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EX-31.2 - EXHIBIT 31.2 - Westmoreland Resource Partners, LPc14224exv31w2.htm
EX-23.1 - EXHIBIT 23.1 - Westmoreland Resource Partners, LPc14224exv23w1.htm
EX-21.1 - EXHIBIT 21.1 - Westmoreland Resource Partners, LPc14224exv21w1.htm
EX-32.1 - EXHIBIT 32.1 - Westmoreland Resource Partners, LPc14224exv32w1.htm
EX-10.22 - EXHIBIT 10.22 - Westmoreland Resource Partners, LPc14224exv10w22.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
COMMISSION FILE NO.: 001-34815
 
OXFORD RESOURCE PARTNERS, LP
(Exact name of registrant as specified in its charter)
 
     
Delaware   77-0695453
(STATE OR OTHER JURISDICTION OF   (IRS EMPLOYER
INCORPORATION OR ORGANIZATION)   IDENTIFICATION NO.)
41 South High Street, Suite 3450, Columbus, Ohio 43215
(Address Of Principal Executive Offices And Zip Code)
(614) 643-0314
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: Common Units representing limited partner interests
     
Title of Each Class   Name of Each Exchange On Which Registered
     
Common Units Representing Limited Partner Interests   New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes þ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes þ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No
As of June 30, 2010, the last business day of the registrant’s second fiscal quarter of 2010, the registrant’s common units were not listed on any exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on July 14, 2010. The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $251,653,000 as of December 31, 2010, based on the reported closing price of the common units as reported on the New York Stock Exchange on such date.
As of March 14, 2011, 10,341,416 common units and 10,280,380 subordinated units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “OXF.”
DOCUMENTS INCORPORATED BY REFERENCE: None
 
 

 

 


 

TABLE OF CONTENTS
         
    Page  
 
       
  ii
 
       
  iv
 
       
PART I
 
       
    1  
 
       
    25  
 
       
    42  
 
       
    43  
 
       
    45  
 
       
    45  
 
       
PART II
 
       
    46  
 
       
    48  
 
       
    52  
 
       
    71  
 
       
    72  
 
       
    72  
 
       
    72  
 
       
    73  
 
       
PART III
 
       
    74  
 
       
    79  
 
       
    93  
 
       
    97  
 
       
    100  
 
       
PART IV
 
       
    101  
 
       
 Exhibit 10.22
 Exhibit 21.1
 Exhibit 23.1
 Exhibit 23.2
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2

 


Table of Contents

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains certain “forward-looking statements.” Statements included in this Annual Report on Form 10-K that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions or other such references, are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecasted in these statements. Any differences could be caused by a number of factors, including but not limited to:
    our production levels, margins earned and level of operating costs;
    weakness in global economic conditions or in our customers’ industries;
    changes in governmental regulation of the mining industry or the electric power industry and the increased costs of complying with those changes;
    decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators;
    our dependence on a limited number of customers;
    our inability to enter into new long-term coal sales contracts at attractive prices and the renewal and other risks associated with our existing long-term coal sales contracts, including risks related to adjustments to price, volume or other terms of those contracts;
    difficulties in collecting our receivables because of credit or financial problems of major customers, and customer bankruptcies, cancellations or breaches of existing contracts, or other failures to perform;
    our ability to acquire additional coal reserves;
    our ability to respond to increased competition within the coal industry;
    fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those pertaining to carbon dioxide emissions, and other factors;
    significant costs imposed on our mining operations by extensive and frequently changing environmental laws and regulations, and greater than expected environmental regulation, costs and liabilities;
    legislation, and regulatory and related judicial decisions and interpretations, including issues pertaining to climate change and miner health and safety;
    a variety of operational, geologic, permitting, labor and weather-related factors, including those pertaining to both our mining operations and our underground coal reserves that we do not operate;
    limitations in the cash distributions we receive from our majority-owned subsidiary, Harrison Resources, LLC, and the ability of Harrison Resources to acquire additional reserves on economical terms from CONSOL Energy Inc. in the future;

 

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    the potential for inaccuracies in our estimates of our coal reserves, which could result in lower than expected revenues or higher than expected costs;
    the accuracy of the assumptions underlying our reclamation and mine closure obligations;
    liquidity constraints, including those resulting from the cost or unavailability of financing due to current capital markets conditions;
    risks associated with major mine-related accidents;
    results of litigation, including claims not yet asserted;
    our ability to attract and retain key management personnel;
    greater than expected shortage of skilled labor;
    our ability to maintain satisfactory relations with our employees; and
    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.
When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report on Form 10-K as well as other written and oral statements made or incorporated by reference from time to time by us in other reports and filings with the Securities and Exchange Commission, or the SEC. All forward-looking statements included in this Annual Report on Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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Glossary of Selected Mining Terms
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.
base-load scrubbed power plants: Base-load power plants that are scrubbed power plants.
Btu: British thermal unit, or Btu, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.
dozer: A large, powerful tractor having a vertical blade at the front end for moving earth, rocks, etc.
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.
industrial boilers: Closed vessels that use a fuel source to heat water or generate steam for industrial heating and humidification applications.
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.
probable coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven coal 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 coal reserves, is high enough to assume continuity between points of observation.
proven coal reserves: Coal 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 coal reserves are well-established.
proven and probable coal reserves: Coal reserves which are a combination of proven coal reserves and probable coal reserves.
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.

 

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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.
strip ratio: In open pit mining, strip ratio refers to the number of tons of overburden or waste that must be removed to extract one ton of coal.
tipple: A structure where coal is cleaned and loaded in railroad cars or trucks.
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.

 


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PART I
ITEM 1.   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 currently have 21 active surface mines, two of which became active mines in 2011, that are managed as eight mining complexes. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During 2010, we produced 7.5 million tons of coal. During 2010, we sold 8.1 million tons of coal, including 0.7 million tons of purchased coal. As a result, our coal inventory on hand increased by approximately 0.1 million tons. As is customary in the coal industry, we have entered into long-term coal sales contracts with many of our customers. We define long-term coal sales contracts as coal sales contracts having initial terms of one year or more.
As of December 31, 2010, we owned and/or controlled 93.5 million tons of proven and probable coal reserves, of which 68.1 million tons were associated with our surface mining operations and the remaining 25.4 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. In 2010, we acquired 8.7 million tons of proven and probable coal reserves, an amount equal to 109% of our 2010 production.
The following table summarizes our mining complexes, our coal production for the year ended December 31, 2010 and our coal reserves as of December 31, 2010:
                                                     
            As of December 31, 2010
    Production for     Total                     Average     Average      
    the Year Ended     Proven &                     Heat     Sulfur     Primary
    December 31,     Probable     Proven     Probable     Value     Content     Transportation
Mining Complexes   2010     Reserves(1)     Reserves(1)     Reserves(1)     (BTU/lb.)     (%)     Methods
    (in million tons)                      
Surface Mining Operations:
                                                   
Northern Appalachia - (principally Ohio)
                                                   
Cadiz (2)
    1.4       10.9       10.9             11,500       3.4     Barge, Rail
Tuscarawas County (2)
    0.9       7.6       7.6             11,670       3.9     Truck
Plainfield
    0.3       6.4       6.4             11,460       4.4     Truck
Belmont County
    1.1       6.2       5.9       0.3       11,620       3.8     Barge
New Lexington
    0.6       5.7       5.4       0.3       11,550       3.9     Rail
Harrison(3)
    1.0       5.1       4.9       0.2       12,000       1.8     Barge, Rail, Truck
Noble County
    0.5       2.7       2.7             11,200       4.7     Barge, Truck
Illinois Basin (Kentucky)
                                                 
Muhlenberg County
    1.7       23.5       22.8       0.7       11,309       3.6     Barge, Truck
 
                                           
Total Surface Mining Operations
    7.5       68.1       66.6       1.5                      
 
                                           
 
                                                   
Underground Coal Reserves:
                                                   
Northern Appalachia (Ohio)
                                                   
Tusky(4)
            25.4       20.0       5.4       12,910       2.1      
 
                                             
Total Underground Coal Reserves
            25.4       20.0       5.4                      
 
                                             
 
                                                   
Total
            93.5       86.6       6.9                      
 
                                             
 
     
(1)   Reported as recoverable coal reserves, which is the portion of the coal that could be economically produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield.
 
(2)   One additional mine became active within each of these complexes in 2011.

 

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(3)   The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL Energy. We own 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% 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, 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 100.0% of Harrison Resources. Please read “— Mining Operations — Northern Appalachia — Harrison Mining Complex.”
 
(4)   Please read “— Mining Operations — 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 are a Delaware limited partnership that is listed on the New York Stock Exchange, or NYSE, under the ticker symbol “OXF.” On July 19, 2010, we closed our initial public offering of common units. After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, our offering expenses of approximately $6.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $144.5 million.
We were formed in August 2007 by American Infrastructure MLP Fund, L.P., or AIM, and C&T Coal, Inc., or C&T Coal. AIM is a private investment firm specializing in natural resources, infrastructure and real property. AIM, along with certain of the funds that AIM advises, indirectly owns all of the ownership interests in AIM Oxford Holdings, LLC, or AIM Oxford, the entity it used to form us in 2007. 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. C&T Coal is owned by 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 38 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 and 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.
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.
Industry Overview
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. The U.S. Department of Energy’s Energy Information Administration, or the EIA, forecasts that coal-fired electric power generation will increase by 13.0% through 2015 and by 27.0% through 2035, with steam coal remaining the dominant fuel source in the future.
Coal Quality Characteristics
Coal quality is primarily differentiated by its heat and sulfur content. Heat content is measured in Btu 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.
Sulfur content is measured in pounds of sulfur dioxide emitted per million Btu of fuel combusted. When coal is burned, sulfur dioxide and other air emissions are released. Compliance coal is a term generally used in the United States to describe coal or a blend of coals that, when burned, emits less than 1.2 lbs of sulfur dioxide per million Btu and complies with the requirements of the Clean Air Act Amendments of 1990, or the CAAA, without the use of scrubbers. The primary reserves of compliance coal are found in both the Powder River Basin, or PRB, and Central Appalachia.

 

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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. 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. As with sulfur, coal of various ash contents can be blended to meet the specific combustion and environmental needs of customers.
Coal Mining Methods
Coal is mined using two primary methods, surface mining and underground 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 generally 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. Surface mining methods generally encompass highwall and auger mining methods. After a final highwall is established by other surface mining methods, a highwall miner or auger is used to recover additional reserves from the coal seam in place without additional overburden removal. A highwall miner is similar to a continuous miner used in underground mining connected to a conveyor system to remove coal as the highwall miner advances into the coal seam underground from the open highwall face. Underground mining is generally used when the coal seam is too deep to permit surface mining.
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 bears the freight costs, 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 may be 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 customer.
Overview of U.S. Market
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. In 2009, coal-fired power plants produced approximately 45.0% of all electric power generation and steam coal accounted for 92.0% of total coal consumption.
Short-Term Outlook
The EIA forecasts that domestic coal consumption will increase by 14.4% through 2015 and coal-fired electric power generation will increase by 13.0% through 2015. 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. 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 of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. Additional increases in demand are also projected in connection with new coal-to-liquids plants and carbon capture and sequestration, or CCS, technology.

 

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U.S. exports will also continue to increase, supported by recovering global economies and continued rapid growth in electric power generation and steel production.
Increasingly stringent air quality legislation will continue to impact the demand for coal. A series of more stringent requirements 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.
Mining Operations
We currently have 21 active surface mines, two of which became active mines in 2011, 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 eleven 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. For our auger mining operations, we own and operate seven augers and move them among our mining complexes as necessary. For our highwall mining operations, we own and operate two Superior highwall miners and also move them 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. We also deploy a fleet of over 75 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 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, 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 20 empty barges. We control our Bellaire river terminal through a long-term lease agreement with a third party. In May 2010, we signed a new five-year lease, effective January 1, 2010, with three subsequent five-year renewal terms at our option for a total of up to 20 years. 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 1,300 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 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 and transloading facility on the Green River in western Kentucky;
    our Stonecreek coal crushing facility located in Tuscarawas County, Ohio; and
    our Schoate wash plant located in Muhlenberg County, Kentucky.

 

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The following map shows the locations of our Northern Appalachia mining operations and coal reserves and related transportation infrastructure.
(MAP)

 

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The following map shows the locations of our Illinois Basin mining operations and coal reserves and related transportation infrastructure.
(MAP)

 

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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, 2010, our mining complexes in Northern Appalachia produced an aggregate of 5.8 million tons of steam coal. The following table provides summary information regarding our mining complexes in Northern Appalachia as of December 31, 2010 and for the years indicated:
                                             
                        Tons Produced for the  
    Transportation Facilities       Number     Years Ended  
    Utilized   Transportation   of Active     December 31,  
Mining Complex   River Terminal   Rail Loadout   Method(1)   Mines     2010     2009     2008  
                        (in millions)  
Cadiz (2)
  Bellaire   Cadiz   Barge, Rail     3       1.4       1.1       1.4  
Tuscarawas County (2)
      Truck     5       0.9       0.9       1.0  
Plainfield
      Truck     1       0.3       0.5       0.5  
Belmont County
  Bellaire     Barge     4       1.1       1.3       0.9  
New Lexington
    New Lexington   Rail     1       0.6       0.6       0.7  
Harrison(3)
  Bellaire   Cadiz   Barge, Rail, Truck     1       1.0       0.7       0.4  
Noble County
  Bellaire     Barge, Truck     2       0.5       0.3       0.2  
 
                                   
Total
                17       5.8       5.4       5.1  
 
                                   
 
     
(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)   We added two new mines since December 31, 2010 which are not reflected in the table above, one at our Cadiz Complex and another at our Tuscarawas Complex.
 
(3)   The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL Energy. We own 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% of Harrison Resources indirectly through one of its subsidiaries. Because the results of operations of Harrison Resources are included in our consolidated financial statements for each December 31 year end as required by GAAP, coal production attributable to the Harrison mining complex is presented on a gross basis assuming we owned 100.0% of Harrison Resources. Please read “— Harrison Mining Complex.”
Cadiz Mining Complex. The Cadiz mining complex is located principally in Harrison County, Ohio and includes reserves located in Jefferson County, Ohio and Washington County, Pennsylvania. It consists of the Daron, Elk Run 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, 2010, the Cadiz mining complex included 10.9 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 1.4 million tons of coal for the year ended December 31, 2010.
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, Lisbon 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, 2010, the Tuscarawas County mining complex included 7.6 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes three 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 of coal for the year ended December 31, 2010.

 

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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, 2010, 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. 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 the customer. Coal trucked to our Barb Tipple facility is transported by truck to the customer 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 0.3 million tons of coal for the year ended December 31, 2010.
Belmont County Mining Complex. The Belmont County mining complex is located in Belmont County, Ohio, and consists of the Lafferty, Flushing, Jeffco 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, 2010, the Belmont County mining complex included 6.2 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 1.1 million tons of coal for the year ended December 31, 2010.
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, Middle Kittanning #6 and Pittsburgh #8 coal seams. As of December 31, 2010, the New Lexington mining complex included 5.7 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 of coal for the year ended December 31, 2010.
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 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% of Harrison Resources 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, 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 100.0% of Harrison Resources.
Since its formation in 2007, Harrison Resources has acquired 6.9 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 have no assurance that Harrison Resources will be able to 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, 2010, the Harrison mining complex included 5.1 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 the customer. 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 1.0 million tons of coal for the year ended December 31, 2010.
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, 2010, the Noble County mining complex included 2.7 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 0.5 million tons of coal for the year ended December 31, 2010.

 

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Illinois Basin
We operate one surface mining complex in the Illinois Basin, which is located in western Kentucky. For the year ended December 31, 2010, this mining complex produced an aggregate of 1.7 million tons of steam coal. The following table provides summary information regarding our mining complex in the Illinois Basin as of December 31, 2010 and for the year then ended:
                                 
                            Tons Produced for  
    Transportation                 the Year Ended  
    Facilities Utilized                 December 31,  
    River   Rail     Transportation   Number of     2010  
Mining Complex   Terminal   Loadout     Method(1)   Active Mines     (in millions)  
Muhlenberg County
  Island         Barge, Truck     4       1.7  
 
     
(1)   Barge means transported by truck to our Island river terminal and then transported to the customer by barge. Truck means transported to the customer by truck.
Muhlenberg County Mining Complex. The Muhlenberg County mining complex is located in Muhlenberg and McClean Counties, in western Kentucky, and consists of the Schoate, Highway 431, KO and Rose France 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, 2010, the Muhlenberg County mining complex included 23.5 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes the Schoate wash plant, the KO coal crusher, the Rose France coal crusher 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. Some of the production from this mining complex is washed at our Schoate wash plant prior to being transported 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 1.7 million tons of steam coal during the year ended December 31, 2010.
Underground Coal Reserves
We began our underground mining operation at the Tusky mining complex in late 2003 after leasing our underground coal reserves from a third party in exchange for a royalty based on tonnage sold. 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 almost 15 years remaining on the lease for our underground coal reserves, and our sublessee has almost 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 December 31, 2010, we had approximately $34.9 million in surety bonds and $14,000 in cash bonds outstanding to secure the performance of our reclamation obligations. Additionally, as of December 31, 2010, our surety bonds were supported by approximately $6.7 million in letters of credit. In 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 perform reclamation activities on a continuous basis as our mining activities progress.

 

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Over 84% of our active surface mining permits are associated with coal reserves that were mined by other coal producers prior to the implementation of the Surface Mining Control & Reclamation Act of 1977, or 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 pre-SMCRA 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 Acid Mine Drainage, or AMD. We have seven mining permits that are identified on Ohio’s Inventory of Long-Term AMD sites. Only one of these sites, associated with the Strasburg wash plant, requires continuous AMD treatment, for which we have estimated the present value of the projected annual treatment cost at approximately $85,000 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. Two sites on the AMD Inventory List have 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 recommended for removal from the AMD Inventory List will receive final surety bond release in 2011.
Limestone
At our Daron and Strasburg mines, 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, 2010 include $1.5 million in limestone sales.
During 2010, we produced 0.4 million tons of limestone. Based on estimates from our internal engineers, our Cadiz mining complex has 7.4 million tons of proven and probable limestone reserves as of December 31, 2010. 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 2010, we generated $2.2 million of revenue from a variety of services we performed in connection with our surface mining operations. This revenue included the following:
    service fees we earned 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 earned for providing earth-moving services for Tunnel Hill Partners, LP, an entity owned by our sponsors that owns a landfill; and
    service fees we earned for hauling and disposing of ash at a third party landfill for two municipal utilities.
For more information regarding our relationships and our sponsors’ relationships with Tunnel Hill Partners, LP, please read “Certain Relationships and Related Transactions, and Director Independence.”
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, 2010, we derived 76.3% of our revenues from coal sales to electric utilities (including sales through brokers), 15.7% from coal sales to municipalities and cooperatives, 5.8% from coal sales to industrial customers and the remaining 2.2% from a mixture of sales of non-coal material such as limestone, royalty payments on our underground coal reserves and fees for services we performed for third parties.

 

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Long-Term Coal Sales Contracts
For the past three years over 90.0% 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 or cost adjustment provisions.
During 2010, we executed over $275 million in long-term coal sales contracts primarily having an effect on sales beginning in 2012. These contracts, the majority of which were related to our Illinois Basin operations, were executed at prices significantly higher than current levels. For 2011, 2012, 2013 and 2014, we currently have long-term coal sales contracts that represent 100%, 78%, 52% and 47%, respectively, of our 2011 estimated coal sales of 9.1 million tons. Two of our long-term coal sales contracts with the same customer contain provisions that provide for price re-openers. These price re-openers provide for market-based adjustments to the initial contract price every three years. These long-term coal sales contracts will terminate in 2013 if we cannot agree upon a market-based price with the customer prior to the termination date. In addition, we have one long-term coal sales contract with another customer that will terminate in 2014 if we cannot agree upon a market-based price with the customer prior to the termination date. The coal tonnage which is involved for these two customers through 2014 is 1.0 million tons annually for 2013 and 2014 and 0.4 million tons annually for 2014, respectively.
The current term of our long-term coal sales contract with American Electric Power Service Corporation, or AEP, runs through 2012 but it can be extended for two additional three-year terms if AEP gives us six months advance notice of its election to extend the contract. For each extension term, we will negotiate with AEP to agree upon a market-based price based on similar term contracts. In addition, the contract contains substantial cost pass through and cost adjustment provisions. If AEP elects to extend this contract, we will be committed to deliver an additional 2.0 million tons in 2013 and 2014, and our 2013 and 2014 coal sales under long-term coal sales contracts, as a percentage of 2011 estimated coal sales, would increase to 74% and 69%, respectively. We are currently in negotiations with AEP to extend our contract with them. The mutual goal of the parties is to amend the contract to fix the term to run through 2018, establish future pricing that is acceptable to both parties and adjust the amounts of fixed and optional coal tonnage covered by the contract. While the outcome of these negotiations is not certain at this time, we believe that we will be able to achieve an extension that is on amended terms which are beneficial to us and that furthers our long-term coal sales contract strategy.
The terms of our coal sales contracts result from competitive bidding and negotiations with customers. As a result, the terms of these contracts vary by customer. However, most of our long-term coal sales contracts have full or partial cost pass through provisions or cost adjustment provisions. For 2011, 2012, 2013 and 2014, 81%, 96%, 100% and 91% of the coal, respectively, that we have committed to deliver under our current long-term coal sales contracts are subject to full or partial cost pass through provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for such items as fuel, explosives and/or labor. Cost 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 cost-related indices.
A long-term coal sales contract may contain option provisions that give the customer the right to elect to purchase additional tons of coal each month during the contract term at a fixed price provided for in the contract. For example, upon 30 days advance notice, AEP may elect to purchase, at the contract price in effect at the time for all other tons, an additional 25,000 tons of coal each month under its long-term coal sales contract with us and, in addition, upon 90 days notice, it may elect to purchase, at the contract price in effect at the time for all other tons, an additional 200,000 tons of coal per half year. Our long-term coal sales contracts that provide for these option tons typically require the customer to provide us with from one to three months advance notice of an election to take these option tons. Because the price of these option tons is fixed at the contract price in effect at the time for all other tons under the terms of the contract, if our contract price is below market, we could be obligated to deliver additional coal to those customers at a price that is below the market price for coal on the date the option is exercised. For 2011, 2012, 2013 and 2014, we have outstanding option tons of 0.7 million, 0.9 million, 0.9 million and 1.2 million, respectively. If the customer does elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes.

 

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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 contracts. 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 the customer’s ability to receive coal deliveries.
Customer Concentration
We derived 92.0% of our total revenues from coal sales to our ten largest customers for the year ended December 31, 2010, with our top five customers accounting for 73.9% of our total revenues. In addition, for the year ended December 31, 2010, we derived 30%, 12%, 11% and 11% of our revenues from AEP, Duke Energy, East Kentucky Power Cooperative and First Energy, respectively.
Transportation
Our coal is delivered to our customers by barge, truck or rail. Over 57% of the coal we shipped during 2010 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 from river terminals, where barges are loaded, to their location. We typically pay for the cost of transporting the coal by rail and/or truck to river terminals, rail loading facilities or directly to our customer’s site(s). However, our sales contracts typically have these transportation costs built into the price, as well as provisions for fuel cost adjustments. For the year ended December 31, 2010, 58%, 40% and 2% 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, 2010, expenses we incurred to obtain goods and services in support of our mining operations were $130 million, 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, 2010, we managed our risk from rising fuel prices through both the use of fixed priced forward contracts that provide for physical delivery and the use of escalation and fuel pass through clauses in agreements with key customers. 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 use bidding processes 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 Resource Partners LP.

 

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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.
Our Safety and Environmental Programs and Procedures
We operate some of the industry’s safest mines. Over the last 5 years, our Mine Safety and Health Administration, or MSHA, reportable incident rate was, on average, 1.9 compared to the national surface mine average of 2.2, or 9.9% lower than the national surface coal mine incident rate. Our safety record can be attributed to our extensive safety program, which includes, among other things, (i) employing two full-time safety professionals, (ii) implementing policies and procedures to protect employees and visitors at our mines, (iii) utilizing experienced third-party blasting professionals to conduct our blasting activities, (iv) requiring a certified surface mine foreman to be in charge of the activities at each mine and (v) ensuring that each employee undergoes the required safety, hazard and task training.
In addition, we remain committed to maintaining a system that seeks to control and reduce the environmental impacts of our mining operations. These controls include, among other things, (i) installing sumps or double walled tanks to contain any spillage of fuel or lubricants at our mines and facilities, (ii) evacuating used oil from equipment and placing it in storage tanks before removing it for proper disposal, (iii) employing four full-time environmental compliance professionals and (iv) utilizing experienced in-house personnel and contractors to conduct extensive pre-mining sampling and studies to comply with environmental laws and regulations.
Mining and Environmental Regulation
Federal, state and local authorities regulate the 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. The current 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 interpretation and enforcement of current laws, regulations or orders, may substantially increase operating costs, result in delays and disrupt operations, the extent and scope 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, which may adversely affect our mining operations or the cost structure or demand for coal.
We endeavor to conduct our mining operations at all times in compliance with all applicable federal, state and local laws and regulations. However, due in part to the complexity and extent of the various regulatory requirements and the nature of coal mining operations, violations can and do occur from time to time.
Mining Permits and Approvals
Numerous federal, state or local governmental permits or approvals are required to conduct coal mining and reclamation operations. The application process can require us 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 human health or the environment. The permitting requirements imposed by governmental authorities are costly and have become subject to more enhanced scrutiny, strict review and judicial challenge, which may delay commencement or continuation of mining operations.
In order to obtain federal and state mining permits and approvals, 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 have become 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 has become increasingly longer and has more often been subject to legal challenge by environmentalists and other advocacy groups, although we are not aware of any such challenges to any of our pending permit applications.

 

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Violations of federal, state and local laws or regulations or any permit or approval issued thereunder can result in substantial fines and penalties, including revocation or suspension of mining permits. In certain circumstances, criminal sanctions can be imposed for knowing and willful failure to comply with these laws, regulations, permits or approvals.
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, each of 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 often 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 permits or authorizations 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, or AVS, 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. In addition, 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 AVS. Thus, non-compliance with SMCRA can provide a basis for denying the issuance of new mining permits or modifications of existing mining permits. We are not permit-blocked and know of no existing circumstances which could reasonably provide such a basis for denial.
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 and regulations, 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.

 

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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 laws and 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 penalties or criminal fines, 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 final rule by June 29, 2012. On April 30, 2010, the OSM published a Notice of Intent to prepare an Environmental Impact Statement for a new rule — to be called the Stream Protection Rule — that will evaluate alternatives for revising surface mining rules to better protect streams. 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 considered legislation to further 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 2010, we recorded $2.2 million of expense in our cost of coal sales related to this fee.
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 reclamation obligations. We use letters of credit to secure the performance of a portion of our reclamation obligations.
As of December 31, 2010, we had approximately $34.9 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $6.7 million in letters of credit. There are no letters of credit outstanding in support of surety bonds issued for the benefit of government agencies.

 

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Mine Safety and Health
Coal mining operations are subject to stringent health and safety standards, including pursuant to the Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977, or the Mine Act. In addition to federal regulatory programs, all of the states in which we operate have 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 violate 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 2006, in response to underground mine accidents, Congress enacted the Mine Improvement and New Emergency Response Act, or MINER Act. The MINER Act imposed additional burdens on coal operators, including (i) emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel, (ii) requirements for mine rescue teams, (iii) prompt notification of federal authorities of incidents that pose a reasonable risk of death and (iv) increased penalties for violations of certain federal laws and regulations. Various states have also increased regulation in many of these areas. In the wake of several underground mine accidents, enforcement scrutiny has also increased, including more inspection hours at mine sites, an increased number of inspections and increased issuance of the number and the severity of enforcement actions. Additional federal and state legislation related to mine safety and health is under consideration. We believe that our compliance with these and other reasonably likely mine health and safety laws and regulations could increase our mining costs.
In 2010, in response to additional underground mine accidents, Congress expanded mine safety disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Act. On December 15, 2010, the SEC issued proposed rules to implement Section 1503 by outlining the way in which mining companies must disclose to investors certain information about mine safety and health standards. In 2010, for each coal mine we operated: the total number of violations of mandatory health or safety standards that could significantly and substantially, or S&S, contribute to the cause and effect of a coal or other mine safety or health hazard under Section 104 of the Mine Act for which we received a citation from MSHA was thirty (30) as shown in the following Table OXF-MSHA-1; the total number of orders issued under Section 104(b) of the Mine Act was zero; the total number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act was zero; the total number of flagrant violations under Section 110(b)(2) of the Mine Act was zero; the total number of imminent danger orders issued under Section 107(a) of the Mine Act was zero; and the total dollar value of the proposed assessments from MSHA under the Mine Act was $19,882. In addition, no coal mine of which we were the operator received written notice from MSHA of a pattern of violations, or the potential to have such a pattern, of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Act. The pending legal actions before the Federal Mine Safety and Health Review Commission are shown in the following Table OXF-MSHA-2.

 

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Table: OXF-MSHA-1
                                                                 
                                            (F)             (H)  
    (A)     (B)     (C)     (D)     (E)     Proposed             Pending  
    Section     Section     Section     Section     Section     Assess-     (G)     Legal  
Mining Complex   104     104(b)     104(d)     110(b)(2)     107(a)     ments     Fatalities     Action  
Cadiz
    3                             $ 1,720             2  
Tuscarawas County
    1                             $ 2,682              
Belmont County
    2                             $ 1,287              
Plainfield
    1                             $ 1,542             1  
New Lexington
    1                             $ 1,268             1  
Harrison
    1                             $ 625              
Noble County
    1                             $ 734              
Muhlenberg County
    20                             $ 10,024              
Totals
    30                             $ 19,882             4  
     
(A)   The total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act (30 U.S.C. 814) for which the operator received a citation from MSHA.
 
(B)   The total number of orders issued under section 104(b) of the Mine Act (30 U.S.C. 814(b)).
 
(C)   The total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act (30 U.S.C. 814(d)).
 
(D)   The total number of flagrant violations under section 110(b)(2) of the Mine Act (30 U.S.C. 820(b)(2)).
 
(E)   The total number of imminent danger orders issued under section 107(a) of the Mine Act (30 U.S.C. 817(a)).
 
(F)   The total dollar value of proposed assessments from MSHA under the Mine Act (30 U.S.C. 801 et seq.). Includes proposed assessments for non-S&S citations and proposed assessments received in 2010 for citations issued in 2009.
 
(G)   The total number of mining-related fatalities.
 
(H)   Any pending legal action before the Federal Mine Safety and Health Review Commission involving such coal or other mine. See Table OXF-MSHA-2, below for information regarding pending legal actions.

 

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Table: OXF-MSHA-2
                         
Docket Number               Proposed      
MSHA Mine Name               Civil      
Oxford Mine Complex/Name   Citation     Date   Penalty      
MSHA ID Number   No.     Issued   Assessment     Status
LAKE 2008-383

Oxford Mining #3
New Lexington/New Lexington

33-04336
    7138351     1/9/2008   $ 1,400     Petition for civil penalty assessment for a miner not wearing a hard hat outside of the operating cab of his equipment. The Petition was served on June 6, 2008 and timely answered on July 3, 2008. The Commission recently issued a Notice of Hearing for April 26, 2011. Oxford’s prehearing report is due April 12.
 
                       
LAKE 2009-381-M

Oxford Mining #2
Plainfield/Adamsville*

33-04213

*Adamsville mine — reclaimed
  7141549

7141550
  11/3/2008

11/10/2008
  $

$
460

460
    Petition for civil penalty assessment for two citations regarding brake lights on mobile equipment. The proposed civil penalty assessment became a final order on January 16, 2009, but the notice of contest was mailed to an incorrect address. A Motion to Reopen the Penalty Assessment was filed on March 19, 2009 and unopposed by the Secretary of Labor. The Commission has approved the Motion, and the matter has been assigned to Administrative Law Judge (ALJ) Barbour pending issuance of a Petition for Penalty Assessment.
 
                       
LAKE 2010 -576

Snyder Mine
Cadiz/County Road 29

33-04414
    8017301     8/31/2009   $ 946     Petition for civil penalty assessment for a rock truck operator failing to maintain control of the vehicle and crashing into the highwall; the driver sustained a broken leg. The Petition was served on May 5, 2010 and timely answered on June 7, 2010. The case has been assigned to ALJ Harner. The parties conducted a status conference with the ALJ and have engaged in settlement discussions to no avail. The parties have requested that the ALJ set the matter for a hearing.
 
                       
LAKE 2010-577

Snyder Mine
Cadiz/County Road 29

33-04414
    8024308     2/3/2010   $ 207     Petition for civil penalty assessment for a dump truck that did not give an audible sound when reverse was engaged when tested. The Petition was served on May 6, 2010 and timely answered on June 7, 2010. The case has been assigned to ALJ Harner. The parties conducted a status conference with the ALJ and have engaged in settlement discussions to no avail. The parties have requested that the ALJ set the matter for a hearing.
Black Lung
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 2010, we recorded $3.9 million of expense in our cost of coal sales related to this excise tax. The Patient Protection and Affordable Health Choices Act, or PPAHCA, which was enacted on March 23, 2010, made two potentially significant changes to the federal Black Lung program. First, the PPAHCA provides 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. Second, the PPAHCA establishes 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 changes 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 laws for black lung claims.
Clean Air Act
The Clean Air Act and similar state laws 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 fugitive dust from roadways, parking lots, and equipment such as conveyors and storage piles.

 

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On June 16, 2010, several environmental groups petitioned the U.S. Environmental Protection Agency, or the EPA, to list coal mines as a source of air pollution and establish emissions standards under the Clean Air Act for several pollutants, including particulate matter, nitrogen oxide gases, volatile organic compounds and methane. Petitioners further requested that the EPA regulate other emissions from mining operations, including dust and clouds of nitrogen oxides associated with blasting operations. If the petitioners are successful, emissions of these or other materials associated with our mining operations could become subject to further regulation pursuant to existing laws such as the Clean Air Act. In that event, we may be required to install additional emissions control equipment or take other steps to lower emissions associated with our operations, thereby adversely affecting our results of operations.
The Clean Air Act indirectly affects coal mining operations by extensively regulating air emissions from coal-fired power plants, which are the largest end users of our coal. Coal contains certain impurities, including sulfur, mercury, chlorine and other constituents, many of which are emitted into the air when coal is burned, including emissions of particulate matter, sulfur dioxide (also referred to as SO2), nitrogen oxides (also referred to as NOx), carbon monoxide, ozone, mercury and other compounds emitted by coal-fired power plants. As a result of the regulation of these emissions, coal-fired power plants, which are the largest end users of our coal, have expended considerable resources, and may be required to expend additional resources, to install emission control equipment or take other steps to lower emissions or otherwise achieve compliance. More stringent regulation by the EPA, states or Congress, pursuant to an international treaty or due to a judicial decision, could make it more costly to operate coal-fired power plants. As a result, coal could become a less attractive and less competitive fuel and future demand could decrease. Although we are unable to predict the magnitude of any impact with any reasonable degree of certainty, reduced demand could reduce the price of coal that we mine and sell, thereby reducing our revenues, and thus could have a material adverse effect on our business and the results of our operations.
In addition to the greenhouse gas regulations discussed below, air emission control programs that affect our operations, directly or indirectly, include, but are not limited to, the following:
    Acid Rain. The EPA’s Acid Rain Program, in Title IV of the Clean Air Act, regulates SO2 emissions by coal-fired power plants with a generating capacity greater than 25 megawatts. Affected facilities purchase or are otherwise allocated allowances for SO2 emissions. Affected facilities have reduced SO2 emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading allowances.
    SO2. Pursuant to the Clean Air Act, the EPA sets standards, known as National Ambient Air Quality Standards, or NAAQS, for certain pollutants. On June 3, 2010, the EPA issued a stricter NAAQS for SO2 emissions that established a 1-hour standard at a level of 75 parts per billion or ppb to protect against short-term exposure and minimize health-based risks. The EPA indicated that it would abolish the previous annual standard for SO2. Under the new rule, monitors must be set up by 2013 in the areas of the highest concentrations of SO2. Non-attainment decisions will be made by June 2012, state implementation plans will be due by the winter of 2014 and attainment of the standards must be achieved by the summer of 2018.
    Particulate Matter. Areas that are not in compliance, known 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, if any of the areas in which we operate become designated as non-attainment areas for particulate matter, our mining operations may be directly affected by any related NAAQS.
    Ozone. The EPA’s ozone NAAQS imposes stringent limits on NOx emissions, which are classified as an ozone precursor. 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. The EPA has proposed a stricter NAAQS for ozone, which it expects to finalize in July 2011. Related non-attainment decisions will be made by July 2013, state implementation plans will be due by the end of 2016 and attainment of the standards must be achieved by 2018 or later, depending on the severity of non-attainment.
    NOx SIP Call. The NOx SIP Call program was established by the EPA 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. 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.

 

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    Clean Air Interstate Rule or CAIR. The EPA’s CAIR calls for power plants in 28 eastern states and the District of Columbia to reduce emission levels of SO2 and NOx 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 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. The EPA proposed a replacement rule known as the Clean Air Transport Rule in July 2010 that would set state level caps on SO2 and NOx emissions for power plants for 31 eastern states and the District of Columbia. The final rule is expected in July 2011. Under either CAIR or the Clean Air Transport Rule, some coal-fired power plants may be required to install additional pollution control equipment and burn less high sulfur coal.
    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. The EPA is under a court deadline to issue a final rule by November 2011, and will likely impose stricter limitations on mercury emissions from power plants than the vacated CAMR. In the meantime, case-by-case MACT determinations for mercury may be required for new and reconstructed coal-fired power plants. Mercury emissions from coal-fired power plants may also be subject to state regulation, and related federal legislation has been proposed. In addition, in February 2011, the EPA established new MACT for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. The Obama Administration has also indicated a desire to negotiate an international treaty to reduce mercury pollution.
    Regional Haze. The EPA’s regional haze program seeks to protect and improve visibility at and around national parks, national wilderness areas and international parks. The program may restrict emissions on new coal-fired power plants whose operation may impair visibility at and near such federally protected areas. The program may also require certain existing coal-fired power plants to install additional control measures designed to limit certain haze-causing emissions. On January 19, 2011, several environmental groups notified the EPA that they intend to sue under the citizen suit provision of the Clean Air Act for failure to enforce the regional haze rule.
    New Source Review, or NSR. A number of pending regulatory changes and court actions by the EPA and various environmental groups may affect the scope of the EPA’s NSR program, which, among other emission sources, requires new coal-fired power plants to install emission control equipment and may require existing coal-fired power plants to install additional emission control equipment. 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.
Climate Change
Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide and other greenhouse gases which have been subject to public and regulatory concern with respect to climate change or global warming. Current and future regulation of greenhouse gases may occur on various international, federal, state and local levels, including pursuant to future legislative action, EPA enforcement under the existing Clean Air Act, regional and state laws and initiatives and court orders. The Kyoto Protocol, which expires in 2012, established a set of emission targets for greenhouse gases for ratifying countries. Although it has not ratified the Kyoto Protocol, the United States is participating in international renewal discussions. Any replacement treaty or other international arrangement related to greenhouse gas emissions will have a potentially significant impact on the demand for coal if adopted by the United States.
Congress has actively considered proposals in the past several years 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. Although no bills to reduce such emissions have yet to pass both houses of Congress, bills to reduce such emissions remain pending and others are likely to be introduced. Enactment of comprehensive climate change 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 effect on our business and the results of our operations.

 

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The EPA has also begun regulating greenhouse gas emissions under the Clean Air Act after authorizion by its December 2009 endangerment finding made in response to the 2007 U.S. Supreme Court Massachusetts v. EPA ruling In May 2010, the EPA issued a “tailoring rule” that determines which stationary sources of greenhouse emissions need to obtain a construction or operating permit, and install best available control technology for greenhouse gas emissions, under the Clean Air Act when such facilities are built or significantly modified. Prior to this rule, permits would have been required for stationary sources with emissions that exceed either 100 or 250 tons per year (depending on the type of source). The tailoring rule increases this threshold for greenhouse gas emissions to 75,000 tons per year on January 1, 2011 with the intent to tailor the requirement to initially apply only to large stationary sources such as coal-fired power plants and large industrial plants. The rule will further modify the threshold after July 1, 2011. In addition, the tailoring rule requires the EPA to undertake another rulemaking by no later than July 1, 2012 to, among other things, consider expanding permitting requirements to sources with greenhouse gas emissions greater than 50,000 tons per year. Moreover, in October 2009, the EPA issued a final rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their annual greenhouse gas emissions to the EPA beginning in 2011 for emissions occurring in 2010. Future federal legislative action or judicial decisions to pending or future court challenges may change any of the foregoing final or proposed EPA findings and regulations. If carbon dioxide emissions from electric utilities were to become subject to additional emission limits or permitting requirements, our customers demand for coal could decrease.
In some areas, carbon dioxide emissions are subject to state and regional regulation. For example, the Regional Greenhouse Gas Initiative, or RGGI, calls for a significant reduction of carbon dioxide emissions from power plants in the participating northeastern states by 2018. 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 been holding quarterly carbon dioxide allowance auctions for its initial three-year compliance period from January 1, 2009 to December 31, 2011 to allow utilities to buy allowances to cover their carbon dioxide emissions. Other current and proposed greenhouse gas regulation include the Midwestern Greenhouse Gas Reduction Accord, the Western Regional Climate Action Initiative and recently enacted legislation and permit requirements in California and other states.
Also, the U.S. Supreme Court recently granted certiorari to review a decision by the U.S. Court of Appeals for the Second Circuit. The Second Circuit had held that state governments and advocacy groups could seek injunctive relief using certain common law nuisance and trespass theories on the basis that emissions of carbon dioxide from specific sources of emissions may have created a public nuisance. The U.S. Court of Appeals for the Fifth Circuit recently dismissed on procedural grounds a class action in which the plaintiffs had claimed that various oil and energy companies had contributed to climate change.
In addition to direct regulation of greenhouse gases, over 30 states have adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources. These standards generally range from 10% to 30% over time periods that extend from the present until between 2020 and 2030. Several other 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 require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to switch from coal to lower carbon dioxide emitting fuels or shut down coal-fired power plants. Reasonably likely future regulation may include a carbon dioxide cap and trade program, a carbon tax or other regulatory regimes. The cost of future compliance may also depend on the likelihood that cost effective carbon capture and storage technology can be developed by the necessary date. The permitting of new coal-fired power plants has also recently been contested by 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.
Clean Water Act
The Clean Water Act, or 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 and associated state and federal regulations are complex and frequently subject to amendments, legal challenges and changes in implementation. Recent state and federal court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could increase the cost and time we expend on CWA compliance.

 

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CWA and similar state requirements that may directly or indirectly affect our operations include, but are not limited to, 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 NPDES, requires a permit for any such discharge 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 regulations; and “high quality/exceptional use” streams through anti-degradation regulations which restrict or prohibit discharges that result in degradation. Other requirements necessitate 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 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, require a permit issued under authority of Section 404 of the CWA (Section 404 permit(s)) from the Army Corps of Engineers, or 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 a “nationwide” permit, or NWP, for categories of similar 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 CWA. 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 Fourth Circuit rejected 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. On August 19, 2010, the U.S. Supreme Court dismissed the then pending certiorari.
      After the Fourth Circuit’s Aracoma decision, 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 that had been 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 permit 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, 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.
      On June 17, 2010, the Corps announced the suspension of the NWP 21 permitting process in these six states until the Corps takes further action on NWP 21, or until NWP 21 expires on March 18, 2012. While the suspension is in effect, proposed surface coal mining projects in these states that involve discharges of dredged or fill material into waters of the United States will have to obtain individual permits from the Corps pursuant to the CWA. Projects currently permitted under NWP 21 are not affected by the suspension, and NWP 21 remains available for proposed surface coal mining projects in other states.

 

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      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. The EPA’s review has a strong focus 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. 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. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of CWA permits by state and federal agencies.
      The EPA’s enhanced scrutiny initiatives have been challenged in federal courts by the National Mining Association, or NMA, and the State of West Virginia, and the Kentucky Coal Association/Commonwealth of Kentucky. On January 14, 2011, the U.S. District Court for the District of Columbia denied the EPA’s motion to dismiss the NMA’s complaint and the NMA’s motion for a preliminary injunction of the EPA’s enhanced scrutiny initiatives. The court ruling held that the EPA’s actions “are legislative rules that were adopted in violation of notice and comment requirements.” Although the NMA’s motion for a preliminary injunction was denied, the opinion contains holdings suggesting that the court may rule in favor of the NMA on the merits of the case. The West Virginia and Kentucky cases have been joined with the NMA’s case in the D.C. District Court of Appeals. Unless the challenge to the EPA’s enhanced scrutiny of permit applications is successful, we anticipate that we may not be able to obtain some Section 404 permits, it will continue to take longer to obtain most Section 404 permits, and the costs of obtaining Section 404 permits and compliance with Section 404 permit conditions will increase significantly.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act, or RCRA, regulates 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 RCRA 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 what type of waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when used as mine-fill. In June 2009, the EPA released proposals to regulate coal ash as either a non-hazardous waste under Subtitle D of RCRA or as a special waste under Subtitle C of RCRA. If re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal. The EPA issued a proposed rule for the safe disposal and management of coal ash from coal-fired power plants in May 2010 and received more than 400,000 comments.
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.

 

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Endangered Species Act
The 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 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, including the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act.
Employees
To carry out our operations, our general partner employed approximately 836 full-time employees as of December 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.
Available Information
We file annual and quarterly financial reports and current-event reports, as well as interim updates of a material nature to investors, with the SEC. You may read and copy any of these materials at the SEC’s Public Reference Room at 100 F. Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of that site is http://www.sec.gov.
We make our SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through our Internet website located at http://www.OxfordResources.com. Our annual reports are filed on Form 10-K, our quarterly reports are filed on Form 10-Q, and current-event reports are filed on Form 8-K; we also file amendments to reports filed or furnished pursuant to the Securities Exchange Act of 1934, or the Exchange Act. References to our website addressed in this Annual Report on Form 10-K are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this Annual Report on Form 10-K.

 

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ITEM 1A.   RISK FACTORS
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.
In order to pay the minimum quarterly distribution of $0.4375 per unit per quarter, or $1.75 per unit per year, we will require available cash of approximately $9.2 million per quarter, or $36.8 million per year, based on the number of general partner units, common units and subordinated units outstanding at December 31, 2010. 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.
Because of these and other factors, we may not have sufficient available cash to pay a specific level of cash distributions to our unitholders. Furthermore, the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may be unable to make cash distributions during periods when we record net income.
Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.
Our business is closely linked to domestic demand for electricity and any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. In 2010 we sold approximately 76.3% 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;

 

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    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.
Our long-term coal sales contracts subject us to renewal risks.
We sell most of the coal we produce under long-term coal sales contracts, which we define as contracts with initial terms of one year or more. 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.
In addition, we may be adversely affected by extensions of our long-term coal sales contract with AEP if market prices for coal under long-term contracts are low at the time of such extensions or if increases in costs during the term of such extensions are greater than the offsets from our cost pass through and cost adjustment provisions. The current term of our contract with AEP runs through 2012, but it can be extended for two additional three-year terms. For each extension term, the initial contract price will be based upon a market-based price for similar term contracts and will be negotiated at the time of such extension, subject to cost pass through and cost adjustment provisions. The contract also contains option provisions that give AEP the right to purchase additional tons of coal during each extension term at a fixed price. If AEP elects to extend this contract during a period when market prices for coal under similar term contracts are low, then we may be materially and adversely affected if the contract price we are able to negotiate with AEP is lower than our marginal cost of production. Alternatively, we may be materially and adversely affected if our marginal cost of production increases by more than the offsets from our cost pass through and cost adjustment provisions.
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.

 

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For more information regarding our long-term coal sales contracts, please read “Item 1. Business — Customers — Long-Term Coal Sales Contracts.”
Our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability.
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.
Competition within the coal industry may materially and adversely affect our ability to sell coal at an acceptable price.
We compete for domestic sales with numerous other coal producers in Northern Appalachia and the Illinois Basin and in other coal producing regions of the United States, primarily Central Appalachia and the 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.
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 our ability to make cash distributions to our unitholders.
We derived 73.9% of our revenues from coal sales to our five largest customers for the year ended December 31, 2010 and, as of March 1, 2011, we had long-term coal sales contracts in place with these same customers for 78.8% of our 2011 estimated coal sales. 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.
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.
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, regional and state regulatory initiatives to limit emissions of greenhouse gases include 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 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.

 

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The permitting of new coal-fired power plants has recently been contested by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions. In addition, a federal appeals courts has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, although the U.S. Supreme Court has granted certiorari to review this decision. A second federal appeals court dismissed such a case on procedural grounds. 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 “Item 1. Business — Mining and Environmental Regulation — Climate Change.”
Existing and future regulatory requirements relating to sulfur dioxide and other air emissions could affect our customers and could reduce the demand for the high-sulfur coal we produce and cause coal prices and sales of our high-sulfur coal to decline materially.
Coal-fired power plants are subject to extensive environmental regulation, particularly with respect to air emissions. For example, the Clean Air Act, and similar state and local laws and related regulations, 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 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. For a more detailed discussion of the regulation of air emissions, please read “Item 1. Business — Mining and Environmental Regulation — Clean Air Act.”
Our coal mining operations are subject to operating risks, which could result in materially increased operating expenses and decreased production levels and could have a material adverse effect on our business, financial condition or results of operations.
Our coal mining operations are subject to a number of operating risks beyond our control. Because we maintain very limited produced coal inventory, various conditions or events could disrupt operations, adversely affect production and shipments and 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 laws and regulations or changes in the interpretation or enforcement of existing laws and 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.

 

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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, any of which could have a material adverse effect on our business, financial condition or results of operations.
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 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.
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 distributions from Harrison Resources on a quarterly basis, including an aggregate of $5.9 million in distributions to us during 2010. In the future, however, there can be no assurance that we will receive regular cash distributions from Harrison Resources.
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.
A significant portion of our cash available for distribution to our unitholders is derived from royalty payments we receive on our underground coal reserves, which we do not operate.
In June 2005, we sold our underground mining operations at the Tusky mining complex to an independent coal producer 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, 2010, we received royalty income on our underground coal reserves of approximately $2.8 million or approximately 5.4% of our adjusted EBITDA. 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.

 

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Increases in the cost of diesel fuel and explosives, or the inability to obtain a sufficient quantity of those supplies, could increase our operating expenses, disrupt or delay our production and have a material adverse effect on our profitability.
We use considerable quantities of diesel fuel in our mining operations. 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 is 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.
Extensive environmental laws and regulations impose significant costs on our mining operations, and future laws and regulations could materially increase those costs or limit our ability to produce and sell coal.
The coal mining industry is subject to increasingly strict 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 accidents at certain underground mines. Violations can result in administrative, civil and criminal penalties and a range of other possible sanctions. In April 2010, a fatal mining accident in West Virginia received national attention and led Congress to further increase mine safety disclosure requirements. Additional state and national responses increasing mine safety regulation, reporting requirements, inspection and enforcement, particularly with regard to underground mining operations, are possible. 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.
We may be unable to obtain, maintain or renew permits necessary for our operations, which would materially reduce our production, cash flows and profitability.
As is typical in the coal industry, our coal production is dependent on our ability to obtain 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, has 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. Permitting by the Corps, the EPA and the Department of the Interior has become subject to enhanced review and stricter enforcement, especially under the CWA, to reduce the harmful environmental consequences of mountain-top mining, especially in Central Appalachia.
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. We expect that mining permits will be further 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 operations, and there could be a material adverse effect on our ability to make cash distributions to our unitholders. Please read “Item 1. Business — Mining and Environmental Regulation.”

 

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If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated.
SMCRA and counterpart state laws and regulations establish reclamation and closure standards for surface mining. As of December 31, 2010, we had accrued a reserve of approximately $13.0 million for future reclamation and mine closure obligations. The estimate of ultimate reclamation obligations is reviewed periodically 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 consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Asset Retirement Obligations” for more information regarding our reclamation and mine closure obligations.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
    our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
    our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
    we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
    our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
Restrictions in our 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 credit facility limits 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 credit facility also contains covenants requiring us to maintain certain financial ratios.
The provisions of our 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 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 may impact the environment or cause environmental contamination, which could result in material liabilities to us.
Our operations use hazardous materials, generate limited quantities of hazardous wastes and may affect runoff or drainage water. In the event of environmental contamination or a release of hazardous materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and clean up of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. 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 “Item 1. Business — Mining and Environmental Regulation.”
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 effectively could be impaired if we fail to attract and retain key management personnel.
Our ability to operate our business and implement our strategies depends 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.
A shortage of skilled labor in the mining industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time 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.
Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.
All of our mines are operated by non-union employees 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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Inaccuracies in our estimates of our coal reserves could result in lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of the estimates of our proven and probable coal reserves. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, any one of which may vary considerably from actual results. These factors and assumptions include:
    quality of the coal;
    geologic and mining conditions, which may not be fully identified by available exploration data or may differ from our experiences in areas where we currently mine;
    the percentage of coal ultimately recoverable;
    the assumed effects of regulation, including the issuance of required permits, and taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
    assumptions concerning the timing for the development of reserves; and
    assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.
As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers and accounting personnel, or by the same engineers and accounting personnel at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in the estimates related to our reserves could have a material adverse effect on our ability to make cash distributions.
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. The current economic volatility and tight 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 of the 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 2010, approximately 24% of our sales were through coal brokers. We expect our sales through coal brokers to increase to approximately 31% of our sales in 2011.
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 ability to make cash distributions to our unitholders.
Federal and state laws require us to secure the performance of certain long-term obligations, such as mine closure or reclamation costs. The amount of these security arrangements is substantial, with total amounts of surety bonds at March 14, 2011 of approximately $35.5 million, which were supported by letters of credit of $6.7 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 our ability to make cash distributions to our unitholders could be adversely affected.

 

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The amount of estimated reserve replacement expenditures that 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.
For 2011, we expect to incur between $5.5 million and $6.0 million in reserve replacement expenditures. 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. 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. 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, subject to approval by the conflicts committee of the board of directors of our general partner, or the Conflicts Committee.
Our management team does not have experience managing our business as a stand-alone publicly traded partnership, and if they are unable to manage our business as a publicly traded partnership our business may be affected.
Our management team does not have experience managing our business as a publicly traded partnership. If we are unable to manage and operate our partnership as a publicly traded partnership, our business and results of operations will be adversely affected.
We will be required by Section 404 of the Sarbanes-Oxley Act to evaluate the effectiveness of our internal controls. If we are unable to establish and maintain effective internal controls, our financial condition and operating results could be adversely affected.
We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We are also in the process of performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management report 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 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. 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.
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.

 

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Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Risks Inherent in an Investment in Us
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.
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 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 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 or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or 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.

 

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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.
C&T Coal owns an 18.2% limited partner interest in us, AIM Oxford owns a 35.7% limited partner interest in us, and C&T Coal and AIM Oxford own substantially all of and control our general partner and its 2.0% general partner interest in us. 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 and issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;
    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 80.0% 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.
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.

 

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Our unitholders have limited voting rights and are not entitled to elect our general partner or its directors or initially to remove our general partner without its consent.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders 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 have limited ability to remove our general partner.
Our unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 80.0% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. Affiliates of our general partner own 55.4% of our common units and subordinated units. 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.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own choices and to control the decisions and actions of the board of directors and executive officers of our general partner.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
C&T Coal and AIM Oxford own an aggregate of 55.1% of our common units and subordinated units. If at any time our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our 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 Exchange Act.

 

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We may issue additional units without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, our partnership agreement does not prohibit the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
    our unitholders’ proportionate ownership interest in us will decrease;
    the amount of cash available for distribution on each unit may decrease;
    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
    the relative voting strength of each previously outstanding unit may be diminished; and
    the market price of the common units may decline.
Our general partner may, without unitholder approval, elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%) 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.
Cost reimbursements due to our general partner and its affiliates reduce cash available for distribution to our unitholders.
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole 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 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. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders.

 

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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 are not entitled to receive distributions or allocations of income or loss on their common units and their common units will be subject to redemption.
Our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner 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 is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. 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.
Our unitholders may have liability to repay distributions.
Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or the IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. 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 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (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.

 

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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.
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 taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Recently, members of the U.S. Congress considered substantive changes to the existing U.S. federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. Any modification to the U.S. federal income tax laws or interpretations thereof 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 changes could negatively impact the value of an investment in our common units.
Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.
Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2012, 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, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.
Our unitholders’ share of our income is taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder is treated as a partner to whom we allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income is 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.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the 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 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 the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of 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.

 

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Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
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.
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 use of this proration method may not be permitted under existing Treasury Regulations. 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.
A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to effect 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 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.

 

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We have adopted 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 the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the 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.
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. 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.
ITEM 1B.   UNRESOLVED STAFF COMMENTS
None.

 

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ITEM 2.   PROPERTIES
Mining Operations
See “Item 1. Business — Mining Operations” for specific information about our mining operations.
Coal Reserves
The estimates of our proven and probable reserves associated with our surface mining operations in Northern Appalachia 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.
As of December 31, 2010, 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, 2010, we owned 19% of our coal reserves and leased 81% 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 to mine for approximately the next three years. Given the current permitting environment, we intend to continually address the timing of our permitting process in such a way as to as much as possible avoid any material delays in obtaining or renewing permits on our remaining coal reserves associated with our mining operations.

 

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The following table provides information as of December 31, 2010 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
    10.9       6.5       4.4  
Tuscarawas County
    7.6       0.1       7.5  
Plainfield
    6.4       0.8       5.6  
Belmont County
    6.2       1.6       4.6  
New Lexington
    5.7       3.7       2.0  
Harrison(2)
    5.1       5.1        
Noble County
    2.7             2.7  
 
                 
Total Northern Appalachia
    44.6       17.8       26.8  
 
                 
 
                       
Illinois Basin (Kentucky)
                       
Muhlenberg County
    23.5             23.5  
 
                 
Total Illinois Basin
    23.5             23.5  
 
                 
 
                       
Total Surface Mining Operations
    68.1       17.8       50.3  
 
                 
 
Underground Coal Reserves:
                       
Tusky
    25.4             25.4  
 
                 
Total Underground Coal Reserves
    25.4             25.4  
 
                 
Total
    93.5       17.8       75.7  
 
                 
 
                       
Percentage of Total
    100.0 %     19.0 %     81.0 %
 
                 
 
     
(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 51.0% of Harrison Resources and CONSOL Energy Inc. owns the remaining 49.0% of Harrison Resources 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, 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 100.0% of Harrison Resources.

 

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The following table provides information on particular characteristics of our coal reserves as of December 31, 2010:
                                                                 
    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%  
                                    (tons in millions)  
Surface Mining Operations:
                                                               
Northern Appalachia (principally Ohio)
                                                               
Cadiz
    11.9       3.4       11,500       6.0       10.9       0.9       5.0       5.0  
Tuscarawas County
    10.6       3.9       11,670       6.6       7.6       1.2       2.9       3.5  
Plainfield
    10.5       4.4       11,460       7.7       6.4             0.8       5.6  
Belmont County
    12.9       3.8       11,620       6.6       6.2             3.7       2.5  
New Lexington
    11.6       3.9       11,550       6.8       5.7             2.9       2.8  
Harrison(2)
    12.1       1.8       12,000       3.1       5.1       3.6       1.5        
Noble County
    12.1       4.7       11,200       8.3       2.7             0.4       2.3  
Illinois Basin (Kentucky)
                                                               
Muhlenberg County
    10.9       3.6       11,309       6.4       23.5             22.8       0.7  
Underground Coal Reserves:
                                                               
Tusky
    5.4       2.1       12,910       3.3       25.4       3.8       21.6        
 
     
(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 51.0% of Harrison Resources and CONSOL Energy Inc. owns the remaining 49.0% of Harrison Resources 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, 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 100.0% of Harrison Resources.
Office Facilities
We lease and own office space in Columbus, Ohio and Coshocton, Ohio, respectively, that is used by our general partner’s executive and administrative employees. Our Columbus, Ohio office space lease expires in 2015.
ITEM 3.   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 could 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.
ITEM 4.   RESERVED

 

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PART II
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common units are listed on the NYSE under the symbol “OXF” and began trading on July 14, 2010 on a “when-issued” basis. Prior to July 14, 2010, our common units were not listed on any exchange or traded in any public market. On March 14, 2011, the closing market price for the common units was $25.90 per unit. As of March 14, 2011, there were 10,341,416 common units outstanding. There were approximately 49 record holders of common units on December 31, 2010. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.
The following table sets forth, for each period indicated, the high and low sales prices per common unit, as reported on the NYSE, and the cash distributions declared and paid per common unit for each quarter since our initial public offering:
                         
    High     Low        
Period   Price     Price     Distributions Declared Per Unit  
Quarter ended September 30, 2010
  $ 19.80     $ 16.44     $ 0.3519  
Quarter ended December 31, 2010
  $ 24.93     $ 19.36     $ 0.4375  
We have also issued 10,280,380 subordinated units and 420,853 general partner units, for which there is no established public trading market. All of the subordinated units and general partner units are held by affiliates of our general partner. The affiliates of our general partner receive quarterly distributions on the subordinated units only after sufficient distributions have been paid to the common units.
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 resulting from working capital borrowings made subsequent to the end of such quarter. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement that are used solely to pay distributions to unitholders.
Our partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4375 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. 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.
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) $1.75 (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 September 30, 2013 or (ii) $0.65625 per quarter (150.0% of the minimum quarterly distribution, which is $2.625 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 September 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. When the subordination period ends, each outstanding subordinated unit will convert into one common unit and any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished. All of our subordinated units are held by AIM Oxford and C&T Coal.

 

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Our general partner is entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 420,853 general partner units. 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 in excess of $0.5031 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 general partner may receive on common units or subordinated units that it owns. We did not pay our general partner any amounts with respect to its incentive distribution rights in connection with distributions for 2010.
There is no guarantee that we will distribute quarterly cash distributions to our unitholders. Our cash distribution policy is subject to restrictions on cash distributions under our credit facility. Specifically, our credit facility contains 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 credit facility. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Credit Facility.”
Our ability to pay quarterly cash distributions is also potentially restricted by the operating agreement of Harrison Resources, our joint venture with CONSOL Energy. Pursuant to the 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 distributions from Harrison Resources on a quarterly basis, including an aggregate of $5.9 million in distributions to us during 2010. In the future, however, there can be no assurance that we will receive regular cash distributions from Harrison Resources.
Unregistered Sales of Equity Securities
From our formation in August 2007 until July 19, 2010, we issued 91,996 Class A common units to our employees upon the vesting of phantom units granted under our long-term incentive plan. These unit amounts do not reflect the unit split that was effected in connection with our initial public offering. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933 or Rule 701 pursuant to compensatory benefit plans and contracts related to compensation.
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 our general partner as consideration for the issuance to our general partner of approximately 1,282 and 137 general partner units, respectively. These unit amounts do not reflect the unit split that was effected in connection with our initial public offering. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933.
On July 19, 2010, in connection with the closing of our initial public offering, our general partner contributed 175,000 of our common units to us in exchange for 175,000 general partner units in order to maintain its 2.0% general partnership interest in us. This transaction was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.
On October 29, 2010, December 31, 2010 and January 31, 2011, we received contributions of approximately $2,043, $20,194 and $5,349, respectively, from our general partner as consideration for the issuance to our general partner of approximately 106, 920 and 220 general partner units, respectively. These transactions were exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended. Issuer Purchases of Equity Securities
No purchases of our common units were made by us or on our behalf during 2010.
Securities Authorized for Issuance Under Equity Compensation Plan
Please read the information in this Annual Report on Form 10-K under “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” which is incorporated by reference into this Item 5.

 

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ITEM 6.   SELECTED FINANCIAL AND OPERATING DATA
The following table presents our selected 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 should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
SELECTED FINANCIAL AND OPERATING DATA
                                                 
    Oxford Resource Partners, LP     Oxford Mining Company  
    (Successor)     (Predecessor)  
                            Period from        
                            August 24,     January 1,     Year  
                            2007 to     2007 to     Ended  
    Years Ended December 31,     December 31,     August 23,     December 31,  
    2010     2009     2008     2007     2007     2006  
    (in thousands, except per ton amounts)  
Statement of Operations Data:
                                               
Revenues:
                                               
Coal sales
  $ 311,567     $ 254,171     $ 193,699     $ 61,324     $ 96,799     $ 141,440  
Transportation revenue
    38,490       32,490       31,839       10,204       18,083       27,771  
Royalty and non-coal revenue
    6,521       7,183       4,951       1,407       3,267       6,643  
 
                                   
 
Total revenues
    356,578       293,844       230,489       72,935       118,149       175,854  
Costs and expenses:
                                               
Cost of coal sales (excluding DD&A, shown separately)
    229,468       170,698       151,421       40,721       70,415       106,657  
Cost of purchased coal
    22,024       19,487       12,925       9,468       17,494       22,159  
Cost of transportation
    38,490       32,490       31,839       10,204       18,083       27,771  
Depreciation, depletion and amortization
    42,329       25,902       16,660       4,926       9,025       12,396  
Selling, general and administrative expenses
    14,757       13,242       9,577       2,114       3,643       2,097  
Contract termination and amendment expenses, net
    652                                
 
                                   
 
Total costs and expenses
    347,720       261,819       222,422       67,433       118,660       171,080  
 
                                   
 
Income (loss) from operations
    8,858       32,025       8,067       5,502       (511 )     4,774  
Interest income
    12       35       62       55       26       30  
Interest expense
    (9,511 )     (6,484 )     (7,720 )     (3,498 )     (2,386 )     (3,672 )
Gain on purchase of business(1)
          3,823                          
 
                                   
 
Net income (loss)
    (641 )     29,399       409       2,059       (2,871 )     1,132  
Less: Net income attributable to noncontrolling interest
    (6,710 )     (5,895 )     (2,891 )     (537 )     (682 )      
 
                                   
 
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (7,351 )   $ 23,504     $ (2,482 )   $ 1,522     $ (3,553 )   $ 1,132  
 
                                   
Net income (loss) allocated to general partner
  $ (147 )   $ 467     $ (50 )   $ 30       n/a       n/a  
 
                                   
Net income (loss) allocated to limited partner
  $ (7,204 )   $ 23,037     $ (2,432 )   $ 1,492       n/a       n/a  
 
                                   
 
                                               
Net income (loss) per limited partner unit:
                                               
Basic
  $ (0.45 )   $ 2.09     $ (0.24 )   $ 0.17       n/a       n/a  
 
                                   
Diluted
  $ (0.45 )   $ 2.08     $ (0.24 )   $ 0.17       n/a       n/a  
 
                                   
 
                                               
Weighted average number of limited partner units outstanding:
                                               
Basic
    15,887,977       11,033,840       10,104,324       8,922,801       n/a       n/a  
 
                                   
Diluted
    15,887,977       11,083,170       10,104,324       8,926,360       n/a       n/a  
 
                                   
Distributions paid per limited partner unit (2)
  $ 0.58     $ 1.20     $ 1.26     $       n/a       n/a  
 
                                   

 

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SELECTED FINANCIAL AND OPERATING DATA — (continued)
                                                 
    Oxford Resource Partners, LP     Oxford Mining Company  
    (Successor)     (Predecessor)  
                            Period from        
                            August 24,     January 1,     Year  
                            2007 to     2007 to     Ended  
    Years Ended December 31,     December 31,     August 23,     December 31,  
    2010     2009     2008     2007     2007     2006  
    (in thousands, except per ton amounts)  
Statement of Cash Flows Data:
                                               
Net cash provided by (used in):
                                               
Operating activities
  $ 37,997     $ 38,637     $ 33,992     $ (8,519 )   $ 17,634     $ 16,236  
Investing activities
    (82,623 )     (49,171 )     (23,942 )     (98,745 )     (16,619 )     (13,547 )
Financing activities
    42,149       (1,279 )     4,494       106,724       (234 )     (2,548 )
 
                                               
Other Financial Data:
                                               
Adjusted EBITDA (3)
  $ 51,617     $ 56,967     $ 24,686       8,120       10,691       16,998  
Distributable cash flow (4) (5)
    8,526       n/a       n/a       n/a       n/a       n/a  
Reserve replacement expenditures (6)
    3,353       3,057       2,526       163       1,297       3,881  
Other maintenance capital expenditures (6)
    25,028       25,657       25,321       7,420       11,305       9,665  
 
                                               
Balance Sheet Data (at period end):
                                               
Cash and cash equivalents
  $ 889     $ 3,366     $ 15,179     $ 635     $ 1,175     $ 392  
Trade accounts receivable
    28,108       24,403       21,528       17,547       18,396       16,826  
Inventory
    12,640       8,801       5,134       4,655       4,824       3,977  
Property, plant and equipment, net
    198,694       149,461       112,446       106,408       54,510       48,001  
Total assets
    261,071       203,363       171,297       146,774       90,893       80,533  
Total debt (current and long-term)
    102,986       95,711       83,977       75,529       43,165       43,697  
 
                                               
Operating Data:
                                               
Tons of coal produced (clean)
    7,470       5,846       5,089       1,634       2,693       3,913  
Tons of coal purchased
    734       530       434       305       641       962  
Tons of coal sold
    8,151       6,311       5,528       1,938       3,333       4,872  
Tons sold under long-term contracts (7)
    95.9 %     97.8 %     93.8 %     98.9 %     96.6 %     99.5 %
Average sales price per ton (8)
  $ 38.22     $ 40.27     $ 35.04     $ 31.64     $ 29.04     $ 29.03  
Cost of purchased coal sales per ton (9)
  $ 30.00     $ 36.79     $ 29.81     $ 31.08     $ 27.29     $ 23.03  
Cost of coal sales per ton produced (10)
  $ 30.94     $ 29.52     $ 29.81     $ 24.93     $ 26.16     $ 27.27  
Number of operating days — NAPP operations
    275.5       274.5       280.0       97.5       181.5       277.0  
Number of operating days — ILB operations
    273.0       60.5       n/a       n/a       n/a       n/a  
 
     
(1)   On September 30, 2009, we acquired all of the active Illinois Basin 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)   Excludes amounts distributed as part of the initial public offering.
 
(3)   Adjusted EBITDA is not defined in GAAP. Adjusted EBITDA is presented because it is helpful to management, industry analysts, investors, lenders and rating agencies in assessing the financial performance and operating results of our fundamental business activities. For a definition of adjusted EBITDA and a reconciliation of adjusted EBITDA to our net income (loss) attributable to unitholders, please see “Non-GAAP Financial Measures” in this Item 6.
 
(4)   Distributable cash flow is not defined in GAAP. Distributable cash flow is presented because it is helpful to management, industry analysts, investors, lenders and rating agencies in assessing our financial performance. For a definition of distributable cash flow and a reconciliation of distributable cash flow to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” in this Item 6.
 
(5)   Represents our distributable cash flow for the second half of 2010 during which we were a publicly traded partnership. We do not calculate distributable cash flow with respect to periods prior thereto.
 
(6)   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 cash expenditures for the purchase of fee interests in coal reserves and cash expenditures for advance royalties with respect to the acquisition of leasehold interests in coal reserves. Examples of other maintenance capital expenditures include capital expenditures associated with the repair, refurbishment and replacement of equipment and with mine development. 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. In 2010, we modified the definitions and calculations of reserve replacement expenditures and other maintenance capital expenditures on a prospective basis resulting from the amendment to our partnership agreement. Reserve replacement expenditures for 2010 are estimated, while prior years are actual. Other maintenance capital expenditures for 2010 include asset retirement obligations and mine development costs, while prior years do not.

 

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(7)   Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts.
 
(8)   Represents our coal sales divided by total tons of coal sold.
 
(9)   Represents the cost of purchased coal divided by the tons of coal purchased.
 
(10)   Represents our cost of coal sales (excluding depreciation, depletion and amortization, or DD&A) divided by the tons of coal we produce.
NON-GAAP FINANCIAL MEASURES
Adjusted EBITDA
Adjusted EBITDA for a period represents net income (loss) attributable to our unitholders for that period before interest, taxes, DD&A, gain on purchase of business, contract termination and amendment expenses, net, amortization of below-market coal sales contracts, non-cash equity-based compensation expense, non-cash gain or loss on asset disposals and the non-cash change in future asset retirement obligations (“ARO”). The non-cash change in future ARO is the portion of our non-cash change in our future ARO that is included in reclamation expense in our financial statements, and that portion represents the change over the applicable period in the value of our ARO. 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 certain credit facility financial covenants. Because not all companies calculate adjusted EBITDA identically, our calculation may not be comparable to the similarly titled measure of other companies. Please read “— Reconciliation to GAAP Measures” below for a reconciliation of net income (loss) attributable to our unitholders to adjusted EBITDA for each of the periods indicated.
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 credit facility financial covenants; and
 
    our ability to fund capital expenditure projects from operating cash flow.
Distributable Cash Flow
Distributable cash flow for a period represents adjusted EBITDA for that period, less cash interest expense (net of interest income), estimated reserve replacement expenditures and other maintenance capital expenditures. Cash interest expense represents the portion of our interest expense accrued for the period that was paid in cash during the period or that we will pay in cash in future periods. Estimated reserve replacement expenditures represent an estimate of the average periodic (quarterly or annual, as applicable) reserve replacement expenditures that we will incur over the long term as applied to the applicable period. We use estimated reserve replacement expenditures to calculate distributable cash flow instead of actual reserve replacement expenditures, consistent with our partnership agreement which requires that we deduct estimated reserve replacement expenditures when calculating operating surplus. Other maintenance capital expenditures include, among other things, actual expenditures for plant, equipment and mine development and our estimate of the periodic expenditures that we will incur over the long term relating to our ARO. Distributable cash flow should not be considered as 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. Although distributable cash flow is not a measure of performance calculated in accordance with GAAP, our management believes distributable cash flow is a useful measure to investors because this measurement is used by many analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and to compare it with the performance of other publicly traded limited partnerships. We also compare distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the coverage ratio of distributable cash flow to planned cash distributions. Please read “— Reconciliation to GAAP Measures” below for a reconciliation of net income (loss) attributable to our unitholders to distributable cash flow for each of the periods indicated.

 

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Reconciliation to GAAP Measures
The following table presents a reconciliation of net income (loss) attributable to unitholders to adjusted EBITDA and distributable cash flow for each of the periods indicated:
                                                         
    Oxford Resource Partners, LP     Oxford Mining  
    (Successor)     (Predecessor)  
                                    Period     Period        
                                    from     from        
            Year     Year     Year     August 24,     January 1,     Year  
    Second     Ended     Ended     Ended     2007 to     2007 to     Ended  
    Half of     December 31,     December 31,     December 31,     December 31,     August 23,     December 31,  
    2010     2010     2009     2008     2007     2007     2006  
    (in thousands)  
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (4,957 )   $ (7,351 )   $ 23,504     $ (2,482 )   $ 1,522     $ (3,553 )   $ 1,132  
PLUS:
                                                       
Interest expense, net of interest income
    5,634       9,499       6,449       7,658       3,443       2,360       3,642  
Depreciation, depletion and amortization
    23,997       42,329       25,902       16,660       4,926       9,025       12,396  
Contract termination and amendment expenses, net
    652       652                                
Non-cash equity compensation expense
    486       942       472       468       25              
Non-cash (gain) loss on asset disposals
    776       1,228       1,177       (1,407 )     (8 )     (25 )     8  
Change in fair value of future asset retirement obligations
    3,198       5,742       4,991       4,560       167       2,884       (180 )
LESS:
                                                       
Gain on purchase of business
                3,823                          
Amortization of below-market coal sales contracts
    399       1,424       1,705       771       1,955              
 
                                         
Adjusted EBITDA(1)
    29,387     $ 51,617     $ 56,967     $ 24,686     $ 8,120     $ 10,691     $ 16,998  
 
                                         
LESS:
                                                       
Cash interest expense, net of interest income
    3,531                                                  
Estimated reserve replacement expenditures
    2,635                                                  
Other maintenance capital expenditures
    14,695                                                  
 
                                                     
 
                                                       
Distributable cash flow(1)
  $ 8,526                                                  
 
                                                     
 
     
(1)  
The calculation of adjusted EBITDA and distributable cash flow as presented in our quarterly filing for the period ended September 30, 2010 was modified, and such changes are reflected herein, to conform to the current definition of these non-GAAP financial measures. We do not calculate distributable cash flow with respect to periods beginning prior to the second half of 2010 during which we were a publicly traded partnership.

 

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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth under “Cautionary Statement About Forward-Looking Statements.”
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 operate in a single business segment and have three operating subsidiaries, Oxford Mining Company, LLC, Oxford Mining Company — Kentucky, LLC and Harrison Resources, LLC. All of our operating subsidiaries participate in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to our customers.
We currently have 21 active surface mines, two of which became active mines in 2011, that are managed as eight mining complexes. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During 2010, we produced 7.5 million tons of coal and sold 8.1 million tons of coal, including 0.7 million tons of purchased coal. As a result, our coal inventory on hand increased by approximately 0.1 million tons. We purchase coal in the open market and under contracts to satisfy a portion of our sales commitments. During 2010, we produced 1.7 million tons of coal from the Illinois Basin reserves we acquired from Phoenix Coal on September 30, 2009. As is customary in the coal industry, we have entered into long-term coal sales contracts with many of our customers. We define long-term coal sales contracts as coal sales contracts having initial terms of one year or more.
On July 19, 2010, we closed our initial public offering of common units. After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, our offering expenses of approximately $6.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $144.5 million. We used all of the net proceeds from our initial public offering for the uses described in the prospectus for our initial public offering.
In connection with our initial public offering, we paid off the amounts outstanding under a $115 million credit facility evidenced by a credit agreement with a syndicate of lenders, for which FirstLight Funding I, Ltd. acted as Administrative Agent (our “$115 million credit facility” or our “prior $115 million credit facility”), and entered into a new $175 million credit facility evidenced by a credit agreement with Citicorp USA, Inc., as Administrative Agent, Citibank, N.A., as Swing Line Bank, Barclays Bank PLC and The Huntington National Bank, as Co-Syndication Agents, Fifth Third Bank and Comerica Bank, as Co-Documentation Agents, and the lenders party thereto (our “$175 million credit facility” or our “new $175 million credit facility”). Our $175 million credit facility provides for a $60 million term loan and a $115 million revolving credit facility. As of December 31, 2010, we had $90 million of borrowings outstanding under our $175 million credit facility, consisting of term loan borrowings of $57 million and revolving credit facility borrowings of $33 million.
Evaluating Our Results of Operations
We evaluate our results of operations based on several key measures:
    our coal production, sales volume and average sales price, which drive our coal sales;
    our cost of coal sales;
    our cost of purchased coal;
    our adjusted EBITDA, a non-GAAP financial measure; and
 
    our distributable cash flow, a non-GAAP financial measure.

 

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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. These coal volumes are measured in clean tons, net of refuse. 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 prices that are either fixed or contain market-based adjustments, over the contract term. In addition, most of our long-term coal sales contracts have full or partial cost pass through or cost adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for items such as fuel, explosives and labor. Cost 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 cost-related indices, including cost-related indices for fuel, explosives, labor, equipment and cost-of-living generally.
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 and purchases, coal sales volume and average sales price per ton for the periods indicated:
                                         
                            % Change  
                            2010     2009  
    Years Ended December 31,     vs.     vs.  
    2010     2009     2008     2009     2008  
    (tons in thousands)                  
 
                                       
Tons of coal produced (clean)
    7,470       5,846       5,089       27.8 %     14.9 %
(Increase) decrease in inventory
    (53 )     (65 )     5       n/a       n/a  
Tons of coal purchased
    734       530       434       38.5 %     22.1 %
Tons of coal sold
    8,151       6,311       5,528       29.2 %     14.2 %
Tons sold under long-term contracts(1)
    95.9 %     97.8 %     93.8 %     -1.9 %     4.3 %
Average sales price per ton
  $ 38.22     $ 40.27     $ 35.04       -5.1 %     14.9 %
 
     
(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 costs of purchased coal and transportation, DD&A and any indirect costs such as selling, general and administrative expenses, or SG&A expenses, on a cost per ton sold basis. Our cost of coal sales per ton sold represents our cost of coal sales divided by the tons of coal we sold. Our cost of coal sales includes costs for labor, fuel, oil, explosives, royalties, operating leases, repairs and maintenance and all other costs that are directly related to our mining operations. Our cost of coal sales does not take into account the effects of any of the cost pass through or cost adjustment 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 periods indicated relating to our cost of coal sales per ton and tons sold:
                                         
                            % Change  
                            2010     2009  
    Years Ended December 31,     vs.     vs.  
    2010     2009     2008     2009     2008  
    (tons in thousands)                  
 
                                       
Cost of coal sales per ton
  $ 30.94     $ 29.52     $ 29.73       4.8 %     -1.0 %
Tons of coal produced (clean)
    7,470       5,846       5,089       27.8 %     14.9 %

 

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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 our acquisition of Illinois Basin assets from Phoenix Coal, 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 0.4 million tons of coal each year until the coal reserves covered by this contract are depleted. Based on an estimate of the proven and probable coal reserves in place at December 31, 2010, we expect this contract to continue beyond five years.
We evaluate our cost of purchased coal on a per ton basis. For 2010, we sold 734,000 tons of purchased coal. The following table provides summary information for the periods indicated for our cost of purchased coal per ton and tons purchased:
                                         
                            % Change  
                            2010     2009  
    Years Ended December 31,     vs.     vs.  
    2010     2009     2008     2009     2008  
    (tons in thousands)                  
 
Cost of purchased coal per ton
  $ 30.00     $ 36.79     $ 29.81       -18.5 %     23.4 %
Tons of coal purchased
    734       530       434       38.5 %     22.1 %
Adjusted EBITDA
For a definition of adjusted EBITDA and a reconciliation of our net income (loss) attributable to unitholders to adjusted EBITDA, please see “Non-GAAP Financial Measures” in Item 6. Please also read “— Summary” for a reconciliation of net income (loss) attributable to our unitholders to adjusted EBITDA for the period indicated.
Distributable Cash Flow
For a definition of distributable cash flow and a reconciliation of our net income (loss) attributable to unitholders to distributable cash flow, please see “Non-GAAP Financial Measures” in Item 6. Please also read “— Summary” for a reconciliation of net income (loss) attributable to our unitholders to distributable cash flow for the period indicated.
Factors That Impact Our Business
For the past three years over 90.0% 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 or cost adjustment provisions.
During 2010, we executed over $275 million in long-term coal sales contracts primarily having an effect on sales beginning in 2012. These contracts, the majority of which were related to our Illinois Basin operations, were executed at prices significantly higher than current levels. For 2011, 2012, 2013 and 2014, we currently have long-term coal sales contracts that represent 100%, 78%, 52% and 47%, respectively, of our 2011 estimated coal sales of 9.1 million tons. Two of our long-term coal sales contracts with the same customer contain provisions that provide for price re-openers. These price re-openers provide for market-based adjustments to the initial contract price every three years. These long-term coal sales contracts will terminate in 2013 if we cannot agree upon a market-based price with the applicable customer prior to the termination date. In addition, we have one long-term coal sales contract that will terminate in 2014 if we cannot agree upon a market-based price with the customer prior to the termination date. The coal tonnage which is involved for these two customers through 2014 is 1.0 million tons annually for 2013 and 2014 and 0.4 million tons annually for 2014, respectively.

 

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The current term of our long-term coal sales contract with AEP runs through 2012 but it can be extended for two additional three-year terms if AEP gives us six months advance notice of its election to extend the contract. For each extension term, we will negotiate with AEP to agree upon a market-based price based on similar term contracts. In addition, the contract contains substantial cost pass through and/or cost adjustment provisions. If AEP elects to extend this contract, we will be committed to deliver an additional 2.0 million tons in 2013 and 2014, and our 2013 and 2014 coal sales under long-term coal sales contracts, as a percentage of 2011 estimated coal sales, would increase to 74% and 69%, respectively. We are currently in negotiations with AEP to extend our contract with them. The mutual goal of the parties is to amend the contract to fix the term to run through 2018, establish future pricing that is acceptable to both parties, and adjust the amounts of fixed and optional coal tonnage covered by the contract. While the outcome of these negotiations is not certain at this time, we believe that we will be able to achieve an extension that is on amended terms which are beneficial to us and that furthers our long-term coal sales contract strategy.
The terms of our coal sales contracts result from competitive bidding and negotiations with customers. As a result, the terms of these contracts vary by customer. However, most of our long-term coal sales contracts have full or partial cost pass through provisions and/or cost adjustment provisions. For 2011, 2012, 2013 and 2014, 81%, 96%, 100% and 91% of the coal, respectively, that we have committed to deliver under our current long-term coal sales contracts are subject to full or partial cost pass through provisions and/or cost adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for such items as fuel, explosives and/or labor. Cost 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 cost-related indices.
A long-term coal sales contract may contain option provisions that give the customer the right to elect to purchase additional tons of coal each month during the contract term at a fixed price provided for in the contract. For example, upon 30 days advance notice, AEP may elect to purchase, at the contract price in effect at the time for all other tons, an additional 25,000 tons of coal each month under its long-term coal sales contract with us and, in addition, upon 90 days notice, it may elect to purchase, at the contract price in effect at the time for all other tons, an additional 200,000 tons of coal per half year. Our long-term coal sales contracts that provide for these option tons typically require the customer to provide us with from one to three months advance notice of an election to take these option tons. Because the price of these option tons is fixed at the contract price in effect at the time for all other tons under the terms of the contract, if our contract price is below market, we could be obligated to deliver additional coal to those customers at a price that is below the market price for coal on the date the option is exercised. For 2011, 2012, 2013 and 2014, we have outstanding option tons of 0.7 million, 0.9 million, 0.9 million and 1.2 million, respectively. If our customer does elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes.
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.
Results of Operations
Factors Affecting the Comparability of Our Results of Operations
The comparability of our results of operations is impacted by (i) the acquisition of Illinois Basin assets from Phoenix Coal on September 30, 2009, (ii) an amendment to a long-term coal sales contract with a major customer in December 2008 and (iii) the transactions relating to the closing of our initial public offering and our $175 million credit facility in July 2010.

 

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We acquired all of the active Illinois Basin surface mining operations of Phoenix Coal on September 30, 2009. The financial results from this acquisition are included in our consolidated financial statements for 2010. However, only three months of financial results from this acquisition are included in our consolidated financial statements for 2009 and none of the financial results from this acquisition are included in our consolidated financial statements for 2008.
In December 2008, we agreed with one of our major customers 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 temporary increase in the price per ton of coal for 2009 along with certain cost adjustment provisions for the remaining term of the contract, which expires at the end of 2012 unless extended at the customer’s election. This price increase contributed $13.3 million to revenue and adjusted EBITDA for 2009.
In connection with the closing of our initial public offering and our $175 million credit facility, we executed the following transactions, each of which had an impact on our results of operations for 2010:
    we terminated our $115 million credit facility (See Note 10 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Long-Term Debt”);
    we terminated our advisory services agreement with affiliates of AIM Oxford (See Note 19 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Related Party Transactions”); and
    we purchased $54.2 million of previously leased and additional major mining equipment.

 

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Summary
The following table presents certain of our historical consolidated financial data for the years indicated and contains both GAAP and non-GAAP financial measures:
                         
    Years Ended December 31,  
    2010     2009     2008  
    (in thousands)  
 
Statement of Operations Data:
                       
Revenues:
                       
Coal sales
  $ 311,567     $ 254,171     $ 193,699  
Transportation revenue
    38,490       32,490       31,839  
Royalty and non-coal revenue
    6,521       7,183       4,951  
 
                 
Total revenues
    356,578       293,844       230,489  
 
                       
Costs and expenses:
                       
Cost of coal sales (excluding DD&A, shown separately)
    229,468       170,698       151,421  
Cost of purchased coal
    22,024       19,487       12,925  
Cost of transportation
    38,490       32,490       31,839  
Depreciation, depletion and amortization
    42,329       25,902       16,660  
Selling, general and administrative expenses
    14,757       13,242       9,577  
Contract termination and amendment expenses, net
    652              
 
                 
Total costs and expenses
    347,720       261,819       222,422  
 
                       
Income from operations
    8,858       32,025       8,067  
Interest income
    12       35       62  
Interest expense
    (9,511 )     (6,484 )     (7,720 )
Gain on purchase of business (1)
          3,823        
 
                 
 
                       
Net income (loss)
    (641 )     29,399       409  
Less: Net income (loss) attributable to noncontrolling interest
    (6,710 )     (5,895 )     (2,891 )
 
                 
 
                       
Net income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (7,351 )   $ 23,504     $ (2,482 )
 
                 
 
                       
Other Financial Data:
                       
Adjusted EBITDA(2)
  $ 51,617     $ 56,967     $ 24,686  
 
                 
 
     
(1)   On September 30, 2009, we acquired all of the active Illinois Basin 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)   For our definition of adjusted EBITDA, which is a non-GAAP financial measure, and for a reconciliation of this measure to our net income (loss) attributable to unitholders, please see “Item 6: Selected Financial and Operating Data — Non-GAAP Financial Measures.”

 

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The following table presents a reconciliation of net income (loss) attributable to unitholders to adjusted EBITDA for the years indicated:
Reconciliation of net income (loss) attributable to Oxford Resource Partners, LP unitholders to adjusted EBITDA
                         
    Years Ended December 31,  
    2010     2009     2008  
    (in thousands)  
Net Income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (7,351 )   $ 23,504     $ (2,482 )
 
                       
PLUS:
                       
Interest expense, net of interest income
    9,499       6,449       7,658  
Depreciation, depletion and amortization
    42,329       25,902       16,660  
Contract termination and amendment expenses, net
    652              
Non-cash equity-based compensation expense
    942       472       468  
Non-cash (gain) loss on asset disposals
    1,228       1,177       (1,407 )
Change in fair value of future asset retirement obligations
    5,742       4,991       4,560  
 
                       
LESS:
                       
Gain on purchase of business
          3,823        
Amortization of below-market coal sales contracts
    1,424       1,705       771  
 
                 
 
                       
Adjusted EBITDA (1)
  $ 51,617     $ 56,967     $ 24,686  
 
                 
 
     
(1)   For our definition of adjusted EBITDA, which is a non-GAAP financial measure, and for a reconciliation of this measure to our net income (loss) attributable to unitholders, please see “Item 6: Selected Financial and Operating Data — Non-GAAP Financial Measures.”

 

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The following table presents a reconciliation of net income (loss) attributable to unitholders to adjusted EBITDA and distributable cash flow for the period indicated:
Reconciliation of net income (loss) attributable to Oxford Resource Partners, LP unitholders to adjusted EBITDA and distributable cash flow
         
    Second Half of  
    2010  
    (in thousands)  
Net Income (loss) attributable to Oxford Resource Partners, LP unitholders
  $ (4,957 )
 
       
PLUS:
       
Interest expense, net of interest income
    5,634  
Depreciation, depletion and amortization
    23,997  
Contract termination and amendment expenses, net
    652  
Non-cash equity-based compensation expense
    486  
Non-cash loss on asset disposals
    776  
Change in fair value of future asset retirement obligations
    3,198  
 
       
LESS:
       
Amortization of below-market sales contracts
    (399 )
 
     
 
       
Adjusted EBITDA (1)
  $ 29,387  
 
       
LESS:
       
Cash interest expense, net of interest income
    (3,531 )
Estimated reserve replacement expenditures
    (2,635 )
Other maintenance capital expenditures
    (14,695 )
 
     
 
       
Distributable cash flow (1)
  $ 8,526  
 
     
 
     
(1)   The calculation of adjusted EBITDA and distributable cash flow as presented in our quarterly filing for the period ended September 30, 2010 was modified, and such changes are reflected herein, to conform to the current definition of these non-GAAP financial measures. We do not calculate distributable cash flow with respect to periods beginning prior to the second half of 2010 during which we were a publicly traded partnership.
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Overview. For the year ended December 31, 2010, coal production increased 27.8% to 7.5 million tons from 5.8 million tons in 2009. Our tons sold increased 29.2% to 8.1 million tons in 2010 from 6.3 million tons in 2009. During 2010, 96% of tons sold were under long-term coal sales contracts. Total revenue for the year ended December 31, 2010 was $356.6 million compared to $293.8 million for 2009. The full year 2010 net loss was $7.4 million, or $0.45 per diluted limited partner unit, compared to the full year 2009 net income of $23.5 million, or $2.08 per diluted limited partner unit. Net income in 2009 was positively impacted by a temporary price increase and a gain on purchase of business of $13.3 million and $3.8 million, respectively. The 2010 net loss included higher depreciation, depletion and amortization (DD&A) of $16.4 million, primarily due to the full year impact of DD&A from our 2009 acquisition of Phoenix Coal’s active Illinois Basin surface mining assets in western Kentucky and the partial year impact of DD&A from our purchase of previously leased and additional major mining equipment using the proceeds from our initial public offering and borrowings under our $175 million credit facility.
Additional factors affecting comparability for each year and their impact on our net income (loss) are as follows:
Year Ended December 31, 2010
    $13.3 million reduction in net income resulting from the expiration of a temporary price increase with a major customer.
    $16.4 million increase in DD&A with $7.9 million of this amount resulting from the full-year impact of the increase in DD&A associated with the Illinois Basin assets acquired from Phoenix Coal and the remainder from the purchase of previously leased and additional major mining equipment using proceeds from our initial public offering and borrowings under our credit facility.

 

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Year Ended December 31, 2009
    $13.3 million increase in net income resulting from a temporary price increase with a major customer.
    $3.8 million increase in net income resulting from the gain on purchase of business that resulted from the acquisition of Illinois Basin assets from Phoenix Coal.
Coal Production. Our tons of coal produced increased 27.8% to 7.5 million tons in 2010 from 5.8 million tons in 2009. This increase was primarily due to a full year of coal production of 1.7 million tons in 2010 as compared to 0.4 million tons in 2009 from our Muhlenberg County complex in the Illinois Basin that we acquired on September 30, 2009, as well as a 6.8% increase in production from our Northern Appalachia mining complexes. While overall coal production increased, production was adversely affected by delays in receiving the Rose France permit at our Muhlenberg County complex, adverse geological conditions at our Plainfield mine and overall higher strip ratios.
Sales Volume. Our sales volume increased 29.2% to 8.1 million tons in 2010 from 6.3 million tons in 2009. This increase was primarily attributable to the full year’s coal sales of 1.6 million tons from our Muhlenberg County complex in the Illinois Basin that we acquired on September 30, 2009.
Average Sales Price Per Ton. Our average sales price per ton decreased 5.1% to $38.22 in 2010 from $40.27 in 2009. The $2.05 per ton decrease was primarily attributable to the full-year impact of the lower-priced coal sales contracts assumed in connection with our acquisition of Illinois Basin assets on September 30, 2009 and the absence of the temporary price increase realized in 2009.
Coal Sales Revenue. Our coal sales revenue for 2010 increased by $57.4 million, or 22.6%, compared to 2009. This increase was primarily attributable to a full year of coal sales of $74.3 million in 2010 as compared to $21.0 million in 2009 from our Muhlenberg County complex in the Illinois Basin and higher coal sales volumes delivered to our major utility customers served by our Northern Appalachia operations. Reducing the impact of the year-over-year increase was the inclusion in 2009 of $13.3 million of revenue relating to the temporary price increase previously discussed.
Royalty and Non-Coal Revenue. Our royalty and non-coal revenue includes our royalty revenue from subleasing our underground coal reserves to a third party, revenue from the sale of limestone that we recover in connection with our coal mining operations and various fees we receive for performing related services for others. Our royalty and non-coal revenue decreased to $6.5 million in 2010 from $7.2 million in 2009. This decrease was primarily attributable to a $1.7 million temporary royalty reduction from our underground coal reserves that are subleased, as mining occurred during a portion of 2010 on a small piece of property surrounded by our reserves that was not subject to our royalty. In late September 2010, royalty-generating mining activity resumed on our underground coal reserves. This decrease was partially offset by an increase of $1.0 million in non-coal revenue.
Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 34.4% to $229.5 million in 2010 from $170.7 million in 2009. This increase was primarily attributable to the increase of 27.8% in our tons produced, principally from our Muhlenberg County complex in the Illinois Basin. Our average cost of coal sales per ton increased by 4.8% to $30.94 in 2010 compared to $29.52 in 2009. This increase resulted in part from higher operating costs due to the delay of the Rose France mine permit, adverse geologic conditions at our Plainfield mine and higher strip ratios, as well as higher repair and maintenance expenses.
Cost of Purchased Coal. Cost of purchased coal increased to $22.0 million in 2010 from $19.5 million in 2009. This increase was primarily attributable to higher volumes purchased under a long-term coal purchase contract assumed in our acquisition of Illinois Basin assets. Our average cost of purchased coal per ton decreased by 18.5% to $30.00 in 2010 due to a significant portion of our purchases in 2010 being supplied under the long-term coal purchase contract compared to a high percentage of higher-priced spot market purchases in 2009.
Depreciation, Depletion and Amortization (DD&A). DD&A expense in 2010 was $42.3 million compared to $25.9 million in 2009, an increase of $16.4 million. Approximately $7.9 million of this increase related to higher DD&A expense associated with the assets we acquired our acquisition of Illinois Basin assets, and the remaining increase of $8.5 million related primarily to higher depreciation on equipment placed in service in late 2009 and the depreciation on the previously leased and additional major mining equipment that we purchased, all of which purchases were made with proceeds from our initial public offering and borrowings under our $175 million credit facility.

 

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Selling, General and Administrative Expenses (SG&A). SG&A expenses for 2010 were $14.8 million compared to $13.2 million for 2009, an increase of $1.6 million. This increase was primarily due to an increase of $1.0 million in public company expenses and $0.6 million of additional administrative expenses for supporting our Muhlenberg County complex in the Illinois Basin.
Contract Termination and Amendment Expenses, Net. Contract termination and amendment expenses, net for 2010 were $0.7 million compared to zero for 2009. These expenses result from the $2.5 million expense related to the termination of an advisory services agreement with certain affiliates of AIM Oxford in connection with our initial public offering, partially offset by a $1.8 million reduction in a specific reserve for a below-market coal supply contract assumed in our acquisition of Illinois Basin assets that was amended to reset the price to a market rate starting in 2010.
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 revenue and expenses for 2010 increased 18.5% compared to 2009 due to higher coal sales revenue.
Interest Expense. Interest expense for 2010 was $9.5 million compared to $6.5 million for 2009, an increase of $3.0 million. This increase was primarily due to an amendment to our prior $115 million credit facility in September 2009 in connection with our acquisition of Illinois Basin assets that resulted in higher borrowings outstanding and higher effective interest rates during the first half of 2010. In addition, the non-cash mark-to-market adjustment for the interest rate swap agreement increased interest expense by $1.8 million for 2010 compared to 2009.
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 2010, the net income attributable to noncontrolling interest was $6.7 million compared to $5.9 million for 2009. Net income attributable to noncontrolling interest for 2009 included a non-recurring $0.9 million payment received from a customer that terminated a long-term coal sales contract.
Adjusted EBITDA. Adjusted EBITDA for 2010 was $51.6 million versus $57.0 million for 2009. Adjusted EBITDA for 2009 was positively impacted by the aforementioned $13.3 million temporary price increase and a $3.8 million gain on the purchase of a business that resulted from the acquisition of the Illinois Basin assets from Phoenix Coal.
Distributable Cash Flow. Our distributable cash flow for the last half of 2010 during which we were a publicly traded partnership was $8.5 million. We do not calculate distributable cash flow for periods prior to becoming a publicly traded partnership, so there was no comparable amount for 2009.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Overview. For the year ended December 31, 2009, coal production increased 14.9% to 5.8 million tons from 5.1 million tons in 2008. Our tons sold increased 14.2% to 6.3 million tons in 2009 from 5.5 million tons in 2008. During 2009, 98% of tons sold were under long-term coal sales contracts. Total revenue for the year ended December 31, 2009 was $293.8 million compared to $230.5 million for 2008. The full year 2009 net income was $23.5 million, or $2.08 per diluted limited partner unit, compared to the full year 2008 net loss of $2.5 million, or $0.24 per diluted limited partner unit. Our financial performance in 2009 reflected one quarter’s contribution from the Illinois Basin assets that we acquired on September 30, 2009. Additionally, our 2009 results related to our Northern Appalachia operations included a temporary price increase which positively impacted our net income and adjusted EBITDA for 2009 by $13.3 million. Excluding the temporary price increase, our results for 2009 would have included net income attributable to our unitholders of $10.2 million and adjusted EBITDA of $43.7 million.

 

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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 of 0.4 million tons due to our acquisition of Illinois Basin assets and higher production at certain of our Northern Appalachia mining complexes.
Sales Volume. Our sales volume increased 14.2% to 6.3 million tons in 2009 from 5.5 million tons in 2008. The increase in the sales volume in 2009 was primarily attributable to the 0.6 million tons we sold during the fourth quarter of 2009 as a result of our acquisition of Illinois Basin assets.
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 temporary increase in the price per ton in 2009 which resulted in additional revenue of $13.3 million and increased our average sales price per ton by $2.10. Our financial results for 2009 also included $2.1 million of contract buyout fees from a customer that had a $0.33 per ton favorable impact on our average sales price for 2009.
Coal Sales Revenue. Our coal sales revenue 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 $13.3 million related to the temporary price increase in 2009 from a major customer. Approximately $21.0 million of this increase was attributable to the increase in our tons sold resulting from of our acquisition of Illinois Basin assets.
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 that we sublease of $3.2 million partially offset by decreases in other revenue of $1.0 million.
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 sold, partially offset by lower operating costs per ton. During 2009, our cost of coal sales per ton decreased 1.0% primarily as a result of lower fuel, oil and explosives prices partially offset by higher operating lease expenses and higher contract labor costs.
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 purchased coal 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. This increase was due to higher quality coal being purchased at higher prices in 2009 as opposed to 2008.
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 $6.6 million of this increase and the Illinois Basin assets we acquired in 2009 accounted for $1.6 million of this increase. Depletion and amortization increased during 2009 by approximately $1.0 million as a result of the 14.9% increase in coal production.
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 our acquisition of Illinois Basin assets and $1.0 million of legal fees incurred in renegotiating our prior $115 million 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 prior $115 million 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 deferred financing costs associated with our prior $115 million credit facility which was amended to accommodate our acquisition of Illinois Basin assets.

 

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Gain on Purchase of Business. On September 30, 2009, we acquired all of the active Illinois Basin 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 increases in both tons sold and average sales price realized by Harrison Resources in 2009 compared to 2008.
Adjusted EBITDA. Adjusted EBITDA for 2009 was $57.0 million compared to $24.7 million for 2008. Adjusted EBITDA for 2009 was positively impacted by the aforementioned $13.3 million temporary price increase and a $3.8 million gain on purchase of business that resulted from the acquisition of the Illinois Basin assets from Phoenix Coal.
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, credit facility borrowings and contributions from our partners.
The principal indicators of our liquidity are our cash on hand and availability under our $175 million credit facility, which is described under “— Credit Facility” below. Going forward, we expect our sources of liquidity to include:
    our working capital;
    cash generated from operations;
    borrowing capacity under our $175 million 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 years indicated:
                         
    Years Ended December 31,  
    2010     2009     2008  
    (in thousands)  
 
                       
Net cash provided by (used in):
                       
Operating activities
  $ 40,268     $ 38,637     $ 33,992  
Investing activities
    (84,894 )     (49,171 )     (23,942 )
Financing activities
    42,149       (1,279 )     4,494  
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009. Net cash provided by operating activities was $40.3 million for 2010 compared to $38.6 million for 2009.
Net cash used in investing activities was $84.9 million for 2010 compared to $49.2 million for 2009. This $35.7 million increase was primarily attributable to the $52.5 million of newly purchased property and equipment in 2010 partially offset by $18.3 million used in connection with our acquisition of Illinois Basin assets in 2009.
Net cash provided by financing activities was $42.1 million for 2010 compared to net cash used in financing activities of $1.3 million for 2009. This $43.4 million increase was primarily attributable to net proceeds from our initial public offering of $144.4 million partially offset by an increase of $73.2 million in distributions to partners and non-controlling interest, a net reduction in borrowings of $12.5 million, a decrease of $11.5 million in contributions from partners and debt issuance costs of $3.8 million.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Net cash provided by operating activities was $38.6 million for 2009 compared to $34.0 million for 2008. This $4.6 million increase was primarily due to the combined effects of the $26.0 million increase in net income (loss) attributable to our unitholders and higher non-cash adjustments of $10.5 million, partially offset by a decrease in the cash provided by changes in assets and liabilities of $31.7 million. One of the major contributors to this decrease in cash provided by changes in assets and liabilities was a $13.3 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.
Net cash used in investing activities was $49.2 million for 2009 compared to $23.9 million for 2008. This $25.3 million increase was attributable to the $18.3 million we spent in connection with our acquisition of Illinois Basin assets, $3.1 million primarily relating to increases in the purchases of coal properties and mine development costs and a decrease of $3.9 million of proceeds from the sale of property and equipment during 2009 as compared to 2008.
Net cash used in financing activities was $1.3 million for 2009 compared to net cash provided by financing activities of $4.5 million for 2008. This $5.8 million decrease was primarily attributable to $3.7 million of cash distributions to the noncontrolling interest in Harrison Resources and $1.8 million of debt issuance costs during 2009 compared to 2008.
Credit Facility
In connection with our initial public offering, we paid off the amounts outstanding under our $115 million credit facility and we entered into our $175 million credit facility. Our $175 million credit facility provides for a $60 million term loan and a $115 million revolving credit facility. As of December 31, 2010, we had borrowings of $90 million outstanding under our $175 million credit facility, consisting of a $57 million term loan and borrowings of $33 million on the revolving credit facility. We also use our $175 million credit facility to collateralize letters of credit related to surety bonds securing our reclamation obligations. As of December 31, 2010, we had letters of credit outstanding in support of these surety bonds of $6.7 million.

 

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The term loan and revolver will mature in 2014 and 2013, respectively, and borrowings bear interest at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin are each defined in the credit agreement that evidences our $175 million credit facility). We used a portion of the borrowings under our $175 million credit facility and a portion of our initial public offering proceeds to purchase all of the equipment we had under operating leases, which reduced operating lease expenses beginning in the third quarter of 2010.
Borrowings under our $175 million credit facility are secured by a first-priority lien on and security interest in substantially all of our assets. Our $175 million credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, make distributions to our unitholders, make ordinary course dispositions of assets over predetermined levels or enter into equipment leases, as well as enter into a merger or sale of all or substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries. Our $175 million credit facility also requires compliance with certain financial covenant ratios, including limiting our leverage ratio (the ratio of consolidated indebtedness to adjusted EBITDA) to no greater than 2.75 : 1.0 and limiting our interest coverage ratio (the ratio of adjusted EBITDA to consolidated interest expense) to no less than 4.0 : 1.0. In addition, we are not permitted under our $175 million credit facility to fund capital expenditures in any fiscal year in excess of certain predetermined amounts.
The events that constitute an event of default under our $175 million credit facility include, among other things, failure to pay principal and interest when due, breach of representations and warranties, failure to comply with covenants, voluntary bankruptcy or liquidation and a change of control.
Contractual Obligations
We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations as of December 31, 2010 were as follows:
                                         
    Payment Due by Period  
                                    More  
            1 Year     1 - 3     3 - 5     than  
    Total     or Less     Years     Years     5 Years  
    (in thousands)  
 
                                       
Long-term debt obligations
  $ 90,000     $ 6,000     $ 84,000     $     $  
Future interest obligations — long-term debt (1)
    13,491     $ 4,836     $ 8,655              
Other long-term debt (2)
    12,986       1,249       11,732       5        
Future interest obligations — other long-term debt
    1,453       719       734              
Fixed-price diesel fuel purchase contracts
    26,457       26,457                    
Operating lease obligations
    2,199       537       1,581       78       3  
Long-term coal purchase contract (3)
    61,848       12,847       29,401       19,600        
 
                             
Total
  $ 208,434     $ 52,645     $ 136,103     $ 19,683     $ 3  
 
                             
 
     
(1)   Interest on variable rate long-tem debt was calculated using rates estimated by us at December 31, 2010 for the remaining term of outstanding borrowings.
 
(2)   Represents various notes payable with interest rates ranging from 4.6% to 6.75%.
 
(3)   We assumed a long-term coal purchase contract as a result of our acquisition of Illinois Basin assets. Please read Note 10 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Long-Term Debt.”
Capital Expenditures
Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental laws and 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 cash expenditures for the purchase of fee interests in coal reserves and cash expenditures for advance royalties with respect to the acquisition of leasehold interests in coal reserves. Examples of other maintenance capital expenditures include capital expenditures associated with the repair, refurbishment and replacement of equipment, the development of new mines and reclamation upon mine closures. 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.

 

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For 2011, we expect to incur between $37.0 million and $40.0 million in reserve replacement expenditures and other maintenance capital expenditures. However, at December 31, 2010, we did not have any material commitments for 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 $175 million credit facility, issuance of debt and equity securities and/or other external sources of financing.
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.
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 bond obligations. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with bank 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 December 31, 2010, we had approximately $34.9 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $6.7 million in bank letters of credit. Our management believes these bonds and bank 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.
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 heavy and/or extended periods of rain, snow or floods, can impact our ability to mine and ship our coal, and our customers’ ability to take delivery of coal.
Critical Accounting Policies and Estimates
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” discusses our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Our management regularly reviews our accounting policies to make certain they are current and also to provide readers of our consolidated financial statements with useful and reliable information about our operating results and financial condition. These include, but are not limited to, matters related to accounts receivable, inventories, pension benefits and income taxes. Implementation of these accounting policies includes estimates and judgments by management based on historical experience and other factors believed to be reasonable. This may include judgments about the carrying value of assets and liabilities based on considerations that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

 

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Our management believes the following critical accounting policies are most important to the portrayal of our financial condition and results of operations and require more significant judgments and estimates in the preparation of our consolidated financial statements.
Use of Estimates
In order to prepare financial statements in conformity with 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 revenues and expenses during the reporting period. The most significant areas requiring the use of management estimates and assumptions relate to amortization calculations using the units-of-production method, asset retirement obligations, useful lives for depreciation of fixed assets and estimates of fair values of assets and liabilities. 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.
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.
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 including overhead and stripping costs incurred prior to the production phase, which commences when saleable coal beyond a de minimus amount is produced.
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 coal reserves through purchases or leases. We deplete our coal reserves using the units-of-production method on the basis of tonnage mined in relation to total estimated recoverable tonnage with residual surface values classified as land and not depleted. At December 31, 2010 and 2009, 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.
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 us, the costs are capitalized as mine development costs. Capitalization of mine development costs continues until more than a de minimis amount of saleable coal is extracted from the mine. Amortization of these mine development costs is then initiated using the units-of-production method based upon the total estimated recoverable tonnage.

 

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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 an offset or credit against royalties payable on future production. Amortization of leased coal interests is computed using the units-of-production method over 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, interest rate swap agreements and an interest rate cap agreement. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.
We used interest rate swap agreements 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 agreements required us to receive a variable interest rate and pay a fixed interest rate. Our interest rate swap agreements and their variable rate financings were based upon LIBOR. We had an interest rate cap agreement that set an upper limit on LIBOR that we would have to pay under the terms of our existing credit facility. This agreement expired on December 31, 2010. We did not elect hedge accounting for any of these agreements and, therefore, 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 agreements 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 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Fair Value of Financial Instruments.”
Our other financial instruments include fixed price forward contracts for diesel fuel. Our risk management policy requires us to purchase up to 75% of our unhedged 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 usually have a term of one year or less.
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 by accelerating the depletion rate. 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. There were no indicators of impairment present during the years ended December 31, 2010, 2009 and 2008. Accordingly, no impairment losses were recognized during any of these years.
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 the establishment of credit facilities and amortize such costs to interest expense over the term of the credit facility using the effective 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 purchase accounting for our acquisitions of Oxford Mining Company and Phoenix Coal. These intangible assets are being amortized over their expected useful lives. See the “Coal Sales Contracts” section of Note 2 and Note 7 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for further details under the headings “Summary of Significant Accounting Policies” and “Intangible Assets and Liabilities,” respectively.

 

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Asset Retirement Obligations
Our asset retirement obligations, or AROs, arise from 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 is 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, estimate future reclamation costs and make assumptions regarding the mine’s productivity. These cash flows are discounted at a 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 established, the offset is capitalized to the producing mine asset. Over time, the ARO liability is accreted to its present value, and the capitalized cost is depleted using the units-of-production method 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, a portion 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 acreage disturbed during the current year. At December 31, 2010, we had recorded ARO liabilities of $13.0 million, including amounts reported as current liabilities. On an aggregate undiscounted basis, we estimate the cost of final mine closure to be approximately $15.4 million.
Income Taxes
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 and no liability was recognized. 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 dock, 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 $13.3 million 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, $2.1 million of the prepayment remained on our balance sheet as deferred revenue and was fully recognized in 2010.

 

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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 landfill earth moving and transportation 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 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 were purchasing the output of this mine and no royalty was due on purchases by 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 December 31, 2010, 2009 and 2008, we received royalties of $2.8 million, $4.5 million and $1.3 million, respectively.
Below-Market Coal Sales Contracts
Our below-market coal sales contracts were acquired through our acquisition of Illinois Basin assets in 2009 and were coal sales contracts for which the prevailing market price for coal specified in the contract 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 are amortized into coal sales on the basis of tons shipped over the terms of the respective contracts.
Equity-Based Compensation
We account for equity-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. Equity-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. Prior to our initial public offering (see the Initial Public Offering section in Note 1 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Organization and Presentation”), the fair value of our LTIP units was determined based on the sale price of our limited partner units in arm’s-length transactions. Subsequent to our initial public offering, the unit price fair value is determined based on the closing sales price of our units on the New York Stock Exchange on the grant date. See Note 13 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Long-Term Incentive Plan.”
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. Prior to our initial public offering (see the Initial Public Offering section in Note 1 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Organization and Presentation”), limited partner units were separated into Class A and Class B units to prepare for a potential transaction such as an initial public offering. In connection with and since our initial public offering, our limited partner units were converted to and are maintained as common units and subordinated units.
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 antidilutive and therefore not included in the earnings per unit calculation.
General Partner Units: Basic earnings per unit are computed by dividing net income attributable to our general partner by the weighted average units outstanding during the reporting period. Diluted earnings per unit for our general partner 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. In years of a loss, the phantom units are antidilutive and therefore not included in the earnings per unit calculation.

 

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New Accounting Standards Issued
In August 2009, the Financial Accounting Standards Board, or 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 (a “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 guidance did not impact our consolidated financial statements.
In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures — Improving Disclosures about Fair Value Measurements. This guidance requires reporting entities to make new disclosures about recurring or non-recurring 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 for Level 1 and Level 2 reconciliation disclosures and effective December 31, 2010 for Level 3 reconciliation disclosures. The adoption of this guidance did not have a material effect on our consolidated financial statements.
In December 2010, the FASB issued ASU 2010-29, Business Combinations — Disclosure of Supplementary Pro Forma Information for Business Combinations. This guidance requires a public entity to disclose the revenue and earnings of the combined entity in its consolidated financial statements as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This guidance also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination(s) included in the reported pro forma revenue and earnings. These amendments are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 31, 2010. Early adoption of the guidance is permissible. We do not believe this guidance will have a material impact on our consolidated financial statements.
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk includes risks that arise from changes in interest rates, foreign currency exchange rates, commodity prices, equity prices and other market changes that affect market-sensitive instruments. We believe our principal market risks are commodity price risks and interest rate risks.
Commodity Price Risks
We sell most of the coal we produce under long-term coal sales contracts. Historically, we have principally managed the commodity price risks from our coal sales by entering into long-term coal sales contracts of varying terms and durations, rather than through the use of derivative instruments.
We believe that the price risks associated with our diesel fuel purchases is significant. 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 $0.30 per gallon for diesel fuel would have increased net income attributable to our unitholders by $0.4 million for 2010. This hypothetical increase in income results from the fuel escalation clauses contained within our long-term coal sales contracts and fixed price physical fuel purchase contracts.

 

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Interest Rate Risk
We are exposed to interest rate risks as borrowings under our $175 million credit facility are at variable rates. We manage our interest rate risks from time to time through interest rate swap and/or interest rate cap agreements.
On August 2, 2010, we entered into an interest rate swap agreement that had an original notional principal amount of $50 million and a maturity of January 31, 2013. The notional principal amount declines over the term of the interest rate swap agreement at a rate of $1.5 million each quarter that corresponds to our required principal payments on the term loan under our $175 million credit facility. Under the interest rate swap agreement, we pay interest monthly at a fixed rate of 1.39% per annum and receive interest monthly at a variable rate equal to LIBOR (with a 1% floor) based on the notional principal amount. The interest rate swap agreement was effective August 9, 2010. The derivative liability is recorded in other liabilities and increased by $0.1 million in 2010.
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 had an effective date of January 4, 2010 and a notional amount of $50.0 million and provided for a LIBOR interest rate cap of 2% using the three month LIBOR. This interest rate cap agreement expired on December 31, 2010.
The variable interest rate on our debt under the $175 million credit facility, at December 31, 2010, was 5.25%, calculated at the 30-day LIBOR rate, subject to a floor of 1.0%, plus the applicable margin of 4.25%. Based on our current 2011 borrowings, a hypothetical 100 basis point increase in short term interest rates would result, over the subsequent twelve-month period, in a reduction of approximately $0.1 million in income or cash flows. The current 30 day LIBOR is approximately 74 basis points below the 1% LIBOR floor. As a result the $0.1 million hypothetical reduction noted above represents the current 30 day LIBOR interest rate as adjusted for the impact of the hypothetical 100 basis point increase less the 1% LIBOR floor, or an increase of 26 basis points from our current interest rate. This estimate is based upon the current level of variable debt and assumes no changes in the composition of that debt.
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated balance sheets as of December 31, 2010 and 2009 and the related consolidated statements of operations, partners’ equity and cash flows for the years ended December 31, 2010, 2009 and 2008, together with the report of the independent registered public accounting firm thereon, appear on pages F-1 through F-31 hereof and are incorporated herein by reference.
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.   CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this Report on Form 10-K pursuant to Securities Exchange Act of 1934 Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2010, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

 

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Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of the Registered Public Accounting Firm
This Annual Report on Form 10-K does not include management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.   OTHER INFORMATION
None.

 

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PART III
ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Partnership 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. Our general partner 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. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner is 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 general partner’s board of directors has seven directors, three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner’s board of directors has affirmatively determined that Messrs. Tywoniuk, Lilly and Messey are independent as described in the rules of the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.
Directors and Executive Officers
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 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
    75     Chairman of the Board
Charles C. Ungurean
    61     Director, President and Chief Executive Officer
Jeffrey M. Gutman
    45     Senior Vice President, Chief Financial Officer and Treasurer
Gregory J. Honish
    54     Senior Vice President, Operations
Thomas T. Ungurean
    59     Senior Vice President, Equipment, Procurement and Maintenance
Daniel M. Maher
    65     Senior Vice President, Chief Legal Officer and Secretary
Michael B. Gardner
    55     General Counsel and Assistant Secretary
Denise M. Maksimoski
    36     Senior Director of Accounting
Brian D. Barlow
    40     Director
Matthew P. Carbone
    44     Director
Gerald A. Tywoniuk
    49     Director
Peter B. Lilly
    62     Director
Robert J. Messey
    65     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, LP, 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.

 

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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 received a B.A. in general studies from Ohio University and is a Certified Surface Mine Foreman in Ohio.
Mr. Ungurean’s 38 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.
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 a Certified Surface Mine Foreman in Ohio. 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.
Daniel M. Maher was elected Senior Vice President and Chief Legal Officer of our general partner on August 1, 2010 and Secretary of our general partner on December 9, 2010. Mr. Maher had been a partner in the Columbus, Ohio office of the international law firm of Squire, Sanders & Dempsey L.L.P. from March of 1988 to December 31, 2010 and prior thereto he had been an associate and then partner with the predecessor firm to Squire Sanders since June of 1972. He is a licensed attorney in Ohio with more than 38 years of experience in representing various clients in corporate, financial, merger and acquisition, contractual, real property, litigation and other legal matters. He received a J.D. from the University of Virginia and a B.S. from the United States Merchant Marine Academy. While Mr. Maher was elected and has served full-time as an officer of our general partner since August 1, 2010, he did not commence employment with our general partner until January 1, 2011. For that period in 2010 during which he served as an officer, we made aggregate payments of $225,000 to Squire Sanders under an engagement letter between Squire Sanders and our general partner relating to such services.
Michael B. Gardner has served as General Counsel of our general partner since September 2007 and as Assistant Secretary of our general partner since December 9, 2010. Mr. Gardner served as our Secretary from September 2007 until December 8, 2010. 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. Mr. Gardner serves on the Board of Directors of the Ohio Coal Association and Kentucky Coal Association and serves as a trustee on the Energy and Mineral Law Foundation Governing Member Organization for the Ohio Coal Association. He is also a member of the American Corporate Counsel Association, Northeast Ohio Chapter, and the Cleveland Metropolitan Bar Association. Mr. Gardner received a J.D. from Case Western Reserve University, an MBA from Ashland University and a B.S. in Environmental Biology (Botany Emphasis), cum laude, from Ohio University.

 

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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 and a member and the chairman of the Compensation Committee.
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 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 Plan Representative for the plan of liquidation of Pacific Energy Resources Ltd., which was an oil and gas acquisition, exploitation and development company and is now completing its plan of liquidation. Mr. Tywoniuk joined Pacific Energy Resources Ltd. in June 2008 as Senior Vice President, Finance and he was appointed Chief Financial Officer in August 2008. He was also appointed acting Chief Executive Officer in September 2009. He held these positions as an employee until May 2010. Mr. Tywoniuk joined Pacific Energy Resources Ltd. in June 2008 to help the management team work through the company’s financially distressed situation. The board of the company elected to file for Chapter 11 protection in March 2009. In December 2009, the company completed the sale of its assets, and is now working through the remaining steps of liquidation.

 

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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 has 29 years of experience in accounting and finance, including 12 years as the Chief Financial Officer of three public companies and 4 years as Vice President/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 a member of the board of directors of our general partner, a member of the Compensation Committee and a member and the chairman of the Audit Committee. With respect to the Audit Committee, he also qualifies as an “audit committee financial expert.”
Peter B. Lilly was elected as a member of the board of directors of our general partner in June 2010. Prior to joining the board of directors of our general partner, since February 2009 he has been a part-time consultant relating to the coal industry international market and has also focused on investments in commercial real estate through his company, Harm Group, LLC. Before that, Mr. Lilly was an executive officer with CONSOL Energy Inc., the largest producer of high-Btu bituminous coal in the United States. Mr. Lilly joined CONSOL Energy in October 2002 as Chief Operating Officer and served as President — Coal Group from February 2007 until his retirement in January 2009. Prior to joining CONSOL Energy, Mr. Lilly served as President and Chief Executive Officer of Triton Coal Company LLC and Vulcan Coal Holdings LLC from 1998 to 2002. Between 1991 and 1998, Mr. Lilly was with Peabody Holding Company, Inc., where he served as President and Chief Operating Officer from 1995 to 1998, Executive Vice President from 1994 to 1995 and President of Eastern Associated Coal Corporation from 1991 to 1994. He is a former board member of the National Coal Association, the American Mining Congress and the World Coal Institute and a former chairman of the Safety Committee of the National Mining Association. Mr. Lilly is currently a member of Harm Group, LLC, which serves as a consultant to financial analysts on issues related to the coal industry.
Mr. Lilly received a B.S. in General Engineering and Applied Science from the U.S. Military Academy at West Point in 1970 and served in the U.S. Army until 1975. He obtained an MBA from Harvard Business School in 1977.
Mr. Lilly’s 30 plus years of experience in the coal industry, much of it in significant executive management positions, provide him with the necessary skills to serve as a member of the board of directors of our general partner, a member of the Audit Committee and a member of the Compensation Committee.
Robert J. Messey was elected as a member of the board of directors of our general partner in October 2010. He has been an independent management consultant since April 2008. Before that, Mr. Messey served as senior vice president and chief financial officer of Arch Coal (NYSE:ACI), one of the largest U.S. coal producers, from December 2000 until April 2008. Prior to Arch Coal, he served from 1993 as chief financial officer of Sverdrup, a large privately held engineering, architecture, construction and technology services firm, until its acquisition in 1999 by Jacobs Engineering Group, Inc. (NYSE:JEC), one of the largest global firms providing engineering, architecture, construction and technology services. After such acquisition, Mr. Messey served as vice president of financial services with Jacobs until November 2000. He attended Washington University in St. Louis, Missouri, where he received a Bachelor of Science degree in business administration. He is a Certified Public Accountant. Mr. Messey was with the public accounting firm of Ernst & Young from 1968 to 1992, and during that period served as an SEC Audit Partner from 1981 to 1992. He currently serves as a director and audit committee chairperson on the board of Stereotaxis (NASDAQ:STXS), and additionally serves on the compensation committee of Stereotaxis’ board. As well, Mr. Messey currently serves on the advisory board of Mississippi Lime Company, a non-public trust, and is chairperson of the audit committee and serves on the compensation committee of that advisory board.
Mr. Messey has over 40 years of experience in accounting and finance, including 8 years as the Chief Financial Officer of a public company, 6 years as the Chief Financial Officer of a large privately held company and 11 years as an SEC audit partner. His extensive accounting, financial and executive management experience, as well as his in-depth knowledge of the mining industry generally, provide him with the necessary skills to be a member of the board of directors of our general partner, a member of the Audit Committee and a member of the Compensation Committee. With respect to the Audit Committee, he also qualifies as an “audit committee financial expert.”

 

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Corporate Governance
The board of directors of our general partner has adopted corporate governance guidelines to assist it in the exercise of its responsibilities to provide effective governance over our affairs for the benefit of our unitholders. In addition, we have adopted a code of business conduct and ethics, which sets forth legal and ethical standards of conduct for all our officers, directors and employees. The corporate governance guidelines, the code of business conduct and ethics and the charters of our audit and compensation committees are available on our website at www.OxfordResources.com and in print without charge to any unitholder who requests any of them. A unitholder may make such a request in writing by mailing such request to Brian A. Meilton at Investor Relations, Oxford Resource Partners, LP, 41 South High Street, Suite 3450, Columbus, Ohio 43215, or by emailing such request to Mr. Meilton at bmeilton@OxfordResources.com. Amendments to, or waivers from, the code of business conduct and ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the code of business conduct and ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.
Conflicts Committee
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, consisting solely of independent directors, determines 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 NYSE and the Exchange Act.
Audit Committee
The board of directors of our general partner has established an audit committee, or Audit Committee, that complies with the NYSE requirements and Section 3(a)(58)(A) of the Exchange Act. Our general partner is generally required to have at least three independent directors serving on its board at all times. Gerald A. Tywoniuk, Peter B. Lilly and Robert J. Messey are our independent directors and serve as the members of the Audit Committee. The board has determined that Mr. Tywoniuk, who serves as the chairman of the Audit Committee, and also Mr. Messey, each have such accounting or related financial management expertise sufficient to qualify him as an audit committee financial expert in accordance with Item 401 of Regulation S-K.
The Audit Committee meets on a regularly-scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing and the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by SAS 114 (Communications with Audit Committees), and makes recommendations to the board of directors of our general partner regarding the inclusion of our audited financial statements in this Annual Report on Form 10-K.
The Audit Committee is authorized to recommend periodically to the board of directors any changes or modifications to its charter that the Audit Committee believes may be required or desirable.
Compensation Committee
The board of directors of our general partner has established a Compensation Committee. The Compensation Committee establishes standards and makes recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our officers and other employees, including the performance standards or other restrictions pertaining to the vesting of any such awards, under our long-term incentive plan. Brian D. Barlow, Peter B. Lilly, Robert J. Messey and Gerald A. Tywoniuk serve as the members of the Compensation Committee. Mr. Barlow serves as the chairman of the Compensation Committee.

 

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Meeting of Non-Management Directors and Communications with Directors
At each quarterly meeting of our general partner’s board of directors, all of our independent directors meet in an executive session without management participation or participation by non-independent directors. Mr. Tywoniuk, the chairman of the Audit Committee, presides over these executive sessions.
Our general partner’s board of directors welcomes questions or comments about us and our operations. Unitholders or interested parties may contact the board of directors, including any individual director, by contacting the Secretary of our general partner at dmaher@OxfordResources.com or at the following address and fax number; Name of the Director(s), c/o Secretary, Oxford Resource Partners, LP, 41 South High Street, Suite 3450, Columbus, Ohio 43215, 614-754-7100.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our general partner’s board of directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner’s officers, directors and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2010.
ITEM 11.   EXECUTIVE COMPENSATION
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 for the fiscal year ended December 31, 2010 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, General Counsel and Assistant Secretary.
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 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 granted under the Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan, or our LTIP, which are meant to align our executive officers’ interests with those of our unitholders and our long-term performance.

 

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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 members of the Board who were not employees of our general partner, or the Non-employee Directors. In connection with our initial public offering in 2010, we revised certain policies and practices with respect to executive compensation. In particular, the Board 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 adherence to our compensation philosophies and that the total compensation paid to our executive officers is fair, reasonable and competitive;
    reviewing base salary levels for our executive officers and determining any adjustments thereto;
    assessing the individual performance of our Chief Executive Officer, or CEO, and our other named executive officers and their contributions to our company-wide performance, and determining the annual bonuses to be provided to our executive officers for a given year after taking into account target bonus levels set forth in executive officers’ employment agreements or otherwise established at the outset of the year; and
    determining the types, amounts and vesting terms of awards to be provided to our executive officers under our LTIP.
The compensation programs for our executive officers consist of base salaries, annual incentive bonuses and awards under our LTIP, in the form of equity-based phantom units, as well as other customary employment benefits. In making compensation determinations, the Compensation Committee and the Board consider the recommendations of our CEO with respect to the other executive officers. The total compensation of our executive officers and the components and relative emphasis among components of their annual compensation are reviewed on at least an annual basis by the Compensation Committee with any proposed changes recommended to the Board for final approval.
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;
    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 and cooperation on the one hand and executive compensation on the other hand.

 

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Taking account of the foregoing objectives, we structured total 2010 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, dependent on our performance and individual performance of the executives, in the form of discretionary annual bonuses. We also sought 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. Prior to and during 2010, we did not make regular annual grants of awards under our LTIP. Instead, such awards had 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. In January 2011 but relating to performance in 2010, we made, and in the future we expect to regularly make, equity-based awards as a part of our annual compensation decision-making process.
Compensation decisions for individual executive officers were 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 and responsibilities. In measuring the contributions of executive officers and our performance, a variety of financial measures were considered, including non-GAAP financial measures used by management to assess our financial performance. Historically and in 2010, the Board has used and did use 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 “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities — Cash Distribution Policy.” In addition, an evaluation of the individual performance of each of the executive officers was taken into consideration.
In making individual compensation decisions, the Board historically has not relied and in 2010 did not rely on pre-determined performance goals or targets. Instead, determinations regarding compensation were the result of the exercise of judgment based on all reasonably available information and, to that extent, were discretionary. Each executive officer’s current and prior compensation was considered in setting compensation for 2010. The amount of each executive officer’s current compensation was considered as a base against which determinations were made as to whether increases were appropriate to retain the executive officer in light of competition or in order to provide continuing performance incentives. The Board retained and exercised its discretion to adjust 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 had historically relied upon the judgment and industry experience of the 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. For the 2010 performance period, the Compensation Committee made compensation recommendations to the Board based upon trends occurring within our industry, including from a peer group of companies that our Compensation Committee 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, Rhino Resource Partners LP, Vanguard Natural Resources, LLC, Global Partners LP, Legacy Reserves LP, Copano Energy LLC, Suburban Propane Partners LP and Crosstex Energy Inc. Although the Board and our Compensation Committee reviewed compensation data relating to our peer group of companies, they do not and did not benchmark compensation at any particular level relative to our peer group.

 

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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 in the form of base salaries. 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 fixed 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. Trends for our peer group are taken into account in setting 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 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 in four annual installments is designed to facilitate retention of our executive officers.
 
       
Retirement Plan
  Qualified 401(k) retirement plan benefits are available for our executive officers and all other regular full-time employees.   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.

 

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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 Non-employee Directors, in alignment with these considerations and with reference to industry survey data, to ensure the attraction, development and retention of superior talent. For base salary changes in 2010 and going forward, base salary determinations focused and will continue to focus on the above considerations and also were made and will 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 prior year. Future adjustments to base salaries and salary ranges will reflect average movement in the competitive market as well as individual performance. Prior to our initial public offering, annual base salary adjustments, if any, for the CEO were determined by the Non-employee Directors. Since our initial public offering, annual base salary adjustments for the CEO have been and will be approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Prior to our initial public offering, annual base salary adjustments, if any, for the other executive officers were determined by the Board taking into account input from the CEO. Since our initial public offering, annual base salary adjustments for the other executive officers have been and 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 2010. Effective July 19, 2010, base salary increases were provided to each of the 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 executive officer’s performance since his last salary increase, considering a variety of factors, none of which was individually material to such assessment, to reflect increased levels of responsibility following our initial public offering, and to ensure that the base salaries for the executive officers remained competitive with other companies in our industry. The Board considered the salary levels of comparable executive officers in our peer group, and used those salary levels as a check against their conclusions regarding salaries for our executive officers but did not benchmark compensation at any particular level relative to our peer group.
                         
    Base Salary at Start     Base Salary Increase     2010 Base Salary  
Name   of 2010     in 2010     Following Increase(1)  
Charles C. Ungurean
  $ 375,000     $ 125,000     $ 500,000  
Jeffrey M. Gutman
    260,000       10,000       270,000  
Thomas T. Ungurean
    225,000       50,000       275,000  
Gregory J. Honish
    150,000       35,000       185,000  
Michael B. Gardner
    145,000       20,000       165,000  
(1)   There have been no changes in base salaries at the start of 2011 and to date, except that the base salary of Gregory J. Honish has been increased by $25,000 to $210,000 effective January 1, 2011. This increase was approved by the Board based upon the recommendation of the Compensation Committee, which had determined that the increase was warranted to remain competitive for comparable positions with other companies in our industry and to reward performance.
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. Prior to our initial public offering, annual incentive awards, if any, for the CEO were determined by the Non-employee Directors. Since our initial public offering, annual incentive awards, if any, for the CEO have been and will be approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Prior to our initial public offering, annual incentive awards, if any, for the other executive officers were determined by the Board taking into account input from the CEO. Since our initial public offering, annual incentive awards for the other executive officers have been and will be approved by the Board based upon recommendations from the Compensation Committee, which recommendations may take into account input from the CEO.

 

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For our executive officers, target bonus amounts are set forth in their employment agreements, which are discussed in more detail under “— Employment and Severance Arrangements” below. The employment agreements for the executive officers provide for their eligibility to receive annual incentive bonuses in an amount up to 50% (66.6% in the case of Charles C. Ungurean and Thomas T. Ungurean) of their annual base salaries, or such other greater percentage as may be approved by the Non-employee Directors (in the case of Charles C. Ungurean) or the Board (in the case of our other executive officers), in any such case based on the recommendations of the Compensation Committee. Notwithstanding such target bonus amounts, the Compensation Committee, Non-employee Directors and Board have broad discretion to maintain, reduce or increase the award amounts when making their final bonus recommendations and determinations.
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 are determined on a discretionary basis and generally are based on a subjective evaluation referencing individual, company-wide and industry performance criteria. The Board and the Compensation Committee believe that this approach to assessing performance results in a more comprehensive evaluation for compensation decisions. The Board and the Compensation Committee recognize the following factors in making recommendations and determinations of discretionary annual incentive bonuses (without assigning any particular weighting to any factor):
    financial performance for a given fiscal year, including the level of achievement of our cash distribution target for the year as discussed below;
    distribution performance for a given fiscal year compared to the peer group;
    unitholder total return for a given fiscal year compared to the peer group;
    competitive compensation data for executive officers in the peer group;
    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 are considered to be the most appropriate measures upon which to base the annual incentive cash bonus decisions because the Compensation Committee and our Board believe that they help to align individual compensation with competency and contribution and that they most directly correlate to increases in long-term value for our unitholders.
The Board and the Compensation Committee retain broad discretion with respect to the amount of each 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 based on the industry knowledge and experience of the Non-employee Directors and review of the compensation levels of our peer group, and to address the Board’s (and in the case of the CEO the Non-employee Directors’) assessment of each executive officer’s individual performance and contributions to our overall success. Based on these considerations, the Board (and in the case of the CEO the Non-employee Directors) determined to award the incentive bonus amounts set forth in the table below to our executive officers for performance in 2010. These bonus awards in all cases represented 45% of the applicable executive’s base salary, and as compared to the target bonus amounts set forth in their employment agreements these awards represented approximately 68%-90% of the applicable target bonus amounts. These final amounts were ultimately determined based on an assessment of what was fair and competitive total cash compensation for each executive officer in light of our cash distribution performance for 2010, the individual executive officer’s level of responsibility within our organization and the view of the Compensation Committee and the Board (and in the case of the CEO the Non-employee Directors) of each executive officer’s contributions to our success for 2010.

 

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Name   2010 Bonus  
Charles C. Ungurean
  $ 225,000  
Jeffrey M. Gutman
    121,500  
Thomas T. Ungurean
    123,750  
Gregory J. Honish
    83,250  
Michael B. Gardner
    74,250  
Equity-Based Awards
Design. Our LTIP was originally adopted in 2007 in connection with our formation and amended and restated in July of 2010 in connection with our initial public offering. In adopting our 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 our LTIP promotes a long-term focus on results and aligns executive and unitholder interests.
Our 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-based grants are used to incentivize performance that leads to enhanced unitholder value, encourage retention and closely align the executive officers’ and key employees’ interests with unitholders’ interests. Equity-based 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.
Phantom Units. The only awards made under our LTIP since its adoption have been phantom units. A phantom unit is a notional unit granted under our 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. Historically, including in 2010, we have always issued common units 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.
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 our LTIP to the Compensation Committee with the exception 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. Annual equity compensation grants, if any, for the CEO are approved by the Non-employee Directors based upon recommendations from the Compensation Committee. Annual equity compensation grants for the other executive officers are 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 2010. In January 2010, Jeffrey M. Gutman received an award of 27,285 phantom units in recognition of his performance in connection with a restructuring of certain of our indebtedness and the completion of the acquisition of Illinois Basin assets from Phoenix Coal in September 2009. In making this award, the Board also took into account its determination that the initial equity-based 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.

 

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As part of its determination to make regular equity-based awards to our named executive officers as part of their annual compensation package, the Board approved awards of phantom units which were granted to the named executive officers on January 1, 2011 in the amounts set forth in the table below. These awards, although granted in 2011, were intended as a part of the named executive officers’ 2010 compensation and were granted to reward the named executive officers for performance in 2010. The Board determined the amount of the awards such that the phantom unit awards represent a total of 10% of each named executive officers’ total compensation for 2010 (inclusive of base salaries, target bonuses and phantom unit awards). In addition, the Board determined at that time to award further phantom units to Gregory J. Honish after determining that the initial equity-based awards granted to him in 2007 were below the level of equity participation appropriate for his position with and contributions to us, based on an assessment of Mr. Honish’s scope of responsibility within our organization and an understanding of the equity participation of comparable executives at other companies in our peer group.
                 
    Value of     Number of  
Name   Phantom Units (1)     Phantom Units  
Charles C. Ungurean
  $ 92,227       3,786  
Jeffrey M. Gutman
    45,017       1,848  
Thomas T. Ungurean
    50,742       2,083  
Gregory J. Honish (2)
    80,851       3,319  
Michael B. Gardner
    27,502       1,129  
 
     
(1)   The number of phantom units was determined based on the closing trading price of our common units on December 31, 2010 so that the number of phantom units corresponding to the number of our common units having a value equal to the indicated dollar amount were granted.
 
(2)   The portion of the units related to 2010 performance was 1,266 units valued at $30,840, with the remainder of the units consisting of 2,053 units valued at $50,011 being to adjust his level of equity participation as described above.
In connection with the closing of our initial public offering, Mr. Gutman was issued 5.979201 Class B Units, representing a 0.44% equity interest, in our general partner pursuant to his employment agreement. The issuance of such equity interest was made to Mr. Gutman in satisfaction of our general partner’s prior commitment to provide such an equity interest upon the consummation of such an offering.
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 such contributions are discretionary, we intend generally to make annual contributions at that level or higher, subject to applicable IRS limits. For each of 2010 and 2011, we 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 such employees 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 payments made to the named executive officers in 2010 are included in bonus amounts and set forth in a footnote to the Summary Compensation Table below.

 

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Recoupment Policy
We currently do not have a formal compensation recoupment policy applicable to annual incentive bonuses, equity awards or other compensation. The Compensation Committee has reviewed and is anticipating legislative and regulatory developments with respect to such a policy and intends to adopt such a policy consistent with applicable legal and regulatory requirements and securities exchange listing standards 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 employment agreements with our executive officers. These employment agreements have two year terms, provide for the base salary and target bonus amounts for each executive officer and contain severance arrangements that we believe are appropriate to encourage the continued attention and dedication of members of our management. 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.”
Compensation Committee Report
We have reviewed and discussed with management certain compensation discussion and analysis provisions to be included in this Annual Report on Form 10-K for the year ended December 31, 2010 to be filed pursuant to Section 13(a) of the Securities and Exchange Act of 1934, or this Annual Report on Form 10-K. Based on that review and discussion, we recommend to the Board that the compensation discussion and analysis provisions be included in this Annual Report on Form 10-K.
Compensation Committee
Brian D. Barlow, Chairman
Peter B. Lilly
Robert J. Messey
Gerald A. Tywoniuk
Risk Assessment in Compensation Programs
Management of our general partner, with the support of our human resources, finance and legal departments, has assisted the Compensation Committee and the Board in analyzing the potential risks arising from our compensation policies and practices, and management, the Compensation Committee and the Board have all determined that there are no such risks that are reasonably likely to have a material adverse effect on us.

 

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Summary Compensation Table
The following table sets forth certain information with respect to the compensation paid to the named executive officers for the periods indicated.
                                                 
                            Unit     All Other        
            Salary     Bonus     Awards     Compensation        
Name and Principal Position   Year     ($)(1)     ($)(2)     ($)(3)     ($)(4)     Total ($)  
Charles C. Ungurean
    2010       432,212       253,846               13,691       699,749  
President and Chief Executive Officer
    2009       375,002       248,077               18,888       641,967  
Jeffrey M. Gutman
Senior Vice President, Chief Financial
    2010       265,423       141,500       295,883       14,820       717,626  
Officer and Treasurer
    2009       261,385       125,481               15,370       402,236  
Thomas T. Ungurean
                                               
Senior Vice President, Equipment,
    2010       247,981       141,057               11,322       400,360  
Procurement and Maintenance
    2009       233,333       190,385               16,572       440,290  
Gregory J. Honish
    2010       166,193       91,580               7,149       264,922  
Senior Vice President, Operations
    2009       142,116       70,096               12,771       224,983  
Michael B. Gardner
    2010       154,404       76,988               6,802       238,194  
General Counsel and Assistant Secretary
    2009       152,083       75,567               13,560       241,210  
 
     
(1)   Amounts shown in this column for 2010 represent salaries paid to the named executive officers in 2010 and include pro-rated amounts based on the increases in salaries that occurred in 2010.
 
(2)   The bonus amounts for the named executive officers for 2010 include and reflect bonuses paid in early 2011 that relate to services performed in 2010, which bonus amounts for each of the named executive officers were as follows: Charles C. Ungurean — $225,000; Jeffrey M. Gutman — $121,500; Thomas T. Ungurean — $123,750; Gregory J. Honish — $83,250; and Michael B. Gardner — $74,250. The bonus amounts also include vacation payments in 2010, as follows: Charles C. Ungurean — $28,846; Jeffrey M. Gutman — $20,000; Thomas T. Ungurean — $17,307; Gregory J. Honish — $8,330; and Michael B. Gardner — $2,738.
 
(3)   Amount shown for Jeffrey M. Gutman reflects the grant date fair value of phantom units awarded under the LTIP to Mr. Gutman in January 2010 of $261,117, as well as an estimate of the grant date fair value of the Class B units in our general partner granted to Mr. Gutman in connection with the consummation of our initial public offering, of $34,766, each as described in more detail under the heading “Compensation Discussion and Analysis — Equity Based Awards” above, and each as determined in accordance with FASB ASC Topic 718.
 
(4)   Amounts shown in this column for 2010 include contributions being made to our 401(k) savings plan for each of the named executive officers with respect to services performed in 2010, payments made in 2010 with respect to life insurance benefits provided to each of the named executive officers, a holiday-related allowance paid in 2010 to each of the named executive officers, the taxable portion of automobile allowances paid to Jeffrey M. Gutman and Gregory J. Honish, and the dues paid for Charles C. Ungurean and Jeffrey M. Gutman for a dining and athletic club facility located in the same building as our executive offices. 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 amounts shown for 2010 also include the cost to us of providing an automobile to them for their use for the estimated personal usage portion thereof for commuting purposes (11% 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 $1,977 and $1,239, respectively.

 

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Grants of Plan-Based Awards for 2010
The following table provides information regarding grants of plan-based awards to named executive officers for the year ended December 31, 2010.
                         
            All Other Unit     Grant Date Fair  
            Awards: Number     Value of Unit  
Name   Grant Date     of Units (#)     Awards ($)  
Jeffrey M. Gutman
    1/1/10       27,285 (1)     261,117 (2)
Senior Vice President, Chief Financial Officer and Treasurer
    7/19/10       5.979201 (3)     34,766 (4)
 
     
(1)   Amount shown is the number of phantom units granted to Jeffrey M. Gutman on January 1, 2010, as adjusted for a unit split that occurred in connection with our initial public offering.
 
(2)   Amount shown is based on the grant date fair market value of our common units of $17.43 ($9.57 after adjustment for a unit split that occurred in connection with our initial public offering).
 
(3)   Amount shown is the number of Class B units of our general partner granted to Jeffrey M. Gutman in connection with our initial public offering. The units represent a 0.44% profits interest in our general partner.
 
(4)   Amount shown is an estimate of the grant date fair market value of the Class B units, as determined in accordance with FASB ASC Topic 718.
Outstanding Equity-Based Awards at December 31, 2010
The following table provides information regarding outstanding equity-based awards held by the named executive officers as of December 31, 2010. All such equity-based awards consist of phantom units granted under our LTIP, other than the Class B units in our general partner held by Jeffrey M. Gutman. Neither Charles C. Ungurean nor Thomas T. Ungurean held any outstanding equity-based awards at December 31, 2010. None of the named executive officers hold outstanding option awards.
                         
    Unit Awards  
    Number of              
    Phantom     Number of     Market Value  
    Units That     Class B Units     of Units That  
    Have Not     That Have     Have Not  
    Vested     Not Vested     Vested  
Name   (#)(1)     (#)(2)     ($)(3)  
Jeffrey M. Gutman
    33,981               827,777  
Senior Vice President, Chief Financial Officer and Treasurer
            5.979201       45,890  
Gregory J. Honish
Senior Vice President, Operations
    4,669               113,737  
Michael B. Gardner
General Counsel and Assistant Secretary
    2,917               71,058  
 
     
(1)   As to Mr. Gutman’s unvested units, 6,821 units, 6,822 units and 6,821 units vest on January 1, 2011 and the next two anniversaries thereof, respectively, and the remaining 13,517 units will vest on March 31, 2011. Messrs. Honish’s and Gardner’s unvested units, which were granted in 2007, will vest on December 1, 2011.
 
(2)   Amount shown is the number of Class B units of our general partner granted to Mr. Gutman in connection with our initial public offering. These units vest 25% on the first anniversary of the July 19, 2010 grant date and an additional 25% on each of the next three subsequent anniversaries of that grant date.
 
(3)   For phantom units, based on the closing price of our common units of $24.36 on December 31, 2010; for Class B units, reflects an estimate of the fair market value of the Class B units of our general partner as of December 31, 2010, as determined in accordance with FASB ASC Topic 718.
In addition to these outstanding equity-based awards at December 31, 2010, there were additional equity-based awards on January 1, 2011 as described above under “Equity-Based Awards — Equity-Based Awards for 2010.”

 

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Units Vested in 2010
The following table shows the phantom unit awards that vested during 2010. Charles C. Ungurean and Thomas T. Ungurean did not hold or vest in any phantom unit awards in 2010 and none of the named executive officers held or exercised any stock options in 2010.
                 
    Number of        
    Units     Value  
    Acquired on     Realized on  
Name   Vesting (#)     Vesting ($)  
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and Treasurer(1)
    20,342       194,711  
Gregory J. Honish
Senior Vice President, Operations(2)
    4,669       102,531  
Michael B. Gardner
General Counsel and Assistant Secretary(2)
    2,917       64,057  
 
     
(1)   Of these units, 6,822 units vested on January 1, 2010 and 13,520 units vested on March 31, 2010, and the value realized amount reflects a unit value of $9.57 per unit, the fair market value on each such vesting date (all after adjustment for a unit split that occurred in connection with our initial public offering).
 
(2)   Units vested on December 1, 2010, and the value realized amounts reflect a unit value of $21.96 per unit, the closing price on such vesting date.
Pension Benefits
The named executive officers do not participate in any defined benefit pension plans and received no pension benefits during the year ended December 31, 2010.
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, 2010.
Potential Payment Upon Termination or Change in Control
Employment Agreements with Named Executive Officers
Our general partner has entered into employment agreements with each of Messrs. Charles C. Ungurean, Gutman, Thomas T. Ungurean, Honish and Gardner, which became effective upon the closing of our initial public offering, and which replaced and superseded our named executive officers’ existing employment agreements that were entered into prior to 2009. Each of these new employment agreements has an initial term of two years. 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 agreements establish customary employment terms including base salaries, bonuses and other incentive compensation and other benefits. For information regarding the base salaries and other compensation to be provided under the new employment agreements, please refer to the discussion above under “Compensation Discussion and Analysis — Employment and Severance Arrangements.”

 

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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 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, in each case, during the term of the agreement 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. Under the employment agreements, 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 base salary. All 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 of employment 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 coal mining business in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia and Virginia until August 24, 2014. In the cases of Messrs. Honish, Gardner and Gutman, those provisions apply during the term of their respective employment with our general partner and continue for a period of 12 months following termination of employment for any reason if such termination occurs during the term of the employment agreement and not in connection with the expiration of the employment agreement.

 

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The following table shows the value of the severance benefits and other benefits for the named executive officers under the new employment agreements, assuming each named executive officer had terminated employment on December 31, 2010.
                             
        Death or     Termination     Resignation for  
        Disability     Without Cause     Good Reason  
Name   Payment Type   ($)     ($)     ($)  
Charles C. Ungurean
  Cash severance           $ 1,000,000     $ 1,000,000  
 
  Benefit Continuation   $ 25,854       25,854          
 
  Total     25,854       1,025,854       1,000,000  
Thomas T. Ungurean
  Cash severance             550,000       550,000  
 
  Benefit Continuation     22,055       22,055          
 
  Total     22,055       572,055       550,000  
Jeffrey M. Gutman
  Cash severance             270,000       270,000  
Gregory J. Honish
  Cash severance             185,000       185,000  
Michael B. Gardner
  Cash severance             165,000       165,000  
Our named executive officers other than Mr. Gutman are not entitled to any additional payments or benefits upon the occurrence of a change in control with respect to us or our general partner. Mr. Gutman’s employment agreement provides that, upon the occurrence of a change in control with respect to us or our general partner, all of the awards granted to Mr. Gutman under our LTIP that have not vested as of the date of the change in control will immediately vest. Assuming that a change in control with respect to us or our general partner had occurred on December 31, 2010, Mr. Gutman would have been entitled to accelerated vesting with respect to 33,981 phantom units that he held as of such date, having an aggregate market value as of such date of $827,777, based on the closing price of our common units of $24.36 on that date. In addition, in connection with the closing of our initial public offering, Mr. Gutman received 5.979201 Class B units in our general partner representing a profits participation interest in our general partner. The interest vests over the four-year period following the closing of our initial public offering and is subject to accelerated vesting upon a change in control with respect to us or our general partner. Assuming that a change in control with respect to us or our general partner had occurred on December 31, 2010, Mr. Gutman would have been entitled to accelerated vesting with respect to all of such Class B units that he held as of such date, having an estimated aggregate fair market value as of such date of $45,890, determined in accordance with FASB ASC Topic 718.
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 for purposes of the plan 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 of directors. In addition, other members of the board of directors that are not employees of our general partner can be approved by the board of directors 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 receives 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.
In addition, each non-employee director receives per meeting fees of:
    $1,000 for board meetings attended in person;
    where applicable, $500 for committee meetings attended in person; and
    $500 for telephonic board meetings and committee meetings greater than one hour in length.

 

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In addition, in connection with the initial election of a non-employee director, the board of directors of our general partner 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 of their compensation under the plan, as outlined above, in the form of unrestricted common units granted under our 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. The annual compensation package is paid to each non-employee director based on his or her service for the period beginning upon the date of his or her appointment to the board. If a non-employee director’s service 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 is also paid in quarterly installments of units having equivalent fair market value on the date of issuance to one fourth of the total annual grant value described above. 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 to receive units in lieu of cash compensation, are granted under our 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 2010
The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2010, as described above. None of our non-employee directors held any unvested units as of December 31, 2010.
                         
    Fees Earned or              
Name   Paid in Cash ($)     Unit Awards ($)(1)     Total ($)  
Gerald A. Tywoniuk
  $ 53,000     $ 50,003     $ 103,003  
Peter B. Lilly
  $ 33,000     $ 75,018     $ 108,018  
Robert J. Messey
  $ 17,500     $ 62,526     $ 80,026  
 
     
(1)   The amount in this column represents the value of unit awards made to directors under our LTIP in 2010. For Gerald A. Tywoniuk, 2,277 units were granted and vested on December 1, 2010 and their market value is based on the closing price of $21.96 per unit on such date; for Peter B. Lilly, 2,703 units were granted and vested on August 18, 2010 and their value is based on the initial public offering price of $18.50 per unit on such date, and the remaining 1,139 units were granted and vested on December 1, 2010 and their market value is based on the closing price of $21.96 per unit on such date; and for Robert J. Messey, 2,472 units were granted and vested on October 8, 2010 and their market value is based on the closing price of $20.23 per unit on such date, and the remaining 570 units were granted and vested on December 1, 2010 and their market value is based on the closing price of $21.96 per unit on such date.
Compensation Committee Interlocks and Insider Participation
Brian D. Barlow, Peter B. Lilly, Gerald A. Tywoniuk and Robert J. Messey serve as the members of the Compensation Committee. Mr. Barlow serves as the chairman of the Compensation Committee. For a description of certain transactions between us and affiliates of Mr. Barlow, see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
The following table sets forth certain information regarding the beneficial ownership of units as March 14, 2011 (the “Ownership Reference Date”) by:
    each person who is known to us to beneficially own 5% or more of such units to be outstanding;
    our general partner;
    each of the directors and named executive officers of our general partner; and
    all of the directors and executive officers of our general partner as a group.

 

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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.
The equity interests of our general partner are comprised of class A units and class B units. The class B units represent only profits interests in our general partner from the date of issuance. The class A units of our general partner are 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 of whom is a member of our management team, and AIM Oxford is owned by AIM Coal LLC and certain investment partnerships affiliated with AIM. The class B units of our general partner are owned 50% by Jeffrey M. Gutman and 50% by Daniel M. Maher, each of whom is a member of our management team.
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 the Ownership Reference Date, 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.

 

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The percentage of units beneficially owned is based on a total of 10,341,416 common units and 10,280,380 subordinated units outstanding as of the Ownership Reference Date.
                                         
                                    Percentage  
                                    of Total  
            Percentage of             Percentage of     Common and  
            Common Units     Subordinated     Subordinated     Subordinated  
    Common Units to     to be     Units to be     Units to be     Units to be  
    be Beneficially     Beneficially     Beneficially     Beneficially     Beneficially  
Name of Beneficial Owner   Owned     Owned     Owned     Owned     Owned  
AIM Oxford Holdings, LLC(1)(2)
    709,143       6.9 %     6,813,160       66.3 %     36.5 %
C&T Coal, Inc.(3)
    360,882       3.5 %     3,467,220       33.7 %     18.6 %
Cushing MLP Opportunity Fund I, LP(4)
    700,000       6.8 %                 3.4 %
Swank Energy Income Advisors, LP (n/k/a Cushing MLP Asset Management, LP(4)(5)
    1,649,100       15.9 %                 8.0 %
Swank Capital, L.L.C.(4)(6)
    1,649,100       15.9 %                 8.0 %
Jerry V. Swank(4)(7)
    1,649,100       15.9 %                 8.0 %
George E. McCown(1)(2)(8)
    709,143       6.9 %     6,813,160       66.3 %     36.5 %
Brian D. Barlow(2)
                             
Matthew P. Carbone(1)(2)(8)
    709,143       6.9 %     6,813,160       66.3 %     36.5 %
Gerald A. Tywoniuk(3)(9)(10)
    5,850       *                   *  
Peter B. Lilly(3)(10)
    10,462       *                   *  
Robert J. Messey(3)(10)
    3,525       *                       *  
Charles C. Ungurean(3)(11)(12)
    360,882       3.5 %     3,467,220       33.7 %     18.6 %
Thomas T. Ungurean(3)(11)(13)
    360,882       3.5 %     3,467,220       33.7 %     18.6 %
Jeffrey M. Gutman(3)(14)
    26,903       *                   *  
Gregory J. Honish(3)(15)
    7,870       *                   *  
Michael B. Gardner(3)(16)
    7,510       *                   *  
All directors and executive officers as a group (consisting of 13 persons)
    1,144,785       10.1 %     10,280,380       100.0 %     55.4 %
 
     
An asterisk indicates that the person or entity owns less than one percent.
 
(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 capacities 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)   The address for this person or entity is 8117 Preston Road, Suite 440, Dallas Texas 75225.
 
(5)   As investment advisor to Cushing MLP Opportunity Fund I, LP (the “Cushing Fund”) and other holders of common units, Swank Energy Income Advisors, LP (n/k/a Cushing MLP Asset Management, LP) (“Cushing Management”) shares voting and investment power over the common units held by the Cushing Fund and certain other private funds and managed accounts (collectively, the “Cushing Management Funds/Accounts”).
 
(6)   As general partner of Cushing Management, Swank Capital, L.L.C. shares voting and investment power over the common units held by the Cushing Fund and the Cushing Management Funds/Accounts.
 
(7)   As principal of Swank Capital, L.L.C., Jerry V. Swank shares voting and investment power over the common units held by the Cushing Fund and the Cushing Management Funds/Accounts.
 
(8)   Each of Messrs. McCown and Carbone disclaim beneficial ownership of the units, except to the extent of any pecuniary interest therein.
 
(9)   A total of 5,367 of these common units are owned by a trust established by Mr. Tywoniuk and his spouse and for which they both serve as trustees. Mr. Tywoniuk disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein.

 

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(10)   The common units shown for Messrs, Tywoniuk, Lilly and Messey include common units which will vest and be issued to them on March 31, 2011. The number of such units which will vest and be issued are estimated because the actual number to be issued to each of them will be dependent upon the closing price for the units on March 31, 2011. Mr. Tywoniuk will have units having a value of $12,500 at such closing price (estimated at 483 units) issued to him, Mr. Lilly will have units having a value of $29,000 at such closing price (estimated at 1,120 units) issued to him and Mr. Messey will have units having a value of $12,500 at such closing price (estimated at 483 units) issued to him. The estimated number of units for each of them has been estimated based on the closing price on the Ownership Reference Date.
 
(11)   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. Each of Charles C. Ungurean and Thomas T. Ungurean disclaim beneficial ownership of the units, except to the extent of any pecuniary interest therein.
 
(12)   Does not include 3,786 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.
 
(13)   Does not include 2,083 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.
 
(14)   Does not include 15,491 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.
 
(15)   Does not include 7,988 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.
 
(16)   Does not include 4,046 common units that could be issuable upon the vesting of phantom units, which phantom units will not vest within 60 days of the Ownership Reference Date.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information concerning common units that may be issued under our LTIP. Our LTIP allows for awards of options, phantom units, restricted units, unit awards, other unit awards and unit appreciation rights. It currently permits the grant of awards covering an aggregate of 2,056,075 units. Our LTIP is administered by the Compensation Committee.
The board of directors of our general partner in its discretion may terminate, suspend or discontinue our LTIP at any time with respect to any award that has not yet been granted. The board of directors of our general partner also has the right to alter or amend our LTIP or any part of our LTIP 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 impair the rights of the participant without the consent of the participant.
The following table summarizes the number of securities remaining available for future issuance under our LTIP as of December 31, 2010.
                         
                    Number of Securities  
                    Remaining Available  
                    for Future Issuance  
    Number of Securities             Under Equity  
    to be Issued Upon     Weighted-Average     Compensation Plans  
    Exercise of     Exercise Price of     (Excluding Securities  
    Outstanding Options,     Outstanding Options,     Reflected in  
Plan Category   Warrants and Rights     Warrants and Rights     Column(a))  
    (a)     (b)     (c)  
Equity compensation plans approved by security holders(1)
        $       1,879,275 (2)
Equity compensation plans not approved by security holders
                 
 
                   
Total
        $       1,879,275 (2)
 
                   
 
     
(1)   Our LTIP was approved by our partners (general and limited) prior to our initial public offering. Our LTIP currently permits the grant of awards covering an aggregate of 2,056,705 units, inclusive of prior award grants, which grants did not and do not require approval by our limited partners.
 
(2)   The number of remaining available units for award grants includes the units that would be issuable upon vesting of a total of 124,480 outstanding phantom units.

 

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ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
C&T Coal owns 360,882 common units and 3,467,220 subordinated units representing a combined 18.6% limited partner interest in us, and AIM Oxford owns 709,143 common units and 6,813,160 subordinated units representing a combined 36.5% limited partner interest in us. C&T Coal and AIM Oxford control our general partner which owns a 2.0% general partner interest in us and all of our incentive distribution rights. The equity interests of our general partner are comprised of class A units and class B units. The class B units represent only profits interests in our general partner from the date of issuance. The class A units of our general partner are owned 33.7% by C&T Coal and 66.3% by AIM Oxford. 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 class B units of our general partner are owned 50% by Jeffrey M. Gutman and 50% by Daniel M. Maher, each of whom is a member of our management team.
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 our ongoing operation and liquidation. 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 our initial public offering
 
   1,458,800 common units;

   10,280,380 subordinated units;

   all of our incentive distribution rights;

   2.0% general partner interest; and

   approximately $76.4 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 98.0% to the unitholders, including affiliates of our general partner, as the holders of an aggregate of 1,458,800 common units and all of the subordinated units and 2.0% to our general partner. If distributions exceed the minimum quarterly distribution and the first target distribution level, our general partner will be entitled to increasing percentages of the distributions, up to 48.0% 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 $0.7 million on the 2.0% general partner interest and approximately $20.5 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 us. 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.
 
   
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.
 
   
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.

 

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Ownership Interests of Certain Executive Officers and Directors of Our General Partner
C&T Coal, AIM Oxford, Jeffrey M. Gutman and Daniel M. Maher collectively own 100.0% 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. 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. Jeffrey M. Gutman is the Senior Vice President, Chief Financial Officer and Treasurer of our general partner and Daniel M. Maher is the Senior Vice President, Chief Legal Officer and Secretary of our general partner.
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 48.0%, of the cash we distribute in excess of $0.6563 per quarter.
Advisory Services Agreement
Upon our formation in August 2007, Oxford Mining Company, LLC 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 members of the board of directors of our general partner. Our advisors performed financial and advisory services for us under this agreement, which was terminated in connection with our initial public offering in exchange for a one-time, non-recurring payment to our advisors of $2.5 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, 2010, excluding and in addition to the one-time, non-recurring payment of $2.5 million, we paid our advisors approximately $210,000 for these services.
Administrative and Operational Services Agreement
On August 24, 2007, we entered into an administrative and operational services agreement with Oxford Mining Company, LLC 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 2010, we paid our general partner approximately $68.2 million for services, primarily related to payroll, performed under the administrative and operational services agreement. Any party may terminate the administrative and operational services agreement by providing at least 30 days’ written notice to the other parties of its intention to terminate the administrative and operational services agreement.
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 our initial public 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.

 

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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 appoint will be reduced if necessary such 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, provided that the number of directors C&T Coal has the right to appoint is not less than one. 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 and subordinated units.
Furthermore, the investors’ rights agreement gives C&T Coal, Charles C. Ungurean and Thomas T. Ungurean tag-along rights to sell their limited partner interests in us in any case where AIM Oxford requires C&T Coal, Charles C. Ungurean and Thomas T. Ungurean, pursuant to the investors’ rights agreement, to sell their interest in our general partner in connection with the sale by AIM Oxford of all of its interests in us and our general partner to a non-affiliated third party. All of the other rights provided for in the investors’ rights agreement related to dispositions of interests in us by AIM Oxford or C&T Coal, Charles C. Ungurean and Thomas T. Ungurean terminated upon the closing of our initial public offering.
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 2010 were approximately $1.4 million.
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 Tunnell Hill Reclamation LLC of future landfills or other waste disposal facilities on such properties.
Chartering of Aircraft Transportation
From time to time for business purposes we charter the use of an airplane from Zanesville Aviation located in Zanesville, Ohio. In each of these cases we are invoiced for and pay the normal amounts that Zanesville Aviation charges any chartering person. T&C Holdco owns an airplane that it leases to Zanesville Aviation and that Zanesville Aviation uses in providing chartering services to its customers including us. Under its lease with Zanesville Aviation, T&C Holdco receives compensation from Zanesville Aviation for the use of T&C Holdco’s airplane. The airplane owned by T&C Holdco was chartered to us on a number of occasions in 2010, and we paid Zanesville Aviation an aggregate of approximately $175,000 for those charters.
Procedures for Review, Approval and Ratification of Related Person Transactions
The board of directors of our general partner has adopted a code of business conduct and ethics that provides 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 provides that our management will make all reasonable efforts to cancel or annul the transaction.
The code of business conduct and ethics provides 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.

 

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The code of business conduct and ethics described above was adopted in connection with the closing of our initial public offering, and as a result the transactions described above were not reviewed under such policy.
Further information required for this item is provided in “Item 1. Business — Overview,” “Item 10. Directors, Executive Officers and Corporate Governance” and Note 19, Related Party Transactions, included in the notes to the audited consolidated financial statements included in “Item 8 — Financial Statements and Supplementary Data.”
ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table sets forth fees and out-of-pocket expenses billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered for the fiscal years ended December 31, 2010 and 2009:
                 
Name   2010     2009  
Audit fees(1) (5)
  $ 332,000     $ 639,000  
Audit-related fees(2)
           
Tax fees(3) (5)
    134,000       145,000  
All other fees(4)
           
 
           
 
               
Total
  $ 466,000     $ 784,000  
 
           
 
     
(1)   Includes fees and expenses for audits of annual financial statements of our subsidiaries (as well as an audit of our financial statements at December 31, 2009 in connection with our initial public offering), reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC.
 
(2)   Includes fees and expense related to consultations concerning financial accounting and reporting standards and services related to the implementation of our internal controls over financial reporting.
 
(3)   Includes fees and expenses related to professional services for tax compliance, tax advice and tax planning.
 
(4)   Consists of fees and expenses for services other than services reported above.
 
(5)   Includes fees and expenses associated with our initial public offering.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee is responsible for the appointment, compensation, retention and oversight of the work of our external auditors; the pre-approval of all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and the establishment of the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP, including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee.

 

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The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for resolution of and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encounter in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
    the external auditors’ internal quality-control procedures;
 
    any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
 
    the independence of the external auditors;
 
    the aggregate fees billed by the external auditors for each of the previous two fiscal years; and
 
    the rotation of the external auditors’ lead partner.
PART IV
ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)1.    Financial Statements. See “Index to Financial Statements” on page F-1.
 
(a)2.    Financial Statement Schedules. Other schedules are omitted because they are not required or applicable, or the required information is included in our consolidated financial statements or related notes.
 
(a)3.    Exhibits. See “Index to Exhibits.”

 

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: March  18, 2011
             
    OXFORD RESOURCE PARTNERS, LP    
 
           
 
  By:   OXFORD RESOURCES GP, LLC, its general partner    
 
           
 
  By:   /s/ CHARLES C. UNGUREAN    
 
     
 
Charles C. Ungurean
   
 
      President and Chief Executive Officer    
 
      (Principal Executive Officer)    
 
           
 
  By:   /s/ JEFFREY M. GUTMAN    
 
     
 
Jeffrey M. Gutman
   
 
      Senior Vice President, Chief Financial Officer and Treasurer    
 
      (Principal Financial Officer)    
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in their indicated capacities, which are with the general partner of the registrant, on the dates indicated.
         
Signature   Title   Date
 
       
/s/ GEORGE E. MCCOWN
 
George E. McCown
  Chairman of the Board    March 18, 2011
 
       
/s/ CHARLES C. UNGUREAN
 
Charles C. Ungurean
  Director, President and Chief
Executive Officer
(principal executive officer)
  March 18, 2011
 
       
/s/ JEFFREY M. GUTMAN
 
Jeffrey M. Gutman
  Senior Vice President, Chief Financial Officer and Treasurer
(principal financial officer)
  March 18, 2011
 
       
/s/ DENISE M. MAKSIMOSKI
 
Denise M. Maksimoski
  Senior Director of Accounting 
(principal accounting officer)
  March 18, 2011
 
       
/s/ BRIAN D. BARLOW
 
Brian D. Barlow
  Director    March 18, 2011
 
       
/s/ MATTHEW P. CARBONE
 
Matthew P. Carbone
  Director    March 18, 2011
 
       
/s/ GERALD A. TYWONIUK
 
Gerald A. Tywoniuk
  Director    March 18, 2011
 
       
/s/ PETER B. LILLY
 
Peter B. Lilly
  Director    March 18, 2011
 
       
/s/ ROBERT J. MESSEY
 
Robert J. Messey
  Director    March 18, 2011

 

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INDEX TO EXHIBITS
         
Exhibit    
Number   Description
       
 
  3.1    
Certificate of Limited Partnership of Oxford Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
       
 
  3.2    
Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP dated July 19, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
       
 
  3.3    
Certificate of Formation of Oxford Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
       
 
  3.4    
Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated January 1, 2011 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on January 4, 2011)
       
 
  10.1A    
Credit Agreement dated as of July 6, 2010 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
       
 
  10.1B    
First Amendment to Credit Agreement and Limited Waiver dated as of July 15, 2010 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
       
 
  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 (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
       
 
  10.3 #  
Employment Agreement between Oxford Resources GP, LLC and Michael B. Gardner (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010 filed on August 10, 2010)
       
 
  10.4 #  
Employment Agreement between Oxford Resources GP, LLC and Jeffrey M. Gutman (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010 filed on August 10, 2010)
       
 
  10.5 #  
Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010 filed on August 10, 2010)
       
 
  10.6 #  
Employment Agreement between Oxford Resources GP, LLC and Charles C. Ungurean (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010 filed on August 10, 2010)
       
 
  10.7 #  
Employment Agreement between Oxford Resources GP, LLC and Thomas T. Ungurean (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010 filed on August 10, 2010)

 

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Exhibit    
Number   Description
       
 
  10.8 #  
Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Michael B. Gardner (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
       
 
  10.9 #  
Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Jeffrey M. Gutman (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
       
 
  10.10 #  
Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gregory J. Honish (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
       
 
  10.11 #  
Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Denise M. Maksimoski (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
       
 
  10.12 #  
Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan dated July 19, 2010 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
       
 
  10.13A #  
Form of Long-Term Incentive Plan Grant Agreement (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
       
 
  10.13B #  
Form of Long-Term Incentive Plan Grant Agreement between Oxford Resources GP, LLC and Jeffrey M. Gutman (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
       
 
  10.14 #  
Non-Employee Director Compensation Plan (incorporated by reference to Exhibit 10.14 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010 filed on August 10, 2010)
       
 
  10.15A #  
Form of Non-Employee Director Compensation Plan Grant Agreement (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
       
 
  10.15B #  
Director Unitholder Agreement, dated December 1, 2009, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gerald A. Tywoniuk (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
       
 
  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 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
       
 
  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 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
       
 
  10.17B    
Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)

 

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Exhibit    
Number   Description
       
 
  10.17C    
Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
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