
Land
  $ 3,374,000     $ 2,475,000  
Coal reserves
    39,905,000       25,597,000  
                 
Land and mineral rights
    43,279,000       28,072,000  
                 
Buildings and tipple
    2,025,000       1,375,000  
Machinery and equipment
    133,667,000       93,908,000  
Vehicles
    3,913,000       3,005,000  
Furniture and fixtures
    690,000       594,000  
Railroad sidings
    160,000       160,000  
Mine development costs
    8,606,000       4,712,000  
                 
Total property, plant and equipment, gross
    192,340,000       131,826,000  
Less: accumulated depreciation, depletion and amortization
    42,879,000       19,380,000  
                 
Total property, plant and equipment, net
  $ 149,461,000     $ 112,446,000  
                 


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 5:   PROPERTY, PLANT AND EQUIPMENT, NET — (Continued)
 
The amounts of depreciation expense related to owned and leased fixed assets, depletion expense related to owned and leased coal reserves, and amortization expense related to mine development costs for the respective years are set forth below:
 
                                 
                Oxford Mining
    Oxford Resource Partners, LP
  Company
    (Successor)   (Predecessor)
    For the Years Ended
  For the Period from
  For the Period from
    December 31,   Inception to
  January 1, 2007
    2009   2008   December 31, 2007   to August 23, 2007
 
Expense Type:
                               
Depreciation
  $ 19,632,000     $ 11,455,000     $ 3,404,000     $ 7,827,000  
Depletion
    4,672,000       3,226,000       1,030,000       216,000  
Amortization
    1,200,000       1,533,000       318,000       982,000  
 
NOTE 6:   OPERATING LEASES
 
We lease certain equipment under non-cancelable lease agreements that expire on various dates through 2014. Generally the lease agreements are for a period of four years. As of December 31, 2009, aggregate lease payments that are required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are set forth below:
 
         
For the years ending December 31, 2010
  $ 6,289,000  
2011
    6,014,000  
2012
    4,429,000  
2013
    1,570,000  
2014
    123,000  
 
For the years ended December 31, 2009 and 2008, the period from inception to December 31, 2007 and the Predecessor period from January 1, 2007 to August 23, 2007, we incurred lease expenses of approximately $5,428,000, $2,267,000, $260,000 and $1,775,000, respectively.
 
We also entered into various coal reserve lease agreements under which future royalty payments are due based on production. Such payments are capitalized as advance royalties at the time of payment, and amortized into royalty expense based on the stated recoupment rate.
 
NOTE 7:   INTANGIBLE ASSETS AND LIABILITIES
 
                                 
    December 31, 2009  
    Estimated
                   
    Remaining
          Accumulated
    Net Carrying
 
    Life (years)     Cost     Amortization     Value  
 
Intangible assets
                               
Customer relationships
    18     $ 3,315,000     $ 1,019,000     $ 2,296,000  
Deferred financing costs
    3       1,811,000       174,000       1,637,000  
                                 
Total intangible assets
          $ 5,126,000     $ 1,193,000     $ 3,933,000  
                                 
Intangible liabilities
                               
Below-market coal sales contracts
    3     $ 6,600,000     $ 1,705,000     $ 4,895,000  
                                 
 


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 7:   INTANGIBLE ASSETS AND LIABILITIES — (Continued)
 
                                 
    December 31, 2008  
    Estimated
                   
    Remaining
          Accumulated
    Net Carrying
 
    Life (years)     Cost     Amortization     Value  
 
Intangible assets
                               
Customer relationships
    19     $ 3,315,000     $ 621,000     $ 2,694,000  
Deferred financing costs
    4       1,786,000       528,000       1,258,000  
                                 
Total intangible assets
          $ 5,101,000     $ 1,149,000     $ 3,952,000  
                                 
 
Customer relationships represent intangible assets that were recorded at fair value when we acquired Oxford on August 24, 2007. We amortized these assets over the expected life of the respective customer relationships. The amount included in depreciation, depletion and amortization related to customer relationships was $398,000, $446,000 and $174,000 for the years ended December 31, 2009 and 2008 and the period from inception to December 31, 2007, respectively. Oxford did not have this type of intangible asset prior to inception.
 
We capitalize costs incurred in connection with the establishment of credit facilities. On September 30, 2009, we amended and restated our credit agreement (the “Restated Credit Agreement”). The Restated Credit Agreement was determined to be substantially different from our prior credit agreement, and therefore, we wrote off, to interest expense, the remaining unamortized capitalized costs of $1,252,000 from our prior credit agreement (the “Original Credit Agreement”). We incurred costs of $1,811,000 associated with the Restated Credit Agreement which we capitalized. These costs are amortized to interest expense over the life of the Restated Credit Agreement using the interest method. Amortization of deferred financing costs included in interest expense was $530,000, $398,000, $131,000 and $147,000 for the years ended December 31, 2009 and 2008, the period from inception to December 31, 2007 and the Predecessor period from January 1, 2007 to August 23, 2007, respectively.
 
Expected amortization of identifiable intangible assets and deferred loan costs for each of the next five years will be approximately:
 
         
During the years ending December 31, 2010
  $ 984,000  
2011
    868,000  
2012
    639,000  
2013
    254,000  
2014
    227,000  
Thereafter
    961,000  
 
We evaluate our intangible assets for impairment when indicators of impairment exist. For the years ended December 31, 2009 and 2008, the period from inception through December 31, 2007 and the Predecessor period from January 1, 2007 to August 23, 2007, there were no impairments related to intangibles.
 
Based on expected shipments related to the below-market contracts, we expect to record annual amortization income of:
 
         
During the years ending December 31, 2010
  $ 2,345,000  
2011
    1,919,000  
2012
    631,000  

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 8:   OTHER CURRENT LIABILITIES
 
Other current liabilities consist of the following at December 31:
 
                 
    2009     2008  
 
Below-market coal sales contracts(1)
  $ 2,345,000     $  
Accrued interest and interest rate swap(2)
    860,000       2,262,000  
Contingent liabilities(1)
    1,125,000        
Other
    1,384,000       1,098,000  
                 
Total
  $ 5,714,000     $ 3,360,000  
                 
 
 
(1) Below-market coal sales contracts and contingent liabilities assumed with the Phoenix Coal acquisition. See Note 3.
 
(2) The interest rate swap is discussed in Note 11.
 
NOTE 9:   ASSET RETIREMENT OBLIGATION
 
Our asset retirement obligations arise from the SMCRA and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in our mining permits. These activities include reclaiming the pit and support acreage at surface mines.
 
We review our asset retirement obligations at least annually and make necessary adjustments for permit changes as granted by state authorities and for revisions of estimates of the amount and timing of costs. When the liability is initially recorded for the costs to open a new mine site, the offset is recorded to the producing mine asset. Over time, the ARO liability is accreted to its present value, and the capitalized cost is depreciated over the units-of-production for the related mine. The liability is also increased as additional land is disturbed during the mining process. The timeline between digging the mining pit and extracting the coal is relatively short; therefore, much of the liability created for active mining is expensed within a month or so of establishment because the related coal has been extracted.
 
At December 31, 2009, we had recorded asset retirement obligation liabilities of $13.3 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with absolute certainty as of December 31, 2009, we estimate that the aggregate undiscounted cost of final mine closure is approximately $15.5 million.
 
The following table presents the activity affecting the asset retirement obligation for the respective years:
 
                 
    Year Ended December 31,  
    2009     2008  
 
Beginning balance
  $ 9,292,000     $ 7,644,000  
Accretion expense
    650,000       459,000  
Payments
    (3,358,000 )     (2,594,000 )
Revisions in estimated cash flows
    3,802,000       3,783,000  
Additions due to acquisition
    2,957,000        
                 
Total asset retirement obligation
  $ 13,343,000     $ 9,292,000  
Less current portion
    (7,377,000 )     (4,749,000 )
                 
Noncurrent liability
  $ 5,966,000     $ 4,543,000  
                 


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 10:   LONG-TERM DEBT
 
We had long-term debt as of December 31, 2009 and 2008 consisting of the following:
 
                 
    2009     2008  
 
FirstLight Funding I, Ltd.:
               
Term loans
  $ 64,925,000     $ 65,625,000  
Acquisition loans
    21,304,000       14,800,000  
Revolving loans
    4,500,000        
                 
Total FirstLight Funding I, Ltd. Loans
    90,729,000       80,425,000  
                 
Note payable — Peabody #1
    228,000       436,000  
Note payable — Peabody #2
    1,843,000        
Note payable — CONSOL #1
    1,570,000       3,089,000  
Note payable — CONSOL #2
    1,317,000        
Note payable — Other
    24,000       27,000  
                 
Long-term debt
    95,711,000       83,977,000  
Less current portion
    (4,113,000 )     (2,535,000 )
                 
Total long-term debt
  $ 91,598,000     $ 81,442,000  
                 
 
FirstLight Funding I, Ltd. Debt
 
Our Restated Credit Agreement is with a syndicate of lenders with FirstLight Funding I, Ltd. (“FirstLight”) acting as the Agent. The Restated Credit Agreement provides for borrowings of up to $115,000,000 in the form of $70,000,000 of term loans, acquisition loans of up to $25,000,000 and a revolving credit facility of $20,000,000. The Restated Credit Agreement includes the option of a Base Rate (as defined below) or LIBOR interest rate plus an applicable margin depending upon the type of borrowing. Base Rate is defined by the Restated Credit Agreement as the highest of (a) the rate publicly quoted from time to time by The Wall Street Journal as the “base rate on corporate loans posted by at least seventy-five percent (75%) of the nation’s 30 largest banks,” (b) the sum of the Federal Funds Rate plus one-half of one percentage point (0.50%), and (c) effective September 30, 2009, 1.50%. The Restated Credit Agreement is secured by pledging all of our assets and equity interests in wholly-owned subsidiaries. The Restated Credit Agreement requires us to meet various financial covenants and contains financial and other covenants that limit our ability to, among other things, effect acquisitions or dispositions and borrow additional funds.
 
At December 31, 2009 and 2008, we had $90,729,000 and $80,425,000, respectively, of borrowings outstanding and $8,245,000 and $5,404,000, respectively, of letters of credit outstanding. At December 31, 2009 and 2008, we had available unused capacity for borrowings under the Restated Credit Agreement and our original credit agreement (“Original Credit Agreement”) of $7,255,000 and $9,900,000, respectively. As of December 31, 2009 and 2008, the Base Rate was 3.25% and LIBOR was 0.25% and 1.83%, respectively.
 
In February 2009, we were notified by FirstLight that we failed to provide an updated list of after-acquired properties within the timeframe outlined in our Original Credit Agreement. This administrative issue was satisfactorily resolved by the Third Amendment and Waiver to the Original Credit Agreement that was executed on February 23, 2009. The Third Amendment and Waiver waived any potential defaults or potential events of default due to this administrative oversight. As consideration for the Third Amendment and Waiver, we paid and expensed amendment fees totaling $350,000 and the applicable margin for Term Loan 1, Acquisition Loan 1 and the Revolving Loans (as defined in the Original Credit Agreement) was increased from 2.5% to 3.0% per annum for LIBOR advances and from 1.25% to 2.75% per annum on Base Rate


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 10:   LONG-TERM DEBT — (Continued)
 
advances. The applicable margins for Term Loan 2 and Acquisition Loan 2 (as defined in the Original Credit Agreement) were increased from 5.5% to 6.5% per annum on LIBOR advances and from 4.25% to 6.25% per annum on Base Rate advances.
 
In order to facilitate the Phoenix Coal acquisition, it was necessary to enter into negotiations with FirstLight that resulted in another amendment to our Original Credit Agreement. The parties agreed to incorporate this amendment and all prior amendments directly into the Restated Credit Agreement. This resulted in the Restated Credit Agreement, effective September 30, 2009. This amendment allowed for the Phoenix Coal acquisition, subject to certain financial limitations. As consideration for the Restated Credit Agreement, we paid amendment fees totaling $500,000 and the applicable margins for all Term Loan 1, Acquisition Loan 1 and the Revolving Credit Facility amounts outstanding or new borrowings was increased from 3.0% to 4.5% per annum on LIBOR loans and from 2.75% to 4.25% per annum on Base Rate loans. The applicable margins for all Term Loan 2 and Acquisition Loan 2 amounts outstanding increased from 6.5% to 8.0% per annum on LIBOR advances and from 6.25% to 7.75% per annum on Base Rate advances. The amendment also provided for a LIBOR interest rate floor of 1.0% per annum. In addition, the Leverage Ratio covenant, defined as total debt divided by the last twelve months’ EBITDA (as defined in the Restated Credit Agreement), was reduced from 4.25 to 1.00 to 3.50 to 1.00 for the period September 30, 2009 through December 31, 2010 and to 3.00 to 1.00 thereafter.
 
We were in compliance with all covenants under the terms of the Restated Credit Agreement as of December 31, 2009.
 
Term Loans
 
We had $64,925,000 of term loans outstanding as of December 31, 2009 under the Restated Credit Agreement with $43,625,000 representing Term Loan 1 borrowings and $21,300,000 representing Term Loan 2 borrowings. Term Loan 1 provided for borrowings up to $48,000,000 and has a current stated interest rate equal to Base Rate plus 4.25% per annum on advances or, at the election of the borrower, LIBOR plus 4.5% per annum on advances. We are obligated to make quarterly principal payments of $175,000 on Term Loan 1 until maturity. During 2009, we made principal repayments of $700,000. Term Loan 2 provided for borrowings up to $22,000,000 and has a current stated interest rate of Base Rate plus 7.75% per annum on advances or, at the election of the borrower, LIBOR plus 8.0% per annum. No principal repayments are required on Term Loan 2 until maturity. Both obligations mature in August 2012 and any advances requested by us were prorated between the two term loans. Additional borrowings are not permitted under the terms of these term loans.
 
Acquisition Loans
 
We had $21,304,000 of acquisition loans outstanding as of December 31, 2009 with $14,454,000 representing borrowings under Acquisition Loan 1 and $6,850,000 representing Acquisition Loan 2 borrowings. Acquisition Loan 1 provided for borrowings up to $17,000,000 and, as of December 31, 2009, had stated interest rates of Base Rate plus 4.25% per annum on advances or, at the election of the borrower, LIBOR plus 4.50% per annum on advances. Acquisition Loan 2 was for $8,000,000 and had a current stated interest rate of Base Rate plus 7.75% per annum on advances or, at the election of the borrower, LIBOR plus 8.0% per annum on advances. Both obligations mature in August 2012 and any advances requested by us are prorated between the two acquisition loans.
 
We had until March 30, 2009 to utilize these lines of credit, after which time no additional borrowings were permitted. Until March 30, 2009, we paid a commitment fee of 0.50% per annum that was due quarterly on the unused portion of these lines of credit. Beginning on March 30, 2009, we were obligated to make


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 10:   LONG-TERM DEBT — (Continued)
 
quarterly principal payments of $36,500 on Acquisition Loan 1 until maturity. During 2009, we made principal payments of $146,000. No principal repayments are required on Acquisition Loan 2 until maturity.
 
Revolving Credit Facility
 
We have a revolving credit facility for Revolving Loans in the amount of $20,000,000. As of December 31, 2009 and 2008, we had $4,500,000 and $0, respectively, outstanding under the revolving credit facility and $8,245,000 and $5,404,000, respectively, of outstanding letters of credit. The revolving credit facility has an August 2012 maturity and a current stated interest rate of Base Rate plus 4.25% per annum on advances, or, at the election of the borrower, LIBOR plus 4.5% per annum on advances. Under the facility, letters of credit can be issued in an aggregate amount not to exceed $12,000,000, which results in a dollar for dollar reduction in the available capacity. As of December 31, 2009, we had $7,255,000 available on the revolving credit facility. The facility matures on August 24, 2012 and, until that time, only interest payments are required. For our outstanding letters of credit issued under the revolving credit facility, we pay issuing fees of 0.25% per annum on the stated amount of the letters of credit when we issue a letter of credit and an applicable margin of 2.50% per annum to FirstLight, as the Agent, on behalf of the lenders. Additionally, we pay a commitment fee of 0.50% per annum that is due quarterly for any unused capacity under this revolving credit facility.
 
Other Notes Payable
 
Peabody #1 — In July 2007, we acquired coal reserves from Peabody Energy Corporation through one of its subsidiaries in exchange for a note payable that is due in three annual payments of $250,000 at no stated interest rate. The obligation was secured by real property and mineral rights and matures in June 2010. The difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 9.25% and is being amortized into interest expense using the interest method.
 
Peabody #2 — In December 2009, we acquired coal reserves from Peabody Energy Corporation through one of its subsidiaries in exchange for a down payment of $1,000,000 and a note payable that is due in two annual payments of $1,000,000 at no stated interest rate. The obligation was secured by real property and mineral rights and matures in December 2011. The difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 5.5% and is being amortized into interest expense using the interest method.
 
CONSOL #1 — In August 2007, Harrison Resources acquired coal reserves from CONSOL Energy, through one of its subsidiaries, in exchange for a note payable that matures in August 2010. The note is payable in three equal installments of $1,773,000 at no stated interest rate. The difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 8.25% and is being amortized into interest expense using the interest method.
 
CONSOL #2 — In March 2009, we acquired coal reserve leases from CONSOL Energy, through one of its subsidiaries, in exchange for a down payment of $1,500,000 and a note payable that matures in March 2012 in an original face amount of $1,500,000. The note is payable in monthly installments based on units-of-production with a minimum of $500,000 due annually at no stated interest rate. The difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 4.6% and is being amortized using the interest method.
 
Other Note Payable — We acquired coal reserves from an individual with payments due of $5,000 per year for ten years at no stated interest rate. The obligation matures in April 2015. The difference between the face amount and the imputed amount was recorded as a discount using an imputed interest rate of 6.75% and is being amortized into interest expense using the interest method.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 10:   LONG-TERM DEBT — (Continued)
 
Debt Maturity Table
 
The total debt of the Partnership matures as follows:
 
         
During the years ending December 31, 2010
  $ 4,113,000  
2011
    2,268,000  
2012
    89,317,000  
2013
    4,000  
2014
    4,000  
Thereafter
    5,000  
         
    $ 95,711,000  
         
 
NOTE 11:   INTEREST RATE CAP AND SWAP AGREEMENTS
 
On September 11, 2009, we entered into an interest rate cap agreement to hedge our exposure to rising LIBOR interest rates during 2010. This agreement, which has an effective date of January 4, 2010 and a notional amount of $50,000,000, provides for a LIBOR interest rate cap of 2% using three-month LIBOR. LIBOR was 0.251% as of December 31, 2009. We paid a fixed fee of $85,000 for this agreement which has quarterly settlement dates and matures on December 31, 2010. At December 31, 2009, the value of the interest rate cap was $34,000 and was recorded in other assets and the mark-to-market decrease in value of $51,000 was recorded to interest expense in the consolidated statement of operations for the year ended December 31, 2009.
 
We entered into an interest rate swap agreement on August 24, 2007 that had an original notional principal amount of $67,500,000 and a maturity of August 2009. Under the swap agreement, we paid interest at a fixed rate of 4.83% and received interest at a variable rate equal to LIBOR (1.43% as of December 31, 2008), based on the notional amount. The swap agreement decreased interest expense by $1,681,000 for the year ended December 31, 2009 and increased interest expense by $574,000 and $1,107,000 for the year ended December 31, 2008 and the period from inception to December 31, 2007, respectively. As of December 31, 2008, the fair value of the swap agreement was a liability of approximately $1,681,000. The swap agreement matured in August 2009.
 
NOTE 12:   FAIR VALUE OF FINANCIAL INSTRUMENTS
 
Effective January 1, 2008, we adopted the provision for fair value of financial assets and financial liabilities. We utilized fair value measurement guidance that, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchal disclosure framework based upon the quality of inputs used to measure fair value. We elected to defer the application of the guidance to nonfinancial assets and liabilities until our fiscal year 2009 and that application did not have a material impact on our consolidated financial statements as of December 31, 2009. As a result of the adoption, we have elected not to measure any additional financial assets or liabilities at fair value, other than those which were previously recorded at fair value prior to the adoption.
 
The financial instruments measured at fair value on a recurring basis are summarized below:
 
                         
    Fair Value Measurements at December 31, 2009
    Quoted Prices in
      Significant
    Active Markets for
  Significant Other
  Unobservable
    Identical Liabilities
  Observable Inputs
  Inputs
Description
  (Level 1)   (Level 2)   (Level 3)
 
Interest rate cap agreement
  $     $ 34,000     $  


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 12:   FAIR VALUE OF FINANCIAL INSTRUMENTS — (Continued)
 
                         
    Fair Value Measurements at December 31, 2008
    Quoted Prices in
      Significant
    Active Markets for
  Significant Other
  Unobservable
    Identical Liabilities
  Observable Inputs
  Inputs
Description
  (Level 1)   (Level 2)   (Level 3)
 
Interest rate swap agreement
  $     $ 1,681,000     $  
 
The following methods and assumptions were used to estimate the fair values of financial instruments for which the fair value option was not elected:
 
Cash and cash equivalents, trade accounts receivable and accounts payable:  The carrying amount reported in the balance sheets for cash and cash equivalents, trade accounts receivable and accounts payable approximates its fair value due to the short maturity of these instruments.
 
Fixed rate debt:  The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.
 
Variable rate debt:  The fair value of variable rate debt is estimated using discounted cash flow analyses, based on our best estimates of market rate for instruments with similar cash flows.
 
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
 
                                 
    December 31, 2009   December 31, 2008
    Carrying
      Carrying
   
    Amount   Fair Value   Amount   Fair Value
 
Fixed rate debt
  $ 4,982,000     $ 4,952,000     $ 3,552,000     $ 3,311,000  
Variable rate debt
  $ 90,729,000     $ 90,729,000     $ 80,425,000     $ 80,425,000  
 
NOTE 13:   LONG-TERM INCENTIVE PLAN
 
In November 2007, we implemented a Long-Term Incentive Plan or LTIP whereby equity awards may be granted to executives, officers, employees, directors, or consultants, as determined by the Board of Director’s Compensation Committee (“Compensation Committee”), in the form of partnership units, and may include distribution equivalent rights. Under this program, we have granted phantom units that have no rights until they are converted upon vesting. At our option, we can issue cash or LTIP units upon vesting, although we do not intend to settle these awards in cash. To date, we have always issued units and those units have the right to an allocation of income and to distributions but are not obligated to participate in any capital calls. See Unit-Based Compensation section of Note 2 for a further description of how we value our LTIP units.
 
These units are subject to such conditions and restrictions as our Compensation Committee may determine, including continued employment or service or achievement of pre-established performance goals and objectives. Currently, there are no outstanding performance awards. Although we have the option to repurchase these units upon employee termination, we currently do not have the intent to do so. Generally, these units vest in equal annual increments over four years with accelerated vesting of the first increment in certain cases. The total number of units authorized to distribute under the plan was 181,348 at December 31, 2009. Unless amended by our Compensation Committee, the LTIP will expire in November 2017.
 
Surrendered units were used to satisfy the individual tax obligations of those LTIP participants electing a net issuance whereby we pay the employee’s tax liability and the employee surrenders a sufficient number of units equal to the amount of tax liability assumed by us. After consideration of the grant vesting during 2009, 44,431 units remain available for issuance in the future.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 13:   LONG-TERM INCENTIVE PLAN — (Continued)
 
We recognize compensation expense over the vesting period of the units, which is generally four years for each award. For the years ended December 31, 2009 and 2008 and for the period from inception to December 31, 2007, our gross LTIP expense was approximately $472,000, $468,000 and $25,000, respectively, which is included in selling, general and administrative expenses (SG&A) in our consolidated statements of operations. As of December 31, 2009 and 2008, approximately $840,000 and $1,118,000, respectively, of cost remained unamortized which we expect to recognize over a remaining weighted average period of 2 years.
 
The following table summarizes additional information concerning our unvested LTIP units:
 
                 
          Weighted Average
 
          Grant Date
 
    Units     Fair Value  
 
Unvested balance at December 31, 2007
    106,410     $ 11.20  
Granted
    43,172       11.20  
Issued
    (26,984 )     11.20  
Surrendered
    (8,825 )     11.20  
Forfeited
    (6,410 )     11.20  
                 
Unvested balance at December 31, 2008
    107,363     $ 11.20  
Granted
    11,148       17.43  
Issued
    (30,883 )     11.75  
Surrendered
    (8,578 )     11.88  
                 
Unvested balance at December 31, 2009
    79,050     $ 11.79  
                 
 
The value of LTIP units vested during the years ended December 31, 2009 and 2008 and the period from inception to December 31, 2007 was $465,000, $401,000 and $0, respectively.
 
NOTE 14:   WORKERS’ COMPENSATION AND BLACK LUNG
 
We have no liabilities under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees, former employees and their dependents. With regard to workers’ compensation, we provide benefits to our employees by being insured through state sponsored programs or an insurance carrier where there is no state sponsored program.
 
NOTE 15:   RETIREMENT PLAN
 
We had a money purchase pension plan in which substantially all full-time employees with more than six months of service participated. Contributions were made annually at 4% of qualified wages and an additional 4% was contributed on wages over the FICA limit up to the maximum allowed under the Internal Revenue Code. We incurred expense of $1,522,000, $1,083,000, $379,000 and $496,000 for the years ended December 31, 2009 and 2008, the period from inception to December 31, 2007 and the Predecessor period from January 1, 2007 to August 23, 2007, respectively.
 
Effective January 1, 2010, the money purchase pension plan was replaced with a 401(k) plan.
 
NOTE 16:   NONCONTROLLING INTEREST
 
Harrison Resources, a limited liability company, was formed in March 2006 by Oxford to acquire coal properties, develop mine sites, and mine coal for sale to customers. Effective January 30, 2007, 49% of Harrison Resources was sold to CONSOL Energy and its ownership interest is held by one of its subsidiaries. Harrison Resources’ revenues which are included in the consolidated statements of operations were


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 16:   NONCONTROLLING INTEREST — (Continued)
 
$37,190,000, $20,605,000, $4,791,000, and $4,250,000 for the years ended December 31, 2009 and 2008 and the periods from inception to December 31, 2007 and from January 1, 2007 to August 23, 2007, respectively. Oxford Mining has a contract mining agreement with Harrison Resources to operate the mines for an agreed-upon per ton price and markets all the coal under a broker agreement with Harrison Resources.
 
Harrison Resources’ cash, which is deemed to be restricted due to the limitations of its use for Harrison Resources’ operations and primarily relates to funds set aside for future reclamation obligations, was $1,877,000 and $1,873,000 at December 31, 2009 and 2008, respectively, and is included in the balance sheet caption Other long-term assets. Harrison Resources’ total net assets as of December 31, 2009 and 2008 were $4,218,000 and $4,688,000, respectively.
 
The noncontrolling interest represents the 49% of Harrison Resources owned by CONSOL Energy, through one of its subsidiaries, and consists of the following:
 
                 
    Year Ended December 31  
    2009     2008  
 
Beginning balance
  $ 2,297,000     $ 1,856,000  
Net income
    5,895,000       2,891,000  
Distributions to owners
    (6,125,000 )     (2,450,000 )
                 
Ending balance
  $ 2,067,000     $ 2,297,000  
                 
 
NOTE 17:   COMMITMENTS AND CONTINGENCIES
 
Coal Sales Contracts
 
We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Most of these prices are subject to pass through or inflation adjusters that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. The remaining life of our long-term contracts ranges from one to nine years.
 
Purchase Commitments
 
We use independent contractors to mine some of our coal at a few of our mines. We also purchase coal from third parties in order to meet quality or delivery requirements under our customer agreements. We assumed one long-term purchase agreement as a result of the Phoenix Coal acquisition. Under this agreement, we are committed to purchase a certain volume of coal 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. Additionally, we bought coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. Supply disruptions could impair our ability to fill customer orders or require us to purchase coal from other sources at a higher cost to us in order to satisfy these orders.
 
Transportation
 
We depend upon barge, rail, and truck transportation systems to deliver our coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments. We entered into a long-term transportation contract on April 1, 2006 for rail services, and that agreement has been amended and extended through March 31, 2011.


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 17:   COMMITMENTS AND CONTINGENCIES — (Continued)
 
Defined Contribution Pension Plan
 
At December 31, 2009, we had an obligation to pay our GP for the purpose of funding our GP’s commitments to the money purchase pension plan in the amount of $1,522,000. This amount is expected to be paid by September 2010.
 
Security for Reclamation and Other Obligations
 
As of December 31, 2009, we had $31,300,000 in surety bonds and $14,000 in cash bonds outstanding to secure certain reclamation obligations. Additionally, as of December 31, 2009, we had letters of credit outstanding in support of these surety bonds of $6,900,000 and also a letter of credit of $1,345,000 guaranteeing an operating lease. Further, as of December 31, 2009, we had certain road bonds of $645,000 outstanding and performance bonds outstanding of $12,300,000. Our management believes these bonds and letters of credit will expire without any claims or payments thereon and thus any subrogation or other rights with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.
 
Legal
 
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes these claims will not have a material adverse effect on our financial position, liquidity or operations.
 
Guarantees
 
Our GP and the Partnership guarantee certain obligations of our subsidiaries. Our management believes that these guarantees will expire without any liability to the guarantors, and therefore any indemnification or subrogation commitments with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.
 
NOTE 18:   CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
 
We have a credit policy that establishes procedures to determine creditworthiness and credit limits for trade customers. Generally, credit is extended based on an evaluation of the customer’s financial condition. Collateral is not generally required, unless credit cannot be established.
 
We market our coal principally to electric utilities, municipalities and electric cooperatives and industrial customers in Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. As of December 31, 2009 and 2008, accounts receivable from electric utilities totaled $18.2 million and $16.3 million or 75% and 76% of total trade receivables, respectively. A small portion of these sales are executed through coal brokers. Three customers individually accounted for greater than 10% of coal sales for the year ended December 31, 2009 which, in the aggregate, represented approximately 64.1% of coal sales for the year. Two customers individually accounted for greater than 10% of coal sales which, in the aggregate, represented approximately 55.5%, 64.0% and 64.2% of coal sales for the year ended December 31, 2008, the period from inception to December 31, 2007 and the Predecessor period from January 1, 2007 to August 23, 2007, respectively. These same customers, in the aggregate, represented approximately 58.5% and 51.5% of the outstanding accounts receivable at December 31, 2009 and 2008, respectively.
 
NOTE 19:   RELATED PARTY TRANSACTIONS
 
In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (“Services Agreement”) with our GP. The Services


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 19:   RELATED PARTY TRANSACTIONS — (Continued)
 
Agreement is terminable by either party upon thirty days’ written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management services, human resources, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, we reimbursed our GP for costs primarily related to payroll for all the periods after August 24, 2007, of which $2,504,000 and $2,502,000 were included in our accounts payable at December 31, 2009 and 2008, respectively.
 
Also in connection with our formation in August 2007, Oxford Mining entered into an advisory services agreement (“Advisory Agreement”) with certain affiliates of AIM Oxford. The Advisory Agreement runs for a term of ten years until August 2017, subject to earlier termination at any time by the AIM Oxford affiliates. Under the terms of the Advisory Agreement, the AIM Oxford affiliates have duties as financial and management advisors to Oxford Mining, including providing services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services for the operation and growth of Oxford Mining. These services consist of advisory services of a type customarily provided by sponsors of U.S. private equity firms to companies in which they have substantial investments. Such services are rendered at the reasonable request of Oxford Mining. The basic annual fees under the Advisory Agreement were $250,000 for 2008, and for 2009 and each year thereafter increase based on the percentage increase in gross revenues. Further fees are payable for additional significant services requested. Pursuant to the Advisory Agreement, advisory fees were paid to AIM Oxford affiliates of $1,307,000 and $225,000 for the years ended December 31, 2009 and 2008, respectively. No advisory fees were paid for the period from inception to December 31, 2007. The advisory fees paid for 2009 included a transaction fee of $1,000,000 paid to the AIM Oxford affiliates for additional significant services in connection with the Restated Credit Agreement and the fee is included in deferred financing costs. See FirstLight Funding I, Ltd. Debt section of Note 10.
 
We have debt with CONSOL Energy, the minority owner of Harrison Resources, as described in Note 10. Also, coal was purchased for resale from CONSOL Energy in the amount of $1,089,000 and $4,780,000 during the period from inception to December 31, 2007 and the Predecessor period from January 1, 2007 to August 23, 2007, respectively. We did not purchase coal from CONSOL Energy for resale during the years ended December 31, 2009 and 2008.
 
Contract services were provided to Tunnell Hill Reclamation, LLC, a company with common owners, in the amount of $695,000, $1,050,000, $186,000 and $1,104,000 for the years ended December 31, 2009 and 2008, the period from inception to December 31, 2007 and the Predecessor period from January 1, 2007 to August 23, 2007, respectively. Accounts receivable were $70,000 and $0 from Tunnel Hill at December 31, 2009 and 2008, respectively. We have concluded that Tunnell Hill Reclamation, LLC does not represent a variable interest entity.
 
We had accounts receivable from employees and owners in the amount of $28,000 and $6,000 at December 31, 2009 and 2008, respectively, which have been collected in full subsequent to year end.
 
NOTE 20:   SUPPLEMENTAL CASH FLOW INFORMATION
 
The Partnership revised our cash flow statements for 2009, 2008, and the period from August 24, 2007 to December 31, 2007 to correct the presentation of certain non-cash transactions in the cash flow statement. Coal reserves purchased with debt were previously disclosed as cash transactions impacting the amounts reported in accounts payable and purchases of property and equipment are now presented as non-cash activities. We have also corrected the supplemental disclosures to reflect the appropriate classifications of certain non-cash transactions, and changed its presentation of the activity on our revolving credit facility from


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 20:   SUPPLEMENTAL CASH FLOW INFORMATION — (Continued)
 
net to gross. The following table presents the impact of the reclassifications on our total operations, investing and financing activities:
 
                                                 
    As
          As
       
    Previously
      As
  Previously
      As
    Reported   Reclassifications   Revised   Reported   Reclassifications   Revised
 
Cash Flows
                                               
    December 31, 2009   December 31, 2008
         
CASH FLOWS FROM OPERATING ACTIVITIES:
                                               
Net cash provided by (used in) operating activities
    35,540       1,643       37,183       33,951       41       33,992  
CASH FLOWS FROM INVESTING ACTIVITIES:
                                               
Net cash used in investing activities
    (51,115 )     1,587       (49,528 )     (23,901 )     (41 )     (23,942 )
CASH FLOWS FROM FINANCING ACTIVITIES:
                                               
Net cash provided by (used in) financing activities
    3,762       (3,230 )     532       4,494             4,494  
         
    Period from August 24
to December 31, 2007
  Period from January 1
to August 23, 2007
         
CASH FLOWS FROM OPERATING ACTIVITIES:
                                               
Net cash provided by (used in) operating activities
    (8,478 )     (41 )     (8,519 )     17,634             17,634  
CASH FLOWS FROM INVESTING ACTIVITIES:
                                               
Net cash used in investing activities
    (103,336 )     4,591       (98,745 )     (16,619 )           (16,619 )
CASH FLOWS FROM FINANCING ACTIVITIES:
                                               
Net cash provided by (used in) financing activities
    111,274       (4,550 )     106,724       (234 )           (234 )


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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
NOTE 20:   SUPPLEMENTAL CASH FLOW INFORMATION — (Continued)
 
Supplemental cash flow information:
 
                                 
    Oxford Resource
  Oxford Mining
    Partners, LP
  Company
    (Successor)   (Predecessor)
                For the
            For the
  Period from
            Period from
  January 1,
    For the Years Ended
  Inception to
  2007 to
    December 31,   December 31,
  August 23,
    2009   2008   2007   2007
 
Cash paid for:
                               
Interest
  $ 6,005,000     $ 6,395,000     $ 2,202,000     $ 2,625,000  
Non-cash activity
                               
Market value of common units vested in LTIP
    363,000       302,000              
Accounts payable for purchase of coal reserves as of December 31
    62,000       87,000              
Accounts payable for purchase of royalty advances as of December 31
    55,000       5,000              
Accounts payable for purchase of property and equipment as of December 31
    2,049,000       3,161,000       983,000       4,924,000  
Purchase of coal reserves with debt
    3,230,000             4,550,000        
 
NOTE 21:   SEGMENT INFORMATION
 
We operate in one business segment. We operate surface coal mines in Northern Appalachia and the Illinois Basin and sell high value steam coal to utilities, industrial customers or other coal-related organizations primarily in the eastern United States. Our operating and executive management reviews and bases its decisions upon consolidated reports. All three of our operating subsidiaries participate primarily in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to their customers. The operating companies share customers and a particular customer may receive coal from any one of the operating companies.
 
NOTE 22:   SUBSEQUENT EVENTS
 
The following represents material events that have occurred subsequent to December 31, 2009 through March 24, 2010, the date these financial statements were issued.
 
We paid Phoenix Coal $500,000 in January 2010 for achieving specified objectives as to arrangements for additional coal leases in western Kentucky.
 
We made a quarterly distribution to our unitholders of $2,815,000 in February 2010.
 
We granted LTIP awards in January and February 2010 in the amount of $649,000. Of those units, the first 25% vested in January and March respectively with a remaining unvested value of $487,000. The remaining grant vests ratably over the next three years.


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REPORT OF INDEPENDENT AUDITORS
 
The Board of Directors of Phoenix Coal Inc.
 
We have audited the accompanying combined balance sheets of the Carved-Out Surface Mining Operations of Phoenix Coal Inc. (the Company) as described in Note 1, as of September 30, 2009 and December 31, 2008, and the related combined statements of operations and comprehensive loss, group equity, and cash flows for the nine months ended September 30, 2009 and for the years ended December 31, 2008 and 2007. These financial statements are the responsibility of Phoenix Coal Inc.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of the Company as described in Note 1, at September 30, 2009 and December 31, 2008, and the combined results of their operations and their cash flows for the nine months ended September 30, 2009 and for the years ended December 31, 2008 and 2007 in conformity with U.S. generally accepted accounting principles.
 
/s/ Ernst & Young LLP
 
Louisville, Kentucky
December 18, 2009


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Table of Contents

Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
 
                 
    September 30,
    December 31,
 
    2009     2008  
 
Assets
               
Current assets:
               
Trade accounts receivable
  $ 6,349,835     $ 2,843,134  
Coal inventories
    252,357       452,558  
Prepaid expenses and other current assets
    591,957       400,886  
                 
Total current assets
    7,194,149       3,696,578  
Property, plant, and equipment, net
    48,576,077       45,162,984  
Restricted certificates of deposit
          509,825  
Mining rights, mine development costs and mineral reserves net of accumulated amortization of $3,796,187 in 2009 and $3,888,082 in 2008
    16,707,173       15,649,026  
Prepaid royalties
    188,602       216,147  
                 
    $ 72,666,001     $ 65,234,560  
                 
Liabilities and shareholders’ equity
               
Current liabilities:
               
Trade accounts payable and accrued liabilities
  $ 8,839,064     $ 6,449,019  
Current portion of long-term debt
    8,224,486       6,532,045  
Current portion of asset retirement obligations
    1,627,800       1,958,000  
                 
Total current liabilities
    18,691,350       14,939,064  
                 
Asset retirement obligations, less current portion
    2,898,278       2,366,000  
Long-term debt, less current portion
    13,080,972       14,641,745  
Group equity
    37,995,401       33,287,751  
                 
    $ 72,666,001     $ 65,234,560  
                 
 
See accompanying notes.


F-56


Table of Contents

Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
 
                         
    Nine Months
    Year
    Year
 
    Ended
    Ended
    Ended
 
    September 30,
    December 31,
    December 31,
 
    2009     2008     2007  
 
Revenue
  $ 58,493,767     $ 76,645,989     $ 66,973,145  
Cost and expenses:
                       
Cost of sales, exclusive of depreciation and amortization shown separately
    54,531,148       71,877,168       61,939,870  
Selling expenses
    5,851,821       8,188,945       7,746,824  
General and administrative expenses
    6,947,484       11,090,565       5,822,082  
Depreciation and amortization
    5,799,952       6,646,543       4,064,979  
Sales contract termination cost
    3,000,000              
Asset impairment
                2,873,055  
                         
      76,130,405       97,803,221       82,446,810  
                         
Loss from operations
    (17,636,638 )     (21,157,232 )     (15,473,665 )
Other income (expense)
                       
Interest expense
    (2,600,873 )     (1,811,280 )     (86,316 )
Interest income
    3,900       6,302       8,292  
Other, principally sale of assets
    (5,142 )     (1,014,424 )     739,493  
                         
      (2,602,115 )     (2,819,402 )     661,469  
                         
Loss before income taxes
    (20,238,753 )     (23,976,634 )     (14,812,196 )
Income taxes
    16,081       37,838       70,155  
                         
Net loss and comprehensive loss
  $ (20,254,834 )   $ (24,014,472 )   $ (14,882,351 )
                         
 
See accompanying notes.


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Table of Contents

Carved-Out Surface Mining Operations of Phoenix Coal Inc.

Combined Statements of Group Equity
For the Nine Months Ended September 30, 2009 and
the Years Ended December 31, 2008 and 2007
 
         
Group equity at December 31, 2006
  $ 18,800,282  
Contribution from parent
    21,670,486  
Share-based compensation allocated from parent
    813,454  
Net loss
    (14,882,351 )
         
Group equity at December 31, 2007
    26,401,871  
Contribution from parent
    26,511,411  
Share-based compensation allocated from parent
    4,388,941  
Net loss
    (24,014,472 )
         
Group equity at December 31, 2008
    33,287,751  
Contribution from parent
    22,703,615  
Share-based compensation allocated from parent
    2,258,869  
Net loss
    (20,254,834 )
         
Group equity at September 30, 2009
  $ 37,995,401  
         
 
See accompanying notes.


F-58


Table of Contents

Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
 
                         
    Nine Months
    Year
    Year
 
    Ended
    Ended
    Ended
 
    September 30,
    December 31,
    December 31,
 
    2009     2008     2007  
 
Operating activities
                       
Net loss
  $ (20,254,834 )   $ (24,014,472 )   $ (14,882,351 )
Adjustments to reconcile net loss to net cash used in operating activities:
                       
Depreciation and amortization
    5,799,952       6,646,543       4,064,979  
Loss (gain) on sale of property and equipment
    792       1,012,779       (742,086 )
Share-based compensation
    2,258,869       4,388,941       813,454  
Asset impairment write down
                2,873,055  
Asset retirement obligations
    (644,217 )     (730,436 )     1,244,438  
Changes in noncash operating assets and liabilities:
                       
Accounts receivable
    (3,506,701 )     1,452,404       (2,541,574 )
Inventories
    200,201       620,139       (816,314 )
Prepaid expenses and other current assets
    (191,071 )     34,096       (235,371 )
Trade accounts payable and other accrued liabilities
    2,390,045       (2,169,229 )     5,147,696  
                         
Net cash used in operating activities
    (13,946,964 )     (12,759,235 )     (5,074,074 )
Investing activities
                       
Restricted certificates of deposit
    509,825       (509,825 )      
Proceeds from sale of investments
                216,477  
Payments for other assets, principally mine development and mining rights
    (1,631,921 )     (3,194,375 )     (6,879,142 )
Proceeds from sale of property and equipment
    210,000       683,912       1,582,346  
Payments for property and equipment
    (1,346,609 )     (3,187,274 )     (9,712,212 )
                         
Net cash used in investing activities
    (2,258,705 )     (6,207,562 )     (14,792,531 )
Financing activities
                       
Contributions from parent
    22,703,615       26,511,411       21,670,486  
Principal payments on debt
    (209,025 )     (1,058,336 )     (939,463 )
Payments on equipment financing
    (6,288,921 )     (6,486,278 )     (1,007,250 )
                         
Net cash provided by financing activities
    16,205,669       18,966,797       19,723,773  
                         
Net decrease in cash and cash equivalents
                (142,832 )
Cash and cash equivalents, beginning of period
                142,832  
                         
Cash and cash equivalents, end of period
  $     $     $  
                         
Supplemental disclosure
                       
Interest paid
  $ 1,237,268     $ 1,055,688     $ 245,893  
                         
Noncash investing and financing activities
                       
Vendor financing for equipment purchases
  $ 6,629,614     $ 18,025,434     $ 10,293,381  
                         
 
See accompanying notes.


F-59


Table of Contents

Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008
 
1.   Nature of Operations and Significant Accounting Policies
 
Nature of Operations and Basis of Presentation
 
Phoenix Coal Inc. (PCI) and Phoenix Coal Corporation, a wholly owned subsidiary of PCI, (collectively, the Parent) are engaged in the development, production, and sale of steam coal to utilities and industrial fuel consumers. The Parent is also engaged in the development of underground coal reserves. Mining activities are currently limited to one reportable business segment, which is the Illinois Basin. PCI is a publicly traded entity listed on the Toronto Stock Exchange and is headquartered in Madisonville, Kentucky, with corporate offices in Louisville, Kentucky.
 
On September 30, 2009, the Parent sold substantially all of its operating assets and operations associated with its surface coal mining operations in western Kentucky to Oxford Mining Company, LLC (Oxford). The assets acquired by Oxford were utilized in the operation of multiple surface coal mining locations and related support facilities (maintenance shop, barge loading facility, and coal preparation plant) (collectively, the Company). The assets transferred included coal and supplies inventories, coal reserves and related prepaid royalties, mining property, plant, and equipment, mining rights, coal purchase contracts, and coal sales contracts.
 
These combined financial statements represent the carved-out financial position, results of operations, changes in group equity, and cash flows of the Company, combined from different legal entities, all of which are wholly owned subsidiaries of the Parent. The carved-out financial statements have been prepared in accordance with SEC Financial Reporting Manual section 2065 Acquisition of Selected Parts of an Entity May Result in Less Than Full Financial Statements and Staff Accounting Bulletin (SAB) Topic 1.B. Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity. The carved-out financial statements include allocations of certain Parent corporate expenses and intercompany interest charges (see Note 2). Management believes that the assumptions and estimates used in preparation of the carved-out financial statements are reasonable. However, the carved-out financial statements may not necessarily reflect the Company’s financial position, results of operations, or cash flows in the future, or what its financial position, results of operations, or cash flows would have been if the Company had been a stand-alone entity during the periods presented. Because of the nature of these carved-out financial statements, the Parent’s net investment in the Company, including amounts due to/from the Parent, is shown as “group equity.”
 
The carved-out financial statements have been prepared in accordance with accounting principles generally accepted in the United States (GAAP). All monetary references expressed in these notes are references to United States dollars. All intercompany transactions between the Company’s locations have been eliminated.
 
Use of Estimates
 
The preparation of the carved-out financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the carved-out financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. The assets and liabilities which require management to make significant estimates and assumptions in determining carrying values include, but are not limited to, coal inventories, property, plant, and equipment, mining rights, mine development, mineral reserves, prepaid royalties, provision for income taxes, and asset retirement obligations.


F-60


Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
1.   Nature of Operations and Significant Accounting Policies — (Continued)
 
Parent Sale of Surface Mining Operations
 
The Parent currently reports its consolidated financial results in accordance with Canadian generally accepted accounting principles. As these carved-out financial statements represent a subset of the Parent’s financial activity and are prepared under United States GAAP, the accounting treatment and related materiality levels of certain transactions may differ from the Parent’s separately reported consolidated financial results. As previously noted, on September 30, 2009, the Parent sold substantially all of its operating assets and operations associated with its surface coal mining operations in western Kentucky to Oxford. The consideration received under the terms of the acquisition agreement included cash, payment by Oxford of all debt associated with the equipment being sold and the assumption of certain asset retirement obligations.
 
As of June 30, 2009, pursuant to the Canadian Institute of Chartered Accountants’ Handbook Section 3475, Disposal of Long-lived Assets and Discontinued Operations, (a Canadian accounting standard that is consistent with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 360, Property, Plant, and Equipment), the Parent classified these surface mining operations as held for sale and wrote down the related assets to the amount expected to be realized on sale, resulting in a charge of $38,920,000 to the Parent’s consolidated statement of operations for the six months ended June 30, 2009. Concurrent with the closing on September 30, 2009, the Parent decreased this estimated loss by $2,680,000 and reported a loss on the sale of these surface mining operations of approximately $36,240,000 for the nine months ended September 30, 2009. For purposes of these financial statements, an impairment charge was not recorded in the carved-out statement of operations as the surface mining assets are, from the Company’s perspective, classified as assets held for use and therefore tested for impairment based on estimated future undiscounted cash flows to be realized from the use of the assets. Based on the Company’s impairment analysis, as of September 30, 2009 the estimated future cash flows from the surface mining operations exceeded their carrying value.
 
Cash and Cash Equivalents, Including Restricted Cash
 
The Parent provides cash as needed to support the Company’s surface mining operations, including restricted cash used to collateralize reclamation bonds. Any excess cash collected by the Company at the end of each business day is transferred to the Parent’s bank account. Consequently, the accompanying balance sheets do not include any cash balances. Transfers of cash between the Company and the Parent are classified as a financing activity in the statement of cash flows. At December 31, 2008, pending the transfer of mining permits related to business acquisitions completed in July 2008, restricted certificates of deposit totaling $509,825 were owned by the Company and are included in the balance sheet at that date.
 
Trade Accounts Receivable
 
Trade accounts receivables are recorded at the invoiced amount and do not bear interest. Customers are primarily investment grade companies and quasi-governmental agencies. While the Company is subject to credit risk from its trade accounts receivable, the Company manages its risk by providing credit terms on a case by case basis. As a result, the Company has not experienced any instances of nonpayment and does not currently require an allowance for doubtful accounts. Management monitors customers closely and will record an allowance if trade account balances become potentially uncollectible. Subsequent to September 30, 2009 and December 31, 2008, the Company has collected all of its trade accounts receivable at the applicable reporting dates.


F-61


Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
1.   Nature of Operations and Significant Accounting Policies — (Continued)
 
Inventory
 
The Company accounts for coal inventories on a first-in, first-out basis and values these inventories at the lower of cost and net realizable value with cost determined using average cost per ton. Coal inventory values were $25.95 per ton at September 30, 2009 and $22.62 per ton at December 31, 2008. At September 30, 2009 and December 31, 2008, the coal inventory was valued at net realizable value.
 
The Company accounts for parts inventory using the original cost on a first-in, first-out basis. Parts inventory is included in other current assets and totaled $119,484 and $103,555 as of September 30, 2009 and December 31, 2008, respectively.
 
Property, Plant, and Equipment
 
Property, plant, and equipment are stated at cost. Depreciation is calculated on the straight-line basis with useful lives that range from 5 to 40 years. Depreciation expense for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007 was $4,352,339, $4,362,179, and $2,222,516, respectively.
 
The cost of assets sold, retired, or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts and any resulting gain or loss is included in operations. Expenditures for maintenance and repairs are charged to expense as incurred.
 
Consistent with FASB ASC 360, Property Plant, and Equipment, the Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that their carrying amount may not be recoverable. This impairment testing is based on estimated future undiscounted cash flows to be realized from the use of the long-lived asset. These future cash flows are developed using assumptions that reflect the long-term operating plans given management’s best estimate of future economic conditions, such as revenues, production costs, and reserve estimates. A change in these factors could result in a modification of the impairment calculation.
 
Mine Development Costs
 
Mine development costs represent the costs incurred to prepare future mine sites for mining and are amortized on the units-of-production method. The net book value of mine development costs was $2,650,129 and $529,112 at September 30, 2009 and December 31, 2008, respectively. Accumulated amortization of mine development costs was $471,125 and $505,902 at September 30, 2009 and December 31, 2008, respectively. Development costs amortized totaled $384,743, $665,243, and $455,508 for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007, respectively.
 
Mining Rights
 
Mining rights, which are rights to mine coal properties acquired through coal leases, are recorded at cost. Mining rights are amortized on the units-of-production method. The net book value of mining rights totaled $13,867,610 and $14,930,480 at September 30, 2009 and December 31, 2008, respectively. Accumulated amortization of mining rights was $3,325,062 and $3,382,180 at September 30, 2009 and December 31, 2008, respectively. Mining rights amortization totaled $1,062,870, $1,619,121, and $1,386,955 for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007, respectively.
 
In June 2007, the Crittenden County Coal mining operation was closed due to uneconomical mining conditions. As a result of the closing, the Company recorded an asset impairment write down related to its mining rights of $2,873,055.


F-62


Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
1.   Nature of Operations and Significant Accounting Policies — (Continued)
 
Mineral Reserves
 
Mineral reserves, which are coal properties for which the Company owns the coal in place, are recorded at cost. At September 30, 2009 and December 31, 2008, the net book value of mineral reserves totaled $189,434 and was attributable to properties where the Company was not currently engaged in mining operations and, therefore, the assets were not currently being depleted.
 
Prepaid Royalties
 
Rights to leased coal lands are often acquired through royalty payments. Where royalty payments represent prepayments recoupable against production, they are recorded as a prepaid asset. As mining occurs on these leases, the prepayment is charged to cost of sales. Prepaid royalties were $188,602 and $216,147 at September 30, 2009 and December 31, 2008, respectively.
 
Asset Retirement Obligations
 
FASB ASC 410-20, Asset Retirement Obligations, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Company’s asset retirement obligation (ARO) liabilities primarily consist of spending estimates related to reclaiming surface land and support facilities in accordance with federal and state reclamation laws as defined by each mining permit.
 
Revenue Recognition
 
Revenue is recognized when all of the following criteria are met: (1) persuasive evidence of an arrangement exists, (2) delivery has occurred or services have been rendered, (3) the seller’s price to the buyer is fixed or determinable, and (4) collectability is reasonably assured. In the case of coal that is mined and sold, a specific sales contract is negotiated with each customer, which includes a fixed-price per ton, a delivery schedule, and terms of payment.
 
Royalty Expense
 
The majority of the coal that the Company mines is owned by other entities. The Company acquires the right to mine and sell the coal through various leases. These leases require the Company to pay a royalty to the owners of the land and the minerals being mined. Royalty expense for the nine months ended September 30, 2009 and for the years ended December 31, 2008 and 2007 was $2,688,647, $3,778,642, and $3,386,015, respectively, and is included in selling expenses in the statements of operations and comprehensive loss.
 
Income Taxes
 
The Company files consolidated federal and state income tax returns with the Parent. Income tax expense for purposes of these combined financial statements is calculated on a separate return basis. Deferred income taxes are recorded by applying statutory tax rates in effect at the date of the balance sheet to differences between the book and tax basis of assets and liabilities. Due to the significantly large tax losses generated by the Company, management has recorded a valuation allowance against its total net deferred tax assets as they do not believe it is more-likely-than-not that these assets will be realized. The Company’s income tax expense for the nine months ended September 30, 2009, and the years ended December 31, 2008 and 2007, consisted of state taxes.


F-63


Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
1.   Nature of Operations and Significant Accounting Policies — (Continued)
 
Share-Based Compensation
 
The Parent uses the fair value method for options, warrants, and restricted stock granted. The fair value of stock options and warrants is determined by the Black-Scholes option pricing model with assumptions for risk-free interest rates, dividend yields, volatility factors of the expected market price of the Parent’s common shares and an expected life of the options and warrants. The fair value of the instruments granted is amortized over their vesting period. The share-based compensation expense recorded in these carved-out financial statements has been allocated to the Company based on the employees who have provided services to the Company during the applicable reporting periods and recorded as an expense in the statement of operations. The Parent’s cost of providing these benefits is recorded as a contribution to the Company’s equity.
 
Fair Value and Financial Instruments
 
FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. At September 30, 2009 and December 31, 2008, the fair values of restricted certificates of deposit, trade accounts receivable, trade accounts payable, and accrued liabilities approximated their carrying values because of the short-term nature of these financial instruments. At September 30, 2009, the fair value of the Company’s long-term debt, calculated using the present value of the scheduled debt payments, and using a credit adjusted risk free rate of 8.25%, was $20,843,900, compared to its carrying value at that date of $21,305,458. At December 31, 2008, the fair value of the Company’s long-term debt, calculated using the present value of the scheduled debt payments, and using a credit adjusted risk free rate of 6.75%, was $21,052,500, compared to its carrying value at that date of $21,173,790.
 
New Accounting Standards Issued and Adopted
 
In September 2009, the FASB issued Accounting Standards Update (ASU) 2009-06, Implementation Guidance on Accounting for Uncertainty in Income Taxes and Disclosure Amendments for Nonpublic Entities. ASU 2009-06 amended guidance on certain aspects of FASB ASC 740, Income Taxes, including application to nonpublic entities, as well as application guidance on the accounting for income tax uncertainties for all entities. The amendments are applicable to all entities that apply FASB ASC 740 as well as those that historically had not, such as pass-through and tax-exempt not-for-profit entities. The amendments clarify that an entity’s tax status as a pass-through or tax-exempt not-for-profit entity is a tax position subject to the recognition requirements of FASB ASC 740 and therefore these entities must use the recognition and measurement guidance in FASB ASC 740 when assessing their tax positions. The ASU 2009-06 amendments are effective for interim and annual periods ending after September 15, 2009. The adoption of the ASU 2009-06 amendments for the nine months ended September 30, 2009 did not have a material impact on the Company’s financial statements.
 
For the financial statements for the September 30, 2009 reporting period, the Company adopted amendments to FASB ASC 805, Business Combinations (SFAS No. 141R, Business Combinations), issued by the FASB in December 2007. The FASB ASC 805 amendments apply to all business combinations and establish guidance for recognizing and measuring identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100% ownership in the acquiree. The FASB ASC 805 amendments also require expensing restructuring and acquisition-related costs as incurred and establish disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. Per FASB ASC 805-10-65-1, these amendments to FASB ASC 805 are effective for business combinations with an acquisition date in fiscal years beginning after


F-64


Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
1.   Nature of Operations and Significant Accounting Policies — (Continued)
 
December 15, 2008. The Company did not complete any business acquisitions during the nine months ended September 30, 2009.
 
For the financial statements for the September 30, 2009 reporting period, the Company adopted amendments to FASB ASC 855, Subsequent Events (SFAS No. 165, Subsequent Events), issued by the FASB in May 2009. The amendments to FASB ASC 855 establish the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The amendments to FASB ASC 855 also require disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. The Company evaluated subsequent events after the balance sheet date of September 30, 2009 through December 18, 2009.
 
New Accounting Standards Issued and Not Yet Adopted
 
In August 2009, the FASB issued ASU 2009-05, Measuring Liabilities at Fair Value. The ASU 2009-05 amendments provide additional guidance on measuring the fair value of liabilities, as well as outline alternative valuation methods and a hierarchy for their use. The amendments also clarify that restrictions preventing the transfer of a liability should not be considered as a separate input or adjustment in the measurement of its fair value. The ASU 2006-05 amendments are effective as of the beginning of interim and annual reporting periods that begin after August 26, 2009. The Company does not anticipate these requirements will have a material impact on its financial statements.
 
2.   Preparation of Carved-Out Financial Statements
 
The following allocation policies have been used in the preparation of these carved-out financial statements. Unless otherwise noted, these policies have been consistently applied in the financial statements. In the opinion of management, the methods for allocating these costs are reasonable. It is not practicable to estimate the costs that would have been incurred by the Company if it had been operated on a stand-alone basis.
 
Specifically Identified Expenses
 
Costs related specifically to the Company have been identified and included in the statements of operations and comprehensive loss. These expenses include labor and benefits, mining supplies, equipment maintenance and reclamation costs. In addition, any costs incurred by the Parent which were specifically identifiable to a surface mining operation have been charged to the Company.
 
Shared Operating Expenses
 
Historically, the Company has not allocated corporate general and administrative services to each operating division. These shared services included executive management, accounting, information services, engineering, and human resources. For the purposes of these carved-out financial statements, these costs have been allocated to the Company based primarily on a percentage of revenue.
 
Debt and Related Interest Expense
 
The Parent has funded the acquisition and operating activities of the Company, as well as its other operations, through equity offerings (including private placement, preferred stock offerings, and public stock offerings) and bank and finance company debt. Funds used by the Parent for acquisition of the Company have been recorded by the Parent as an investment in the Company. Funds subsequently provided to, or received


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Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
2.   Preparation of Carved-Out Financial Statements — (Continued)
 
from, the Company after the initial acquisition of its assets have been recorded by the Parent in an “intercompany account balance.”
 
Historically, the Parent has not charged or credited the Company for interest on funds provided to, or received from the Company. For the purpose of these carved-out financial statements, interest expense has been computed on the average intercompany account balance at the Parent’s consolidated average borrowing rate and included in the Company’s statements of operations and comprehensive loss. The intercompany balance has been contributed by the Parent to the Company at the end of each year and therefore has been included in the statement of group equity. Average borrowing rates utilized in this calculation were 6.9%, 8.4%, and 11.7% for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007, respectively.
 
Beginning in September 2007, the Company began executing debt agreements directly with equipment finance companies. Interest expense related to equipment financed debt has also been included in the carved-out statements.
 
3.   Acquisitions
 
C&R Coal Inc.
 
In July 2008, the Parent, through one of its surface mining subsidiaries, purchased all of the outstanding common shares of C&R Coal Inc. (C&R) for cash consideration of $2,051,000. In addition, under the terms of the agreement, the Company will pay the former owners a royalty of $0.60 per ton for each ton of coal sold from the C&R mines. At the acquisition date, the current mining area, Beech Creek and Beech Creek South, contained approximately 450,000 reserve tons. The Company also acquired other leases in the transaction from C&R and R&G Leasing, LLC, a company that is affiliated with C&R through common ownership. At the acquisition date, the Company estimated the leases contained approximately 1,500,000 tons of coal.
 
The cost of the C&R acquisition was allocated to the following identifiable net assets:
 
         
Current assets and restricted certificates of deposit
  $ 1,281,000  
Mining equipment
    859,000  
Mining rights and mine development costs
    2,387,000  
Assumed liabilities
    (2,476,000 )
         
    $ 2,051,000  
         
 
Prior to July 2008, the Parent operated and managed C&R’s mines under a management and administrative services agreement. Since the Parent did not own nor control C&R, it did not consolidate its operating results prior to July 2008, and recorded funds invested and services provided in other assets and accounts receivable on its balance sheet.
 
Renfro Equipment, Inc.
 
In July 2008, the Parent, on behalf of the Company, purchased all of the outstanding common shares of Renfro Equipment, Inc. (Renfro) for total cash consideration of $1,129,000. Additionally, the Parent incurred $18,000 of closing costs. The purchase included all assets and liabilities of Renfro, except certain equipment and associated debt specifically excluded from the purchase. Based on exploration completed by the Parent, management estimated that Renfro controlled approximately 1.5 million tons of coal via lease at acquisition date. Additionally, if by July 2010, the Company acquires at least 1.5 million reserve tons as defined by Canadian Securities Administrators’ National Instrument 43-101 due to the direct efforts of the sellers (the


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Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
3.   Acquisitions — (Continued)
 
Additional Reserves), the Company will pay the sellers $1,000,000 for the first 1.5 million tons of reserves, plus $0.50 per ton for each reserve ton in excess of 1.5 million. The purchase agreement defines a specific territory from which the Additional Reserves can be acquired. The acquisition of the Additional Reserves is on terms and conditions acceptable to the Company in its sole, reasonable discretion.
 
The cost of the Renfro acquisition was allocated to the following identifiable net assets:
 
         
Current assets and restricted certificates of deposit
  $ 334,000  
Mining equipment
    429,000  
Mining rights and mine development costs
    1,770,000  
Assumed liabilities
    (1,386,000 )
         
    $ 1,147,000  
         
 
Charolais Corporation
 
In January 2007, the Parent acquired assets and shares of the Charolais Corporation and related entities. The purchase price paid to the seller was $21,735,000. In addition, the Parent incurred $189,000 of transaction costs related to the purchase for total consideration of $21,924,000. Included in the Charolais acquisition was the purchase of the Rock Crusher Fines (RCF) operation, which was not purchased on behalf of the Company. The RCF operation is not included in these carved-out financial statements as it was a fine coal recovery operation and all assets utilized at RCF were sold in 2007 and not included in the Company’s operations. The portion of the Charolais purchase price attributed to the RCF operation was $6,844,000.
 
The purchase price was allocated as follows:
 
                 
    Total
    Charolais
 
    Charolais
    Acquisition
 
    Acquisition
    Allocation
 
    Allocation     Excluding RCF  
 
Real property
  $ 557,000     $ 557,000  
Plant and equipment
    13,483,000       7,939,000  
Mining rights and mineral reserves
    8,705,000       7,405,000  
Asset retirement obligations
    (821,000 )     (821,000 )
                 
    $ 21,924,000     $ 15,080,000  
                 


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Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
4.   Property, Plant, and Equipment, Net
 
Property, plant, and equipment consists of the following at September 30, 2009 and December 31, 2008:
 
                 
    September 30,
    December 31,
 
    2009     2008  
 
Land
  $ 636,154     $ 599,654  
Building and improvements
    480,885       25,424  
Preparation plant
    3,683,996       3,084,768  
Mining equipment
    52,483,183       45,886,694  
Loading and marine transport equipment
    1,775,000       1,775,000  
Office equipment
    355,557       370,450  
Vehicles
    65,965       65,965  
                 
      59,480,740       51,807,955  
Less accumulated depreciation and amortization
    10,904,663       6,644,971  
                 
    $ 48,576,077     $ 45,162,984  
                 
 
In 2008 and 2007, the Company sold several pieces of noncore property and equipment, generating gross proceeds of $683,912 and $1,582,346, respectively. The Company recorded a loss of $1,012,779 related to these sales in 2008, and a gain of $742,086 in 2007. There were no significant sales of property and equipment for the nine months ended September 30, 2009.
 
5.   Asset Retirement Obligations
 
The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted risk-free rate, which ranged from 6.12% to 7.64% at September 30, 2009 and December 31, 2008. Total estimated undiscounted future cash spending related to the ARO liabilities totaled $4,900,000 at September 30, 2009 with spending estimated to occur from 2009 to 2016. Total estimated undiscounted future cash spending related to the ARO liabilities totaled $5,142,000 at December 31, 2008. The Company records an ARO asset associated with the discounted liability for final reclamation and mine closure as a mine development cost. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized on the units-of-production method over its expected life and the ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted risk-free rate. The Company also recognizes an obligation for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement, and revegetation of backfilled pit areas.


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Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
5.   Asset Retirement Obligations — (Continued)
 
A progression of the reclamation liability recorded on the balance sheet is as follows:
 
                 
    Nine Months
       
    Ended
    Year Ended
 
    September 30,
    December 31,
 
    2009     2008  
 
Balance at beginning of period
  $ 4,324,000     $ 3,757,353  
Liabilities acquired
          1,131,000  
Liabilities incurred
    846,295       166,083  
Accretion
    188,719       189,132  
Liabilities settled
    (832,936 )     (919,568 )
                 
Total asset retirement obligation
    4,526,078       4,324,000  
Less current portion
    1,627,800       1,958,000  
                 
    $ 2,898,278     $ 2,366,000  
                 
 
6.   Debt
 
Long-term debt consists of the following at September 30, 2009 and December 31, 2008:
 
                 
    September 30,
    December 31,
 
    2009     2008  
 
Bank notes payable, interest at 5.50% to 8.90%. Payments are made in monthly installments. The loans are collateralized by various pieces of equipment and mature April 2010
  $ 47,643     $ 105,109  
Equipment notes payable, interest at 5.25% to 8.75%. Payments are made in monthly installments. The loans are collateralized by related assets with a net book value of $31,184,000 as of September 30, 2009 and have maturity dates from August 2010 to March 2013
    21,257,815       21,068,681  
                 
Total long-term debt
    21,305,458       21,173,790  
Less current portion
    8,224,486       6,532,045  
                 
    $ 13,080,972     $ 14,641,745  
                 
 
Expected maturities of notes payable based on years ending December 31 are as follows:
 
         
2009 (remaining three months)
  $ 2,013,455  
2010
    8,147,660  
2011
    7,366,999  
2012
    3,604,101  
2013
    173,243  
         
    $ 21,305,458  
         
 
As previously discussed in Note 1, on September 30, 2009, the Parent sold substantially all of its operating assets and operations associated with its surface coal mining operations in western Kentucky to Oxford. In conjunction with the transactions, Oxford paid off all the outstanding debt as of September 30, 2009.


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Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
7.   Income Taxes
 
The components of income tax expense for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007 are:
 
                         
    Nine Months
       
    Ended
  Year Ended
  Year Ended
    September 30,
  December 31,
  December 31,
    2009   2008   2007
 
Current
  $ 16,081     $ 37,838     $ 70,155  
 
The expense for income taxes includes federal and state income taxes currently payable or receivable and those deferred or prepaid because of temporary differences between the financial statement and the tax basis of assets and liabilities. The Company records income taxes under the liability method. Under this method, deferred income taxes are recognized for the estimated deferred tax effects of differences between the tax basis of assets and liabilities and their financial reporting amounts based on enacted laws.
 
At September 30, 2009 and December 31, 2008, the Company had deferred tax assets of approximately $28,862,000 and $20,263,000 and deferred tax liabilities of $12,471,000 and $10,761,000, respectively. The Company’s deferred tax assets consist principally of net operating loss carryforwards, while deferred tax liabilities relate primarily to temporary timing differences for amortization of mining rights and depreciation. As a result of losses from operations, management has recorded a valuation allowance against the total net deferred tax asset as they do not believe it is more-likely-than-not these assets will be realized.
 
8.   Major Customers
 
For the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007 the Company’s concentration of major customers was as follows:
 
                         
    Nine Months
       
    Ended
  Year Ended
  Year Ended
    September 30,
  December 31,
  December 31,
    2009   2008   2007
 
Number of customers whose sales each exceeded 10% of total revenue
    4       3       3  
Percentage of total revenue
    98 %     86 %     83 %
Accounts receivable due at period end
  $ 6,349,485     $ 2,410,395     $ 2,285,240  
 
The Company has never experienced nonpayment from any of these customers. All amounts due from these customers at September 30, 2009 have subsequently been collected.
 
9.   Commitments and Contingent Liabilities
 
In the normal course of business, the Company makes various commitments and incurs certain contingent liabilities, including liabilities related to asset retirement obligations and financial obligations in connection with mining permits that are not reflected in the balance sheet. The Company does not anticipate any material losses as a result of these transactions. In accordance with Kentucky state law, the Company is required to post reclamation bonds to assure that reclamation work is completed. Outstanding reclamation bonds totaled approximately $12 million at September 30, 2009 and approximately $11 million at December 31, 2008. These bonds are secured by letters of credit or certificates of deposit issued by a bank equal to the amount of the outstanding reclamation bonds, and are typically provided by the Parent. However, at December 31, 2008, pending the transfer of certain mining permits related to the C&R and Renfro acquisitions, restricted certificates of deposit totaling $509,825 were held by the Company and included in the balance sheet.


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Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
9.   Commitments and Contingent Liabilities — (Continued)
 
Subsequent to December 31, 2008 these restricted certificates of deposit were replaced by letters of credit provided by the Parent.
 
A significant amount of the Company’s coal reserves are controlled through leasing arrangements and noncancellable royalty lease agreements under which future minimum lease payments are due.
 
In the ordinary course of business, the Company enters into contracts to purchase diesel fuel from local suppliers for physical delivery at specified prices. Pursuant to these contracts, the Company does not own a futures or options position in the purchased fuel. As of September 30, 2009, the Company had executed purchase contracts for a total of 1,890,000 gallons to be delivered in 2009 and 2010 at a total cost of $4,206,048, or an average weighted price of $2.23 per gallon.
 
In 2007, the Company entered into a master coal purchase and sale agreement (the Master Agreement) to purchase coal fines recovered and processed by Covol Fuels No. 2, LLC (Covol) from two coal slurry reserve areas in Muhlenberg County, Kentucky. On July 6, 2009, the Company executed an amendment to the Master Agreement (the Amended Master Agreement) revising the annual purchase and sale tonnage commitments. The term of the Amended Master Agreement runs through the exhaustion of the reserves (the Term). During the Term of the Amended Master Agreement, by July 1 of each year, the Company and Covol will agree to the annual tonnage commitment (the Commitment) that Covol will produce and that the Company will purchase for the next calendar year. For the calendar year 2010 the Commitment cannot be less than 360,000 tons and for subsequent years the Commitment cannot be less than 400,000 tons. Additionally, the Company has the first right of refusal to purchase any tons produced by Covol in excess of the Commitment, but up to 720,000 tons annually.
 
In June 2009, the Company entered into a coal supply agreement with an Illinois Basin producer to purchase 20,000 tons of coal per month from July 2009 through December 2009. Upon mutual agreement of the parties to the coal supply agreement, the term of the agreement may be extended to December 31, 2010. Subsequent to September 30, 2009, this agreement was extended to June 30, 2010.
 
As part of the Renfro Equipment Inc. acquisition in July 2008, the Company agreed that if, by July 31, 2010, it acquires at least 1.5 million reserve tons as defined by Canadian Securities Administrators’ National Instrument 43-101 (NI 43-101) due to the direct efforts of the sellers (Additional Reserves), the Company will pay the sellers $1,000,000 for the first 1.5 million tons of reserves, plus $0.50 per ton for each reserve ton in excess of 1.5 million. The acquisition closing documents define a specific territory from which the Additional Reserves can be acquired. The acquisition of the Additional Reserves must be on terms and conditions acceptable to the Company in its sole, reasonable discretion. As of September 30, 2009, the sellers had provided several mineral leases to the Company. However, the analysis and drilling that is required to qualify these properties as reserve tons under the definition of NI 43-101 is in its early stages. Therefore, it is not yet probable that the sellers will deliver 1.5 million reserve tons to the Company, so no liability has been currently accrued on the balance sheet to the sellers.
 
10.   Stock Incentive Plans
 
PCI adopted a shareholder-approved stock option plan (the 2008 Plan) on May 20, 2008, which became effective in June 2008. PCC had a stock incentive plan authorized by its Board of Directors in 2004 (the 2004 Plan) to grant options to its employees (including officers), directors, and consultants. In June 2008, each stock option issued under the 2004 Plan was cancelled and extinguished and the holder received a replacement option to purchase that number of common shares of PCI equal to the number of PCC common shares that the holder could purchase under the 2004 Plan.


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Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
10.   Stock Incentive Plans — (Continued)
 
The 2008 Plan is designed to advance the interests of the Company by encouraging employees, officers, directors, and consultants to have equity participation in the Parent through the acquisition of common shares. The 2008 Plan has been used to grant options to the Company’s employees, officers, directors, and consultants. Options granted under the 2008 Plan may be “incentive stock options” or “nonqualified stock options.”
 
For options granted under the 2008 Plan, the exercise price per common share is not to be less than the market price of the common shares at the time of the grant. The exercise period for each stock option is not to be more than ten years (five years in the case of an incentive stock option granted to a person who owns more than 10% of the issued and outstanding common shares of the Parent). Options may be granted subject to vesting requirements. Stock options granted under the 2004 Plan were generally subject to vesting provisions of 25% at the end of year one from the date of grant and then evenly over the following 48 months. The options were granted at a price equal to 100% of the fair value of the Company’s common shares on the date of grant and have a ten-year term.
 
Unless terminated earlier by the Parent’s Board of Directors, the 2008 Plan will remain in effect until all options granted under the 2008 Plan have been exercised or forfeited, or have expired. However, no new options may be granted under the 2008 Plan more than ten years from the date the Plan was originally adopted.
 
Compensation cost of stock option grants is recognized straight-line over the options’ vesting periods. Compensation expense related to stock options for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007 was $2,258,869, $4,388,941, and $813,454, respectively. Under the terms of the 2008 Plan, and as approved by the Board of Directors of the Parent, the sale of the surface mining assets to Oxford caused all options outstanding under the 2008 Plan to become fully vested and all remaining unrecognized compensation expense totaling approximately $547,000 was charged to the statement of operations and comprehensive loss in the third quarter 2009.
 
The options’ fair value was determined using the Black-Scholes option-pricing model. Expected volatilities are based on comparable company historical share price movement and other factors. The cost relating to the stock-based compensation plans is included in general and administrative expenses in the accompanying combined statements of operations and comprehensive loss.
 
                         
    2009
  2008
  2007
    Options   Options   Options
 
Weighted-average fair value per share of options granted
  $ 0.08 per share     $ 0.64 per share     $ 0.73 per share  
Assumptions (weighted-average):
                       
Risk free interest rate
    2.75 %     3.98 %     4.37 %
Expected dividend yield
    0.00       0.00       0.00  
Expected volatility
    0.40       0.40       0.40  
Expected option life (in years)
    10.00       10.00       10.00  
 
11.   Sales Contract Termination
 
On March 3, 2009, the Company entered into a mutual release and settlement agreement with one of its customers to terminate a coal supply agreement for delivery of coal in 2009 and 2010 (the 2009/2010 Supply Agreement). In consideration for terminating the 2009/2010 Supply Agreement, the Company paid the customer $3,000,000 in cash. The payment relieved the Company of the obligation to deliver approximately


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Table of Contents

 
Carved-Out Surface Mining Operations of Phoenix Coal Inc.
 
Notes to Combined Financial Statements
September 30, 2009 and December 31, 2008 — (Continued)
 
11.   Sales Contract Termination — (Continued)
 
970,000 tons of coal, 470,000 in 2009 and 500,000 in 2010. In addition, the Company agreed to make up in 2009 approximately 170,000 tons of shipments that were not delivered in 2008 under a separate coal supply agreement dated January 1, 2008 (the 2008 Supply Agreement). In return for fulfilling the 2008 Supply Agreement, the customer agreed to change the guaranteed monthly average BTU specification from 11,500 to 11,200. The $3,000,000 payment has been charged to the statement of operations and comprehensive loss.
 
12.   Defined Contribution Plan
 
The Company has a retirement savings trust plan in effect for substantially all full-time employees. The Plan also contains a deferred salary arrangement under IRC Section 401(k). Under the deferred salary arrangement, employees can contribute up to 100% of their earnings and the Company may match a portion of the employee contributions. The Company paid and charged to operations Plan contributions of approximately $497,000, $621,000, and $508,000 for the nine months ended September 30, 2009 and the years ended December 31, 2008 and 2007, respectively.
 
13.   Related-Party Transactions
 
The Company is wholly owned by the Parent and its subsidiaries. The Parent has allocated certain overhead costs associated with general and administrative services, including executive management, accounting, information services, engineering, and human resources support to the Company. These overhead costs were allocated based primarily on a percentage of revenue, which management believes is reasonable.
 
Historically, interest costs related to intercompany debt have not been charged or credited to the Parent or the Company. For the purpose of these carved-out financial statements, interest expense has been computed on the average intercompany account balance at the Parent’s consolidated average borrowing rate and included in the carved-out statements.
 
Allocated overhead costs and interest expense on intercompany debt included in the statement of operations are as follows:
 
                         
    Nine Months
       
    Ended
  Year Ended
  Year Ended
    September 30,
  December 31,
  December 31,
    2009   2008   2007
 
Overhead costs
  $ 6,947,484     $ 10,362,888     $ 5,170,340  
Interest expense
    1,363,605       755,592       (159,577 )
 
14.   Subsequent Events
 
On November 4, 2009, the Company received a state mining permit from the Kentucky Department of Natural Resources for its Highway 431 reserve. With this permit, the Company has secured all of the necessary permits required to begin mining on the Highway 431 property in Muhlenberg County, Kentucky.


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APPENDIX A
 
Third Amended and Restated Agreement
of Limited Partnership of Oxford Resource Partners, LP
[to come]


A-1


Table of Contents

APPENDIX B
 
Glossary of Terms
 
adjusted operating surplus:  Adjusted operating surplus, with respect to any period, consists of: (i) operating surplus generated with respect to that period; less (ii) 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 (iii) any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus (iv) 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.
 
available cash:  Available cash generally means, for any quarter, the sum of (i) all cash and cash equivalents on hand at the end of the quarter; plus, (ii) 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; less the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to (x) provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future credit needs) subsequent to that quarter; (y) comply with applicable law, any of our debt instruments or other agreements; or (z) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
 
base-load power plants:  The electrical generation facilities used to meet some or all of a given region’s continuous energy demand and produce energy at a constant rate.
 
Btu:  British thermal unit, or Btu, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.
 
capital account:  The capital account maintained for a partner under the partnership agreement. The capital account in respect of a general partner unit, a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that general partner unit, common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Oxford Resource Partners, LP held by a partner.
 
capital surplus:  All amounts of available cash distributed by Oxford Resource Partners, LP on any date from any source will be deemed to be operating surplus until the sum of all amounts of available cash previously distributed to the partners equals operating surplus from the closing date of this offering through the close of the immediately preceding quarter. Any remaining amounts of available cash distributed on such date will be deemed “capital surplus.”
 
closing price:  For common units, the last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, as reported in the principal consolidated transaction reporting system for securities listed on the principal national securities exchange on which the common units are listed. If the common units are not listed on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the common units are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the common units selected by our general partner. If on that day no market maker is making a market in the common units, the fair value of the common units on that day as determined by our general partner.
 
common unit arrearage:  The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.


B-1


Table of Contents

compliance coal:  A coal or a blend of coals that meets sulfur dioxide emission standards for air quality without the need for flue gas desulfurization.
 
current market price:  For any class of units as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.
 
dozer:  A large, powerful tractor having a vertical blade at the front end for moving earth, rocks, etc.
 
GAAP:  Generally accepted accounting principles in the United States.
 
highwall:  The unexcavated face of exposed overburden and coal in a surface mine or in a face or bank on the uphill side of a contour mine excavation.
 
incentive distribution right:  A non-voting limited partner interest initially issued to the general partner. An incentive distribution right will confer upon its holder only the rights and obligations specifically provided in the partnership agreement for incentive distribution rights.
 
incentive distributions:  The distributions of available cash from operating surplus made to holders of the incentive distribution rights.
 
industrial boilers:  Closed vessels that use a fuel source to heat water or generate steam for industrial heating and humidification applications.
 
interim capital transactions:  The following transactions: (i) borrowings that are not working capital 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).
 
limestone:  A rock predominantly composed of the mineral calcite (calcium carbonate (CaCO2)).
 
metallurgical coal:  The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal typically has a particularly high Btu but low ash and sulfur content.
 
operating expenditures:  All of our cash expenditures (or our proportionate share of expenditures in the case of subsidiaries that are not wholly owned), 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 reserve replacement expenditures, maintenance capital expenditures for all other items 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: repayments of working capital borrowings, if such working capital borrowings were outstanding for twelve months, not repaid, but deemed repaid, thus decreasing operating surplus at such time; payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness; expansion capital expenditures; actual reserve replacement expenditures; payment of transaction expenses (including taxes) relating to interim capital transactions; or distributions to partners.
 
operating surplus:  The total of $      million; an amount equal to the amount of accounts receivable that we distributed to our general partner, C&T Coal, AIM Oxford and the participants in our LTIP that hold our common units, immediately prior to the closing of this offering; plus all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions; plus working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for the quarter; cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus cash distributions paid on equity issued by us (including incremental distributions on


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incentive distribution rights) to pay the interest on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less all of our operating expenditures 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.
 
probable (indicated) reserves:  Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
 
proven (measured) reserves:  Reserves for which (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
 
reclamation:  The restoration of mined land to original contour, use or condition.
 
reserve:  That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.
 
scrubbed power plant:  A power plant that uses scrubbers to clean the gases that pass through its smokestacks.
 
scrubbers:  Air pollution control devices that can be used to remove some particulates and chemical compounds from industrial exhaust streams.
 
selective catalytic reduction, or SCR, device:  A means of converting nitrogen oxides, also referred to as NOx, with the aid of a catalyst into diatomic nitrogen, N2, and water, H2O.
 
spoil-piles:  Earth and rock removed from a coal deposit and temporarily stored during excavation.
 
steam coal:  Coal used by power plants and industrial steam boilers to produce electricity, steam or both.
 
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 a date determined by the conflicts committee of the board of directors of our general partner, that each of the following tests are met: (i) 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; (ii) the “adjusted operating surplus” 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; and (iii) there are no arrearages in payment of the minimum quarterly distribution on the common units. Notwithstanding the foregoing, the subordination period shall terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs: (i) distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded 150% of the minimum quarterly distribution for each calendar quarter in the immediately preceding four-quarter period; (ii) the “adjusted operating surplus” generated during each calendar quarter in the immediately preceding four-quarter period equaled or exceeded 150% 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 (iii) there are no arrearages in payment of the minimum quarterly distributions on the common units.
 
tipple:  A structure where coal is cleaned and loaded in railroad cars or trucks.


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total maximum daily load:  A calculation of the maximum amount of a pollutant that a body of water can receive per day and still safely meet water quality standards.
 
units:  Refers to both common units and subordinated units.
 
working capital borrowings:  are generally borrowings that are made after the closings of the transactions described under “Summary — The Transactions” under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months.


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Oxford LOGO
 
Oxford Resource Partners, LP
 
Common Units
 
Representing Limited Partner Interests
 
 
 
 
 
 
 
 
 
 
 
 
Prospectus
     , 2010
 
 
 
 
 
 
 
 
 
 
 
 
Barclays Capital
 
Citi
 
 
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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PART II
 
INFORMATION NOT REQUIRED IN THE PROSPECTUS
 
Item 13.   Other Expenses of Issuance and Distribution.
 
Set forth below are the expenses (other than the underwriting discount) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.
 
         
SEC registration fee
  $ 17,825  
FINRA filing fee
    25,500  
NYSE listing fee
    *  
Printing and engraving expenses
    *  
Fees and expenses of legal counsel
    *  
Accounting fees and expenses
    *  
Transfer agent fees
    *  
Miscellaneous
    *  
         
Total
  $ *  
         
 
 
To be provided by amendment.
 
Item 14.   Indemnification of Directors and Officers.
 
The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the underwriting agreement to be filed as an exhibit to this registration statement, which provides for the indemnification of Oxford Resource Partners, LP and our general partner, their officers and directors, and any person who controls Oxford Resource Partners, LP and our general partner, including indemnification for liabilities under the Securities Act. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever. As of the consummation of this offering, the general partner of the registrant will maintain directors and officers liability insurance for the benefit of its directors and officers.
 
Item 15.   Recent Sales of Unregistered Securities.
 
On August 27, 2007, in connection with the formation of the partnership, we received (1) a contribution of approximately $35.7 million in cash from AIM Oxford in exchange for the issuance of 3,185,000 Class B common units to AIM Oxford, (2) a contribution of approximately $19.2 million in equity in Oxford Mining Company from C&T Coal in exchange for cash and the issuance of 1,715,000 Class B common units to C&T Coal and (3) a contribution of approximately $1.1 million in cash from Oxford Resources GP, LLC in exchange for the issuance to Oxford Resources GP, LLC of 100,000 general partner units and the incentive distribution rights, which rights will become effective upon an initial public offering. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933. The number of units set forth above reflect a 5,000 to 1 units split that was authorized by our general partner on October 23, 2007.
 
On March 27, 2008, we entered into a contribution agreement with Oxford Resources GP, LLC and AIM Oxford. Pursuant to this contribution agreement, we received a contribution of approximately $8.8 million from AIM Oxford as consideration for the issuance to AIM Oxford of 787,500 Class B common units. We also received a contribution of approximately $180,000 from Oxford Resources GP, LLC as consideration for


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the issuance to Oxford Resources GP, LLC of approximately 16,071 general partner units. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.
 
On September 26, 2008, we entered into a contribution agreement with Oxford Resources GP, LLC, C&T Coal and AIM Oxford. Pursuant to this contribution agreement, we received a contribution of approximately $686,000 from C&T Coal and a contribution of $1.3 million from AIM Oxford as consideration for the issuance to C&T Coal and AIM Oxford of 61,250 Class B common units and 113,750 Class B common units, respectively. We also received a contribution of approximately $40,000 from Oxford Resources GP, LLC as consideration for the issuance to Oxford Resources GP, LLC of approximately 3,571 general partner units. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.
 
On August 28, 2009, we entered into a contribution agreement with C&T Coal and AIM Oxford. Pursuant to this contribution agreement, we received a contribution of approximately $1.1 million from C&T Coal and a contribution of approximately $2.0 million from AIM Oxford as consideration for the issuance to C&T Coal and AIM Oxford of 35 deferred participation units and 65 deferred participation units, respectively. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.
 
On September 28, 2009, we entered into a contribution and conversion agreement with Oxford Resources GP, LLC, C&T Coal and AIM Oxford. Pursuant to this contribution and conversion agreement, we received a contribution of approximately $1.5 million from C&T Coal and a contribution of approximately $6.9 million from AIM Oxford as consideration for the issuance to C&T Coal and AIM Oxford of 84,337 Class B common units and 393,575 Class B common units, respectively. We also received a contribution of approximately $231,224 from Oxford Resources GP, LLC as consideration for the issuance to Oxford Resources GP, LLC of approximately 13,266 general partner units. In connection with the execution of this contribution and conversion agreement, C&T Coal and AIM Oxford elected to convert their deferred participation units into approximately 60,241 Class B common units and approximately 111,876 Class B common units, respectively. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.
 
Since our formation in August 2007, we have issued 91,996 Class A common units to our employees upon the vesting of phantom units granted under our Long-Term Incentive Plan. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.
 
Oxford Resources GP, LLC, our general partner, has the right to contribute a proportionate amount of capital to us to maintain its 2.0% interest if we issue additional units. Pursuant to the exercise of this right, on March 22 and 31, 2010, we received contributions of approximately $22,346 and $2,379, respectively, from Oxford Resources GP, LLC as consideration for the issuance to Oxford Resources GP, LLC of approximately 1,282 and 137 general partner units, respectively. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.
 
Item 16.   Exhibits and Financial Statement Schedules.
 
  (a)  The following documents are filed as exhibits to this registration statement:
 
             
Exhibit
       
Number
     
Description
 
  1 .1**     Form of Underwriting Agreement
  3 .1*     Certificate of Limited Partnership of Oxford Resource Partners, LP
  3 .2**     Form of Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP (included as Appendix A to the Prospectus)
  3 .3*     Certificate of Formation of Oxford Resources GP, LLC
  3 .4**     Second Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC
  5 .1**     Opinion of Latham & Watkins LLP as to the legality of the securities being registered
  8 .1**     Opinion of Latham & Watkins LLP relating to tax matters
  10 .1**     Form of Credit Agreement


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Exhibit
       
Number
     
Description
 
  10 .2**     Investors’ Rights Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean
  10 .3**#     Employment Agreement between Oxford Resources GP, LLC and Michael B. Gardner
  10 .4**#     Employment Agreement between Oxford Resources GP, LLC and Jeffrey M. Gutman
  10 .5**#     Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish
  10 .6**#     Employment Agreement between Oxford Resources GP, LLC and Charles C. Ungurean
  10 .7**#     Employment Agreement between Oxford Resources GP, LLC and Thomas T. Ungurean
  10 .8*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Michael B. Gardner
  10 .9*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Jeffrey M. Gutman
  10 .10*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gregory J. Honish
  10 .11*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Denise M. Maksimoski
  10 .12**#     Oxford Resource Partners, LP Long-Term Incentive Plan, as amended
  10 .13**#     Form of Long-Term Incentive Plan Grant Agreement
  10 .14**#     Form of Non-Employee Director Compensation Plan
  10 .15A**#     Form of Non-Employee Director Compensation Plan Grant Agreement
  10 .15B*#     Director Unitholder Agreement, dated December 1, 2009, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gerald A. Tywoniuk
  10 .16*     Acquisition Agreement, dated August 14, 2009, by and among Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal Corporation and Phoenix Newco, LLC
  10 .17A*†     Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation, agent for Columbus Southern Power Company
  10 .17B*†     Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004
  10 .17C*†     Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005
  10 .17D*†     Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated December 5, 2006
  10 .17E*†     Letter Agreement, dated December 5, 2006, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation
  10 .17F*†     Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated December 29, 2008
  10 .17G*†     Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated May 21, 2009
  10 .17H*†     Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated December 15, 2009
  10 .17I*†     Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated January 11, 2010
  10 .17J*†     Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated February 4, 2010
  10 .18**     Non-Compete Agreement by and among Oxford Resource Partners, LP, C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and Oxford Resources GP, LLC
  10 .19*     Administrative and Operational Services Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Mining Company, LLC and Oxford Resources GP, LLC
  21 .1*     List of Subsidiaries of Oxford Resource Partners, LP
  23 .1     Consent of Grant Thornton LLP
  23 .2     Consent of Ernst & Young LLP
  23 .3     Consent of John T. Boyd Company
  23 .4**     Consent of Latham & Watkins LLP (contained in Exhibit 5.1)

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Exhibit
       
Number
     
Description
 
  23 .5**     Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
  24 .1*     Powers of Attorney (included on the signature page)
 
 
* Previously filed.
 
** To be filed by amendment.
 
# Compensatory plan or arrangement.
 
Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.
 
  (b)  Financial Statements Schedules.
 
Item 17.   Undertakings.
 
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and persons controlling the registrant pursuant to the foregoing provisions, the registrant has been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether or not such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.
 
The undersigned registrant hereby undertakes that:
 
(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this registration statement as of the time it was declared effective.
 
(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES
 
Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Amendment No. 2 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Columbus, State of Ohio, on May 17, 2010.
 
OXFORD RESOURCE PARTNERS, LP
 
  By: 
Oxford Resources GP, LLC, its General Partner
 
  By: 
/s/  Jeffrey M. Gutman
Jeffrey M. Gutman
Senior Vice President,
Chief Financial Officer and Treasurer
 
 
Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in their indicated capacities, which are with the general partner of the registrant, on May 17, 2010.
 
         
Signature
 
Title
 
     
*

George E. McCown
  Chairman of the Board
     
*

Charles C. Ungurean
  Director, President and Chief Executive Officer
(principal executive officer)
     
/s/  Jeffrey M. Gutman

Jeffrey M. Gutman
  Senior Vice President, Chief Financial Officer and Treasurer
(principal financial officer)
     
*

Denise M. Maksimoski
  Senior Director of Accounting
(principal accounting officer)
     
*

Brian D. Barlow
  Director
     
*

Matthew P. Carbone
  Director
     
*

Gerald A. Tywoniuk
  Director
         
*By:  
/s/  Jeffrey M. Gutman

Jeffrey M. Gutman
Attorney-in-fact
   


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EXHIBIT INDEX
 
             
Exhibit
       
Number
     
Description
 
  1 .1**     Form of Underwriting Agreement
  3 .1*     Certificate of Limited Partnership of Oxford Resource Partners, LP
  3 .2**     Form of Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP (included as Appendix A to the Prospectus)
  3 .3*     Certificate of Formation of Oxford Resources GP, LLC
  3 .4**     Second Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC
  5 .1**     Opinion of Latham & Watkins LLP as to the legality of the securities being registered
  8 .1**     Opinion of Latham & Watkins LLP relating to tax matters
  10 .1**     Form of Credit Agreement
  10 .2**     Investors’ Rights Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean
  10 .3**#     Employment Agreement between Oxford Resources GP, LLC and Michael B. Gardner
  10 .4**#     Employment Agreement between Oxford Resources GP, LLC and Jeffrey M. Gutman
  10 .5**#     Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish
  10 .6**#     Employment Agreement between Oxford Resources GP, LLC and Charles C. Ungurean
  10 .7**#     Employment Agreement between Oxford Resources GP, LLC and Thomas T. Ungurean
  10 .8*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Michael B. Gardner
  10 .9*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Jeffrey M. Gutman
  10 .10*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gregory J. Honish
  10 .11*#     Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Denise M. Maksimoski
  10 .12**#     Oxford Resource Partners, LP Long-Term Incentive Plan, as amended
  10 .13**#     Form of Long-Term Incentive Plan Grant Agreement
  10 .14**#     Form of Non-Employee Director Compensation Plan
  10 .15A**#     Form of Non-Employee Director Compensation Plan Grant Agreement
  10 .15B*#     Director Unitholder Agreement, dated December 1, 2009, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gerald A. Tywoniuk
  10 .16*     Acquisition Agreement, dated August 14, 2009, by and among Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal Corporation and Phoenix Newco, LLC
  10 .17A*†     Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation, agent for Columbus Southern Power Company
  10 .17B*†     Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004
  10 .17C*†     Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005
  10 .17D*†     Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated December 5, 2006
  10 .17E*†     Letter Agreement, dated December 5, 2006, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation
  10 .17F*†     Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated December 29, 2008
  10 .17G*†     Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated May 21, 2009
  10 .17H*†     Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated December 15, 2009


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Exhibit
       
Number
     
Description
 
  10 .17I*†     Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated January 11, 2010
  10 .17J*†     Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated February 4, 2010
  10 .18**     Non-Compete Agreement by and among Oxford Resource Partners, LP, C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and Oxford Resources GP, LLC
  10 .19*     Administrative and Operational Services Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Mining Company, LLC and Oxford Resources GP, LLC
  21 .1*     List of Subsidiaries of Oxford Resource Partners, LP
  23 .1     Consent of Grant Thornton LLP
  23 .2     Consent of Ernst & Young LLP
  23 .3     Consent of John T. Boyd Company
  23 .4**     Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
  23 .5**     Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
  24 .1*     Powers of Attorney (included on the signature page)
 
 
* Previously filed.
 
** To be filed by amendment.
 
# Compensatory plan or arrangement.
 
Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.


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