10-K 1 d264360d10k.htm ANNUAL REPORT Annual Report
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

 

¨ 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

INCORPORATION OR ORGANIZATION)

 

(IRS EMPLOYER

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.   ¨    Yes  x    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.  ¨    Yes  x    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.  x    Yes  ¨    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).  x    Yes  ¨    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.    x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act. (Check one)

 

Large Accelerated Filer   ¨    Accelerated Filer   x
Non-Accelerated Filer   ¨    Smaller Reporting Company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨    Yes  x    No

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 $211,862,000 as of June 30, 2011, based on the reported closing price of the common units as reported on the New York Stock Exchange on such date.

As of March 9, 2012, 10,409,027 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

TABLE OF CONTENTS

 

         Page  

Cautionary Statement About Forward-Looking Statements

     ii   

Glossary of Selected Mining Terms

     iv   
PART I   

Item 1.

  Business      1   

Item 1A.

  Risk Factors      23   

Item 1B.

  Unresolved Staff Comments      43   

Item 2.

  Properties      43   

Item 3.

  Legal Proceedings      45   

Item 4.

  Mine Safety Disclosures      45   
PART II   

Item 5.

  Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities      46   

Item 6.

  Selected Financial and Operating Data      49   

Item 7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      53   

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk      72   

Item 8.

  Financial Statements and Supplementary Data      73   

Item 9.

  Changes in and Disagreements With Accountant on Accounting and Financial Disclosure      74   

Item 9A.

  Controls and Procedures      74   

Item 9B.

  Other Information      76   
PART III   

Item 10.

  Directors, Executive Officers and Corporate Governance      78   

Item 11.

  Executive Compensation      83   

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters      97   

Item 13.

  Certain Relationships and Related Transactions, and Director Independence      100   

Item 14.

  Principal Accountant Fees and Services      103   
PART IV   

Item 15.

  Exhibits and Financial Statement Schedules      104   

 

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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 (“Harrison Resources”), and the ability of Harrison Resources to acquire additional reserves on economical terms from CONSOL Energy Inc. in the future;

 

   

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;

 

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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.

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.

 

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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 19 active surface mines one of which became an active mine in the first quarter of 2012, that are managed as eight mining complexes. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During 2011, we produced 8.0 million tons of coal. During 2011, we sold 8.5 million tons of coal, including 0.4 million tons of purchased coal. As a result, our coal inventory on hand decreased by approximately 0.1 million tons. As is customary in the coal industry, we have entered into long-term coal sales contracts with most 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, 2011, we owned and/or controlled 88.0 million tons of proven and probable coal reserves, of which 63.3 million tons were associated with our surface mining operations and the remaining 24.7 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 2011, we acquired 5.9 million tons of proven and probable coal reserves, an amount approximately equal to 74% of our 2011 production.

The following table summarizes our mining complexes, our coal production for the year ended December 31, 2011 and our coal reserves as of December 31, 2011:

 

            As of December 31, 2011

Mining Complexes

   Production for
the Year Ended
December 31,
2011
     Total
Proven &
Probable
Reserves(1)
     Proven
Reserves(1)
     Probable
Reserves(1)
     Average
Heat
Value
(BTU/lb.)
     Average
Sulfur
Content
(%)
     Primary
Transportation
Methods
     (in million tons)                     

Surface Mining Operations:

                    

Northern Appalachia - (principally Ohio)

                    

Cadiz

     1.7         9.0         9.0         —           11,510         3.4       Barge, Rail

Tuscarawas County

     0.9         6.4         6.4         —           11,630         3.9       Truck

Plainfield

     0.2         5.4         5.4         —           11,530         4.4       Truck

Belmont County

     1.0         9.0         8.7         0.3         11,730         4.1       Barge

New Lexington

     0.8         4.7         4.4         0.3         11,580         4.0       Rail

Harrison(3)

     0.8         4.3         4.1         0.2         11,990         1.8       Barge, Rail, Truck

Noble County (2)

     0.4         2.4         2.2         0.2         11,180         4.6       Barge, Truck

Illinois Basin (Kentucky)

                    

Muhlenberg County

     2.2         22.1         21.4         0.7         11,327         3.5       Barge, Truck
  

 

 

    

 

 

    

 

 

    

 

 

          

Total Surface Mining Operations

     8.0         63.3         61.6         1.7            
  

 

 

    

 

 

    

 

 

    

 

 

          

Underground Coal Reserves:

                    

Northern Appalachia (Ohio)

                    

Tusky(4)

        24.7         19.3         5.4         12,900         2.1      
     

 

 

    

 

 

    

 

 

          

Total Underground Coal Reserves

        24.7         19.3         5.4            
     

 

 

    

 

 

    

 

 

          

Total

        88.0         80.9         7.1            
     

 

 

    

 

 

    

 

 

          

 

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(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)

We added one new mine at our Noble County Complex since December 31, 2011, which is reflected in the table above. The new mine replaced a mine which we closed in December 2011.

(3)

The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL Energy. We own 51% of Harrison Resources and CONSOL Energy owns the remaining 49% through one of its subsidiaries. Because the results of operations of Harrison Resources are included in our consolidated financial statements for the year ended December 31, 2011 as required by U.S. generally accepted accounting principles, or GAAP, coal production and proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100% of Harrison Resources. Please read “– 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 39 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 acquired the active surface mining operations of Phoenix Coal Corporation (“Phoenix Coal”). 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 from 2011 through 2035 by 5.7%, 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 2011, coal-fired power plants produced approximately 44.0% of all electric power generation and steam coal accounted for 93% 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 19 active surface mines one of which became an active mine in 2012, 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 fourteen 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 both Northern Appalachia and the Illinois Basin, 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. These 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 five 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; and

 

   

our Stonecreek coal crushing facility located in Tuscarawas County, Ohio.

 

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

 

LOGO

 

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

 

LOGO

 

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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, 2011, 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, 2011 and for the years indicated:

 

     Transportation Facilities Utilized    Transportation    Number of
Active
     Tons Produced for the
Years Ended
December 31,
 

Mining Complex

   River Terminal    Rail Loadout    Method(1)    Mines      2011      2010      2009  
                           (in millions)  

Cadiz

   Bellaire    Cadiz    Barge, Rail      4         1.7         1.4         1.1   

Tuscarawas County

   —      —      Truck      5         0.9         0.9         0.9   

Plainfield

   —      —      Truck      1         0.2         0.3         0.5   

Belmont County

   Bellaire    —      Barge      3         1.0         1.1         1.3   

New Lexington

   —      New Lexington    Rail      1         0.8         0.6         0.6   

Harrison(3)

   Bellaire    Cadiz    Barge, Rail, Truck      1         0.8         1.0         0.7   

Noble County (2)

   Bellaire    —      Barge, Truck      1         0.4         0.5         0.3   
           

 

 

    

 

 

    

 

 

    

 

 

 

Total

              16         5.8         5.8         5.4   
           

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Barge means transported by truck to our Bellaire river terminal and then transported to the customer by barge. Rail means transported by truck to a rail facility and then transported to the customer by rail. Truck means transported to the customer by truck.

(2) 

We added one new mine at our Noble County Complex since December 31, 2011, which is reflected in the table above. The new mine replaced a mine which we closed in December 2011.

(3) 

The Harrison mining complex is owned by Harrison Resources, our joint venture with CONSOL Energy. We own 51% of Harrison Resources and CONSOL Energy owns the remaining 49% 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% 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 currently consists of the Daron, Bundy, Ellis 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, 2011, the Cadiz mining complex included 9.0 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes two coal crushers, 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 the area, contour, auger and highwall miner methods of surface mining. This mining complex produced 1.7 million tons of coal for the year ended December 31, 2011.

Tuscarawas County Mining Complex. The Tuscarawas County mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and currently consists of the Stonecreek, Stillwater, Lisbon, Strasburg and East Canton 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, 2011, the Tuscarawas County mining complex included 6.4 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes three coal crushers with truck scales, Stonecreek and Strasburg blending facilities and the Strasburg wash plant. Coal produced from the Tuscarawas County mining complex is transported by truck 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, 2011.

 

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Plainfield Mining Complex. The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and currently consists of the Otsego 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, 2011, the Plainfield mining complex included 5.4 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes our Barb Tipple blending and coal crushing facility and truck scale. 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 0.2 million tons of coal for the year ended December 31, 2011.

Belmont County Mining Complex. The Belmont County mining complex is located in Belmont County, Ohio, and currently consists of the Lafferty, 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, 2011, the Belmont County mining complex included 9.0 million tons of proven and probable coal reserves. Coal produced from this 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 1.0 million tons of coal for the year ended December 31, 2011.

New Lexington Mining Complex. The New Lexington mining complex is located in Perry, Athens and Morgan Counties, Ohio, and currently 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, 2011, the New Lexington mining complex included 4.7 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, auger and highwall miner method of surface mining. This mining complex produced 0.8 million tons of coal for the year ended December 31, 2011.

Harrison Mining Complex. The Harrison mining complex is located in Harrison County, Ohio, and currently consists of the Harrison mine. Mining operations at this mining complex began in 2007. The Harrison mining complex is owned by Harrison Resources. We own 51% of Harrison Resources and CONSOL Energy owns the remaining 49% 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, 2011 as required by GAAP, coal production and proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100% of Harrison Resources.

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, 2011, the Harrison mining complex included 4.3 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 0.8 million tons of coal for the year ended December 31, 2011.

 

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Noble County Mining Complex. The Noble County mining complex is located in Noble and Guernsey Counties, Ohio, and currently consists of the Shuman mine. 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, 2011, the Noble County mining complex included 2.4 million tons of proven and probable coal reserves. Coal produced from this 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. The Noble County mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.4 million tons of coal for the year ended December 31, 2011.

Illinois Basin

We operate one surface mining complex in the Illinois Basin, which is located in western Kentucky. For the year ended December 31, 2011, this mining complex produced an aggregate of 2.2 million tons of steam coal. The following table provides summary information regarding our mining complex in the Illinois Basin as of December 31, 2011 and for the year then ended:

 

                            Tons Produced for the  
                       Years Ended
December 31,
     Quarter Ended
December 31,
 

Mining Complex

   River Terminal    Rail Loadout    Method(1)    Mines      2011      2010      2009 (2)  
                           (in millions)  

Muhlenberg County

   Island    —      Barge, Truck      3         2.2         1.7         0.4   

 

(1) 

Barge means transported by truck to our Island river terminal and then transported to the customer by barge. Truck means transported to the customer by truck.

(2) 

We acquired this mining complex in October of 2009.

Muhlenberg County Mining Complex. The Muhlenberg County mining complex is located in Muhlenberg and McClean Counties, in western Kentucky, and currently consists of the Schoate, Highway 431, 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, 2011, the Muhlenberg County mining complex included 22.1 million tons of proven and probable coal reserves. The infrastructure at this mining complex includes four coal crushers and our Island river terminal. Coal produced from this mining complex is usually crushed at the mine site and then trucked to our Island river terminal on the Green River or directly to the customer. Coal trucked to our Island river terminal is then transported to the customer by barge. This mining complex uses the area method of surface mining. This mining complex produced 2.2 million tons of steam coal during the year ended December 31, 2011.

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 13 years remaining on the lease for our underground coal reserves, and our sublessee has 13 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, 2011, we had

 

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approximately $38.5 million in surety bonds and $14,000 in cash bonds outstanding to secure the performance of our reclamation obligations. Additionally, as of December 31, 2011, our surety bonds were supported by approximately $7.5 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.

Approximately 79% 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 AMD Inventory List. 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 $224,000 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. Three 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.

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. During 2011 we produced and sold 0.9 million tons of limestone, and our revenues for the year ended December 31, 2011 included $3.5 million in limestone sales.

Based on estimates from our internal engineers, our Cadiz mining complex has 6.4 million tons of proven and probable limestone reserves as of December 31, 2011. 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 2011, we generated $2.6 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 and leasing fees we earned for providing earth-moving services for and leasing equipment to Tunnell Hill Reclamation, LLC, a landfill operator and subsidiary of Tunnel Hill Partners, LP, an entity owned by our sponsors;

 

   

service fees we earned for hauling and disposing of ash at a third party landfill for two municipal utilities; and

 

   

service fees we earned for providing barge loading services, to third-party coal providers, at our Island river terminal and transloading facility on the Green River in western Kentucky.

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.”

 

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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, 2011, we derived 77.6% of our revenues from coal sales to electric utilities (including sales through brokers), 12.2% from coal sales to municipalities and cooperatives, 7.6% from coal sales to industrial customers and the remaining 2.6% 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.

Long-Term Coal Sales Contracts

For the past five years over 90% of our coal sales were made under long-term coal sales contracts and we intend to continue to enter into long-term coal sales contracts for substantially all of our annual coal production. We believe our long-term coal sales contracts reduce our exposure to fluctuations in the spot price for coal and provide us with a more 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.

For 2012, 2013, 2014 and 2015, we currently have long-term coal sales contracts for coal sales of 7.3 million tons, 6.5 million tons, 5.5 million tons and 4.0 million tons, respectively. These tonnages assume the successful renegotiation of some of our long-term coal sales contracts which contain provisions that provide for price reopeners. Two of our long-term coal sales contracts with the same customer provide for market-based adjustments to the initial contract price every three years. These two long-term coal sales contracts will terminate effective December 31, 2012 if we cannot agree upon a market-based price with the customer by September 30, 2012. In addition, we have one long-term coal sales contract with another customer that will terminate effective December 31, 2013 if we cannot agree upon a market-based price with the customer by June 30, 2013. The coal tonnage which is involved for these three contracts is 1.0 million tons for 2013, 1.4 million tons for 2014 and 0.9 million tons for 2015.

The terms of our coal sales contracts result from competitive bidding and negotiation 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 and/or cost adjustment provisions. For 2012, 2013, 2014 and 2015, 70%, 72%, 61% and 48% 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.

Some long-term coal sales contracts contain option provisions that give the customer the right to elect to purchase additional tons of coal during the contract term at the same price as the fixed tons provided for in the contract. We have outstanding option tons of 0.4 million for each of 2012 through 2014 and 0.7 million for 2015. If there are customer elections 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 concluded our long-standing negotiations with American Electric Power Service Corporation (“AEP”) to amend our long-term coal sales contract with them in October of 2011. The mutual goal of the parties was achieved to amend the contract to extend the term of the agreement, establish a future pricing methodology acceptable to both parties, and adjust the amounts of fixed and optional coal tonnage covered by the contract. In this amendment, the pricing is tied to and adjusted periodically based on indices reflecting current market pricing, and pricing adjusters were eliminated. By reason of this amendment, the current term of the contract now runs through 2015, and it can be automatically extended for a further three-year term through 2018 if AEP gives us eighteen months advance notice of its election to extend the contract. Further, in more recent negotiations we have reached an agreement in principle to reduce the 2012 contract tonnage in exchange for a compensating increase in pricing, and we are working to formalize that arrangement in a contract amendment.

On March 2, 2012, we received a notice of contract termination from Big Rivers Electric Corporation (“Big Rivers”). The notice notified us that Big Rivers was terminating the Amended and Restated Coal Supply Agreement between Big Rivers and us (the “Big Rivers Agreement”) effective as of the close of business on March 2, 2012, pursuant to provisions of the Big Rivers Agreement permitting termination in certain circumstances where coal deliveries have not conformed to the quality specifications in the Big Rivers Agreement. The Big Rivers Agreement provides for us to supply to Big Rivers 800,000 tons of coal per year, and absent any termination thereof the term of the Big Rivers Agreement runs

 

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until December 31, 2015. We have met with representatives of Big Rivers on two occasions following this action (on March 7 and March 12, 2012), but have been unable to achieve any satisfactory resolution of the issues during these meetings. We are assessing the validity of the termination notice and any recourse that we may have under the Big Rivers Agreement or otherwise with respect to the actions by Big Rivers, including the termination. We are also assessing the financial and operational impact that such a termination would have on us and reviewing various alternatives, including without limitation mine closure(s) and related cost reduction measures, to compensate for and/or lessen any impact from such actions by Big Rivers and to bring our production and related cost structure in balance with our remaining contractual commitments.

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 and/or use coal deliveries.

Customer Concentration

We derived 92.3% of our total revenues from coal sales to our ten largest customers for the year ended December 31, 2011, with our top five customers accounting for 77.8% of our total revenues. For the year ended December 31, 2011, we derived 34.9%, 14.5%, 11.0%, 10.9% and 6.5% of our revenues from AEP, First Energy, Big Rivers Electric, East Kentucky Power Cooperative and Duke Energy, respectively.

Transportation

Our coal is delivered to our customers by barge, truck or rail. Approximately 57% of the coal we shipped during 2011 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, 2012. 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). For the year ended December 31, 2011, 57%, 42% and 1% of our coal sales tonnage was shipped by barge, truck and rail, respectively.

We believe that we have good relationships with our rail carrier and trucking 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, 2011, expenses we incurred to obtain goods and services in support of our mining operations were approximately $154.1 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, 2011, 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.

 

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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.

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 continually strive to operate our mines with a focus on safety. Over the last 5 years, our Mine Safety and Health Administration, or MSHA, reportable incident rate was, on average, 2.0 which is equal to the national surface mine average. 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, increased public participation 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 may have 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 become subject to legal challenge by environmentalists and other advocacy groups.

 

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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 has primacy to administer the SMCRA program in its territory.

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 these 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, as well as compliance information from OSM’s Applicant Violator System, or AVS, which includes 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 timeframe for permitting is a function of the discretion vested in the various regulatory authorities, including with respect to the handling of comments and objections relating to the project received from affected communities, other governmental agencies 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

 

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mining operation. To our knowledge, no such claims have been asserted against us to date. If such claims are ever asserted against us, we will contest them vigorously on the basis that, among other things, receiving an overriding royalty under a sublease does not alone meet the legal or regulatory test of “ownership” or “control” so as to subject us to the SMCRA liabilities of our sublessee.

We maintain coal refuse areas and slurry impoundments at our Tuscarawas County and Muhlenberg County mining complexes. Such areas and impoundments are subject to extensive regulation under SMCRA and other federal and state 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 ruled that OSM could not withdraw the revised SBZ Rule 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, or EIS, for a new rule – to be called the Stream Protection Rule – that will evaluate alternatives for revising surface mining rules to better protect streams. OSM received public comments during the summer of 2010 and is developing a draft EIS. On February 13, 2012, OSM stated that it expects to release the draft EIS in April 2012. The requirements of the revised SBZ Rule, when adopted, will likely be stricter than the prior SBZ Rule to further protect streams from the impacts of surface mining, and may adversely affect our business and operations. In addition, Congress has 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 2011, we recorded $2.4 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, 2011, we had approximately $38.5 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $7.5 million in letters of credit.

Mine Health and Safety

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 (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

 

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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 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 21, 2011, the SEC issued final rules implementing Section 1503, outlining the way in which mining companies must disclose to investors certain information about mine safety and health standards. These new SEC rules were adopted as final in December 2011, and became effective on January 27, 2012. They require disclosure of the total numbers of health or safety-related violations, citations, orders, notices, assessments, fatalities and legal actions on a mine-by-mine basis. Our disclosure in this regard can be found in “Exhibit 95, Mine Safety Disclosure.”

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 2011, we recorded $4.2 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.

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 the results of our 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, including 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.

 

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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 can reduce 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 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, as well as other air pollutants which are classified as ozone precursors. In 2008, EPA last reviewed and revised the ozone standards and set primary and secondary ozone standards at a level of 0.075 ppm. Although EPA had announced in 2010 a proposal to tighten the ozone standards, it has since withdrawn this proposal and opted to continue implementing the existing 0.075 ppm standard and postpone reconsideration of the standard until 2014. However, EPA’s decision to postpone tightening of the ozone standards has been challenged by environmental groups in a pair of cases before the D.C. Circuit Court of Appeals. Attainment demonstrations under the current standards must be made by December 2013, with attainment dates between 2014 and 2031, depending on the severity of non-attainment.

 

   

NOx Budget Trading Program. The NOx Budget Trading Program was established by 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.

 

   

Cross-State Air Pollution Rule. EPA’s previous rule, the Clean Air Interstate Rule (“CAIR”), called 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 to keep CAIR in effect until EPA is able to issue a new replacement rule. On August 8, 2011, EPA issued a replacement rule known as the Cross-State Air Pollution Rule (“CSAPR”) that caps SO2 and NOx emissions from power plants in 31 eastern states and the District of Columbia. Under CSAPR, some coal-fired power plants will be required to install additional pollution control equipment and burn less high sulfur coal. CSAPR has been challenged by several states and interested parties in the D.C. Circuit Court of Appeals, and the rule is currently stayed pending further proceedings.

 

   

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. In December 2011, EPA issued its Mercury and Air Toxics Standards (“MATS”), which set national standards for mercury pollution from coal-fired power plants. In addition, in February 2011, EPA established new maximum achievable control technology standards for several classes of boilers and process heaters (known as the “boiler MACT”) which require significant reductions in emissions of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. In December 2011, the EPA announced additional revisions to the boiler MACT.

 

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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 seeks to restrict emissions from new coal-fired power plants whose operation may impair visibility at and near such federally protected areas. The program also requires 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. On December 23, 2011, EPA proposed to approve the trading program in the CSAPR as an alternative to establishing Best Available Retrofit Technology (BART) standards on a source-by-source basis. This would allow states in the CSAPR region to substitute participation in CSAPR for source-specific BART for sulfur dioxide and/or nitrogen oxides emissions from power plants.

 

   

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.

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.

The EPA has also begun regulating greenhouse gas emissions under the Clean Air Act after authorization by its December 2009 endangerment finding made in response to the 2007 U.S. Supreme Court’s ruling in Massachusetts v. EPA. 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 increased 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 further modified 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

 

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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.

On June 20, 2011, the U.S. Supreme Court ruled in American Electric Power Co., Inc. v. Connecticut that the Clean Air Act and U.S. EPA regulation of carbon dioxide emissions thereunder preempt any federal common law right for abatement of a public nuisance based upon global warming allegedly caused by out-of-state emissions from fossil-fuel fired power plants.

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 rulings 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 wastewater or 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. Such changes could increase the cost and time we expend on CWA compliance.

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” from point sources into waters of the United States. The National Pollutant Discharge Elimination System, or NPDES, requires a permit for any such discharge, which in turn typically imposes requirements for regular monitoring, reporting and compliance with performance standards that govern such discharges. Failures to comply with the CWA or NPDES permits can lead to the imposition of penalties, injunctive relief, compliance costs and delays in coal production.

The CWA and corresponding state laws also protect waters that states have been designated for special protections including those designated as: impaired (i.e., as not meeting present water quality standards) through total maximum daily load (TMDL) restrictions; and “high quality/exceptional use” stream designations that restrict discharges that could result in their degradation. Other requirements necessitate the treatment of discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids, and avoidance of impacts to streams, wetlands, other regulated water resources and associated riparian lands from surface and 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.

 

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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)) by the U.S. Army Corps of Engineers, or Corps, prior to any discharge or placement of “fill” into navigable waters of the United States. The Corps is empowered to issue a “nationwide” permits, or NWPs, 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, in 1982 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 particularly 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. One 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 based upon deference to the expertise of the Corps in review of the permit applications. On August 19, 2010, the U.S. Supreme Court dismissed the petition for writ of certiorari in the case.

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, 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 based on what the EPA contended was “new” information on the impacts of valley fills on downstream water quality. These EPA comments 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, EPA and the U.S. Department of the Interior announced an interagency action plan for “Enhanced Coordination” 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 and EPA committed to undertake an “Enhanced Coordination Process” in reviewing Section 404 permit applications for such projects. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of CWA permits by state and federal agencies.

In 2010, the National Mining Association, or NMA, the State of West Virginia, and the Kentucky Coal Association and other plaintiffs challenged these EPA guidance’s in (National Mining Association v. Jackson, et al, (D.D.C.). On October 6, 2011, the District Court ruled that the EPA had exceeded its statutory authority, and that the challenged EPA guidance documents were legislative rules that were adopted in violation of notice and comment requirements.

On June 18, 2010, the Corps announced the suspension of the NWP 21 in the Appalachian regions of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia 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.

On February 16, 2011, the Corps solicited comments on three options for the possible reissuance of NWP 21: Option 1 would be to not reissue NWP 21; Option 2 would be to reissue NWP 21 with modifications, including a  1/2-acre limit for losses of non-tidal waters, a 300-foot limit for the loss of stream bed (with possible waiver for the loss of intermittent and ephemeral stream beds under certain conditions) and a prohibition on its use for valley fills; and Option 3 would be the same as Option 2 without the prohibition on valley fills. The Corps’ preferred option is Option 2. Although the comment period has ended, the Corps’ final action on reissuance of NWP 21 is still pending.

 

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Despite the ruling in National Mining Association v. Jackson, on July 21, 2011, EPA issued its final guidance on Improving EPA Review of Appalachian Surface Coal Mining Operations Under the Clean Water Act, National Environmental Policy Act, and the Environmental Justice Executive Order. This final guidance replaces EPA’s interim guidance released on April 1, 2010. The final guidance calls for the imposition of additional discharge restrictions under Section 402 of the CWA, including water-quality based effluent limits, Whole Effluent Toxicity (WET) limits and other permit conditions. It also calls for greater scrutiny of Section 404 applications for less damaging practicable alternatives, protection against water quality standards violations, prevention of significant deterioration of water quality, minimization of water quality impacts and adequate mitigation of project impacts. The new requirements and procedures imposed by EPA’s final guidance are expected to make permitting for Appalachian surface coal mining activities more difficult, and increase the regulatory burdens imposed on such projects. These initiatives likely will extend the time required to obtain permits for coal mining and that the costs associated with obtaining and complying with those permits will increase substantially. Additionally, any future changes could further restrict our ability to obtain other new permits or to maintain existing permits.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act, or RCRA, regulates the management of solid and hazardous wastes from the point of generation through treatment and disposal. RCRA hazardous waste requirements do not apply to most of the wastes generated at coal mines, overburden and coal cleaning wastes, because such materials are not considered hazardous wastes under RCRA regulations. 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, coal combustion residuals (CCRs), often referred to as coal ash, are currently considered exempt wastes under an amendment to RCRA known as the Bevill Exclusion. Most state solid waste laws also regulate coal combustion residuals as non-hazardous wastes. The EPA is currently considering what type of RCRA regulation is warranted for certain CCR’s when used as mine-fill. In June 2010, EPA published a proposal to regulate CCR as either a non-hazardous waste under Subtitle D of RCRA by issuing national minimum criteria or as special wastes under Subtitle C of RCRA when they are destined for disposal in landfills or surface impoundments. On October 21, 2010, EPA published a Notice of Data Availability (NODA) on CCR surface impoundments, and on October 12, 2011, EPA issued another NODA inviting comment on additional information obtained by EPA in conjunction with the June 21, 2010 proposed rule. However, EPA has yet to take final action on the proposed rule. If CCR is regulated under RCRA, 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.

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 transporters 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 or chemicals used by coal companies in operations 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. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we own surface rights.

Endangered Species Act

The 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

 

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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 Substances Control Act and the Emergency Planning and Community Right-to-Know Act.

Employees

To carry out our operations, our general partner employed 929 full-time employees as of December 31, 2011. 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, as amended, 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 more than $9.2 million per quarter, or $36.9 million per year, based on the number of general partner units, common units and subordinated units outstanding at December 31, 2011. 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;

 

   

extreme weather conditions impacting our ability to operate;

 

   

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 utilities 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 2011, we sold approximately 77.6% of our coal to domestic electric utilities, and we have long-term contracts in place with all but one of 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;

 

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indirect competition from alternative fuel sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources;

 

   

environmental and other governmental regulations, including those impacting coal-fired power plants; and

 

   

energy conservation efforts and related governmental policies.

According to the EIA, total electricity consumption in the United States remained essentially flat during 2011 compared with 2010. 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.

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;

 

   

demand for electricity, which tends to follow changes in general economic activity;

 

   

domestic and foreign economic conditions;

 

   

the price, quantity and quality of other coal available to our customers;

 

   

competition for production of electricity from non-coal sources, including the price and availability of alternative fuels and other sources, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the effects of technological developments related to these non-coal energy sources;

 

   

domestic air emission standards for coal-fired power plants, and the ability of coal-fired power plants to meet these standards by installing scrubbers, purchasing emissions allowances or other means; and

 

   

legislative and judicial developments, regulatory changes, or changes in energy policy and energy conservation measures that would adversely affect the coal industry.

For more information regarding our long-term coal sales contracts, please read “Item 1. Business — Customers — Long-Term Coal Sales Contracts.”

 

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Coal prices are subject to change and a decline in prices could materially and adversely affect our profitability and the value of our coal reserves.

Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. The contract prices we may receive in the future for coal depend upon factors beyond our control, including the following:

 

   

the domestic and foreign supply and demand for coal;

 

   

the quantity and quality of coal available from competitors;

 

   

a decline in prices under existing contracts in any case where the pricing under such contracts is tied to and adjusted periodically based on indices reflecting current market pricing;

 

   

competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;

 

   

domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;

 

   

adverse weather, climatic or other natural conditions, including natural disasters;

 

   

domestic and foreign economic conditions, including economic slowdowns;

 

   

legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

 

   

the proximity to, capacity of and cost of transportation and port facilities; and

 

   

market price fluctuations for sulfur dioxide emission allowances.

A substantial or extended decline in the prices we receive for our future coal sales could materially and adversely affect us by decreasing our profitability and the value of our coal reserves.

Our coal reserves decline as we mine our coal and our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability and our ability to make distributions to our unitholders.

Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics our customers desire. Because our reserves decline as we mine our coal, our future profitability and our ability to make distributions to our unitholders 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 and our ability to make distributions to our unitholders.

 

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We depend on a limited number of customers for a significant portion of our revenues, and the loss of, or significant reduction in, purchases by any of them could adversely affect our results of operations and our ability to make cash distributions to our unitholders.

We derived 77.8% of our revenues from coal sales to our five largest customers for the year ended December 31, 2011 and, as of March 1, 2012, we had long-term coal sales contracts in place with these same customers for 79.1% of our 2012 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. In addition, we may be required to renegotiate our existing long-term coal sales contracts on less favorable terms and at reduced purchasing levels, in order to preserve strategic relationships with our customers. 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 regulatory scheme, 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.

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. Future regulation, litigation and permitting restrictions 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 and our ability to make distributions to our unitholders. 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, the blending of our high-sulfur coal with low-sulfur coal or other means to reduce emissions.

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 laws and 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 adversely affect our business, results of operations and ability to make distributions to our unitholders.

 

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There have been a large number of recent changes to regulations issued pursuant to the Clean Air Act. Notably, on August 8, 2011, EPA promulgated the Cross-State Air Pollution Rule (“CSAPR”) that caps SO2 and NOx emissions from power plants in 31 eastern states and the District of Columbia. Although CSAPR has been challenged by several states and interested parties in the D.C. Circuit Court of Appeals, and the rule is currently stayed pending further proceedings, many of our customers could be significantly affected by CSAPR, which requires significant sulfur dioxide emission reductions beginning in 2012 and in 2014. 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.

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.

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.

Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issue force majeure notices which suspend our obligations to deliver coal

 

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under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to re-open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments, the extension of time for delivery or the termination of customers’ contracts. Any of these actions could have a material adverse effect on our business and 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 $5.1 million in distributions to us during 2011. 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.

We may be unsuccessful in identifying or integrating suitable acquisitions, which could impair our growth.

Our ability to grow depends upon our ability to identify, negotiate, complete and integrate suitable acquisitions. This strategy depends on the availability of acquisition candidates with businesses that can be successfully integrated into our existing business and that will provide us with complementary capabilities, products or services. There are many challenges to integrating acquired companies and businesses, including eliminating redundant operations, facilities and systems, coordinating management and personnel, retaining key employees, managing different corporate cultures and achieving cost reductions and cross-selling opportunities. It is possible that we will be unable to successfully complete potential acquisitions which could impair our growth.

Moreover, any acquisition could be dilutive to earnings and distributions to unitholders and any additional debt incurred to finance an acquisition could affect our ability to make distributions to unitholders. Our ability to make acquisitions in the future could be limited by restrictions under our existing or future credit facilities, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

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, 2011, we received royalty income on our underground coal reserves of approximately $3.2 million or approximately 5.9% 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

 

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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.

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.

The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.

We depend upon barge, rail and truck systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to supply coal to our customers. As we do not have long-term contracts with transportation providers to ensure consistent and reliable service, decreased performance levels over longer periods of time could cause our customers to look to other sources for their coal needs. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad.

In recent years, the states of Kentucky and West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that all states in which our coal is transported by truck may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.

If we experience disruptions in our transportation services or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.

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, such as increased 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, also may require us to change operations significantly or incur increased costs or subject us to more severe adverse consequences for non-compliance. Such changes could have a material adverse effect on our business, financial condition or results of operations and our ability to make distributions to our unitholders.

 

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Mining in Northern Appalachia and the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our mining operations and cost structures in these areas.

The geological characteristics of Northern Appalachian and Illinois Basin coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, as compared to mines in the Powder River Basin, permitting, licensing and other environmental and regulatory requirements are more costly and time consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers' ability to use coal produced by, our mines in Northern Appalachia and the Illinois Basin.

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, amended or renewed for new and existing mines has materially impacted coal production. Permitting by the Army Corps of Engineers, EPA and the Department of the Interior has become subject to enhanced review and stricter enforcement, especially under the Clean Water Act (the “CWA”) to reduce the harmful environmental consequences of mountain-top mining, particularly in central Appalachia. On July 21, 2011, the EPA issued final guidance for the environmental review of permits issued by state and federal agencies pursuant to the CWA with respect to mountain-top mining in Central Appalachia. This final guidance replaces the EPA’s interim final guidance issued on April 1, 2010.

The preparation, submission and attainment of mining permits are ongoing activities essential to the success of our business. We currently have approved mining permits representing in excess of 21 million tons of proven and probable reserves, which provides us with more than two years of production based on our current surface mining plan. 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 limit or 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, amended or renewed in a timely fashion or at all, or if such permits 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 our business, results of operations and ability to make distributions to our unitholders could be adversely affected. Please read “Item 1. Business — Mining and Environmental Regulation.”

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, 2011, we had accrued a reserve of approximately $21.8 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 and Note 9 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.

 

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To fund our capital expenditures, we must use cash generated from our operations, additional borrowings, or the issuance of additional equity or debt securities, or some combination thereof, which could limit our ability to pay distributions at the then-current distribution rate.

The use of cash generated from operations to fund capital expenditures reduces cash available for distribution to our unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions, and contingencies and uncertainties that are beyond our control. Our failure to obtain funds necessary for future capital expenditures could have a material adverse effect on our business, results of operations or financial condition, and on our ability to pay distributions to our unitholders. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could limit our ability to pay distributions at the then-current distribution rate.

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.

 

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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.

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 of 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 potential liability for hazardous substances or wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on our business, financial condition or results of operations and our ability to make distributions to our unitholders. 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.

Recent healthcare legislation could adversely affect our financial condition and results of operations.

In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was enacted, potentially impacting our costs to provide healthcare benefits to our eligible active and certain retired employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung disease). The PPACA has both short-term and long-term implications on benefit plan standards. Implementation of this legislation is planned to occur in phases, with plan standard changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018.

In the short term, our healthcare costs could increase due to raising the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions of annual dollar limits per covered individual, among other standard requirements. In the long term, our healthcare costs could increase due to an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual, among other standard requirements.

The healthcare benefits that we provide to our represented employees and retirees are stipulated by law. Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will need to evaluate the impact of the PPACA in future periods, and when these regulations or interpretations are published, we will evaluate its assumptions in light of the new information.

 

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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.

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 business, financial condition or results of operations and our ability to make distributions to our unitholders.

 

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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 2011, approximately 25.4% of our sales were through coal brokers. We expect our sales through coal brokers to increase to approximately 41.1% of our sales in 2012.

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 1, 2012 of approximately $38.6 million, which were supported by letters of credit of $7.5 million. Certain business transactions, such as coal leases and other obligations, may also require bonding. Our bonding requirements could increase in the future. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including putting up letters of credit or posting cash collateral, or other terms less favorable to us upon those renewals. Our ability to obtain or renew our surety bonds could be impacted by a variety of other factors including lack of availability, unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety bonds and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of any credit arrangements then in place. Due to current economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds and we may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and our ability to make cash distributions to our unitholders could be adversely affected.

Defects in title in our mine properties could limit our ability to recover coal from these properties or result in significant unanticipated costs.

Our right to mine some of our reserves may be materially adversely affected by actual or alleged defects in title or boundaries. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs or could even lose our right to mine on that property, which could adversely affect our profitability. In addition, from time to time the rights of third parties for competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, coalbed methane production, pipelines, roads, easements and public facilities may affect our ability to operate as planned if our title is not superior or arrangements cannot be negotiated.

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 2012, we expect to incur between $4.0 million and $5.0 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

 

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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 hedging activities for diesel fuel may prevent us from benefiting from price decreases

We enter into hedging arrangements for a portion of our anticipated diesel fuel and explosive needs. As of December 31, 2011, we had fixed-price fuel contracts for approximately 55% of our calendar year 2012 expected diesel fuel needs. While our hedging strategy provides us protection in the event of price increases to our diesel fuel, it may also prevent us from the benefits of price decreases. If prices for diesel fuel decreased significantly below our swap prices, we would lose the benefit of any such decrease.

Our management team has limited 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 has limited 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.

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;

 

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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 our partnership agreement, including the provisions described above.

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 18.1% limited partner interest in us, AIM Oxford owns a 35.6% 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 duties.” 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;

 

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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

 

   

our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

 

   

our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, AIM currently holds substantial interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, AIM and AIM Oxford are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.

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.

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% 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 54.9% 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.

 

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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 54.9% 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.

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

 

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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.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.

As of December 31, 2011, a single unaffiliated unitholder owned 1,222,925, or 11.7%, of our common units. That unitholder may sell some or all of these units or it may distribute our common units to the holders of its equity interests and those holders may dispose of some or all of these units. The sale or disposition of a substantial number of our common units in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

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.

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 our 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.

 

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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 our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the 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.

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.

 

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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 2013, 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 production of coal and other hard mineral fossil fuels. 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.

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.

 

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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.

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.

 

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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 and Pennsylvania. Each of these states currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

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.

 

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As of December 31, 2011, we owned 15.8% of our coal reserves and leased 84.2% 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. The preparation, submission and attainment of mining permits are ongoing activities essential to the success of our business. We currently have approved mining permits representing in excess of 21 million tons of proven and probable reserves, which provides us with more than two years of production based on our current surface mining plan. In order to sustain our business, we must continue to obtain new permits as specific mine areas are depleted. 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.

The following table provides information as of December 31, 2011 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

     9.0        5.0        4.0   

Tuscarawas County

     6.4        0.1        6.3   

Plainfield

     5.4        0.7        4.7   

Belmont County

     9.0        1.1        7.9   

New Lexington

     4.7        2.7        2.0   

Harrison(2)

     4.3        4.3        —     

Noble County

     2.4        —          2.4   
  

 

 

   

 

 

   

 

 

 

Total Northern Appalachia

     41.2        13.9        27.3   
  

 

 

   

 

 

   

 

 

 

Illinois Basin (Kentucky)

      

Muhlenberg County

     22.1        —          22.1   
  

 

 

   

 

 

   

 

 

 

Total Illinois Basin

     22.1        —          22.1   
  

 

 

   

 

 

   

 

 

 

Total Surface Mining Operations

     63.3        13.9        49.4   
  

 

 

   

 

 

   

 

 

 

Underground Coal Reserves:

      

Tusky

     24.7        —          24.7   
  

 

 

   

 

 

   

 

 

 

Total Underground Coal Reserves

     24.7        —          24.7   
  

 

 

   

 

 

   

 

 

 

Total

     88.0        13.9        74.1   
  

 

 

   

 

 

   

 

 

 

Percentage of Total

     100.0     15.8     84.2
  

 

 

   

 

 

   

 

 

 

 

(1) 

Reported as recoverable coal reserves.

(2) 

The Harrison mining complex is owned by Harrison Resources. We own 51% of Harrison Resources and CONSOL Energy Inc. owns the remaining 49% 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, 2011 as required by GAAP, proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100% of Harrison Resources.

 

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The following table provides information on particular characteristics of our coal reserves as of December 31, 2011:

 

     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

     12.0         3.4         11,510         5.9         9.0         0.9         4.4         3.7   

Tuscarawas County

     10.9         3.9         11,630         6.7         6.4         0.9         2.5         3.0   

Plainfield

     10.3         4.4         11,530         7.7         5.4         —           0.8         4.6   

Belmont County

     12.6         4.1         11,730         7.1         9.0         —           2.8         6.2   

New Lexington

     11.7         4.0         11,580         6.9         4.7         —           2.1         2.6   

Harrison(2)

     12.1         1.8         11,990         3.1         4.3         3.0         1.3         —     

Noble County

     11.3         4.6         11,180         8.2         2.4         —           0.3         2.1   

Illinois Basin (Kentucky)

                       

Muhlenberg County

     10.9         3.5         11,327         6.2         22.1         —           21.6         0.5   

Underground Coal Reserves:

                       

Tusky

     5.4         2.1         12,900         3.2         24.7         3.8         20.9         —     

 

(1) 

As received represents an analysis of a sample as received at a laboratory operated by a third party.

(2) 

The Harrison mining complex is owned by Harrison Resources. We own 51% of Harrison Resources and CONSOL Energy Inc. owns the remaining 49% 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, 2011 as required by GAAP, proven and probable coal reserves attributable to the Harrison mining complex are presented on a gross basis assuming we owned 100% of Harrison Resources.

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. MINE SAFETY DISCLOSURES

Our mining operations are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K.

 

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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 9, 2012, the closing market price for the common units was $9.05 per unit. As of March 9, 2012, there were 10,409,027 common units outstanding. There were approximately 33 record holders of common units on December 31, 2011. 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:

 

Period

   High
Price
     Low
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   

Quarter ended March 31, 2011

   $ 28.34       $ 23.36       $ 0.4375   

Quarter ended June 30, 2011

   $ 27.75       $ 21.59       $ 0.4375   

Quarter ended September 30, 2011

   $ 24.37       $ 15.04       $ 0.4375   

Quarter ended December 31, 2011

   $ 18.33       $ 14.67       $ 0.4375   

We also have outstanding 10,280,380 subordinated units and 422,233 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

 

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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.

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 422,233 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 2011.

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 we can pay quarterly cash distributions. 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 $5.1 million in distributions to us during 2011. 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.

On April 15, 2011, July 15, 2011, October 14, 2011, December 31, 2011 and January 13, 2012, we received contributions of approximately $6,231, $1,103, $1,092, $14,760 and $2,957, respectively, from our general partner as consideration for the issuance to our general partner of approximately 227, 48, 73, 843 and 189 general partner units, respectively. These transactions were exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

 

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Issuer Purchases of Equity Securities.

We did not make any purchases of our common units, and no such purchases were made on our behalf during 2011.

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
(Successor)
    Oxford Mining
Company
(Predecessor)
 
                             Period from  
     Years Ended December 31,     August 24,
2007 to
December 31,
    January 1,
2007 to

August 23,
 
     2011     2010     2009     2008     2007     2007  
           (in thousands, except per ton amounts)  

Statement of Operations Data:

            

Revenues:

            

Coal sales

   $ 343,741      $ 311,567      $ 254,171      $ 193,699      $ 61,324      $ 96,799   

Transportation revenue

     47,305        38,490        32,490        31,839        10,204        18,083   

Royalty and non-coal revenue

     9,331        6,521        7,183        4,951        1,407        3,267   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     400,377        356,578        293,844        230,489        72,935        118,149   

Costs and expenses:

            

Cost of coal sales (excluding DD&A, shown separately)

     272,420        229,468        170,698        151,421        40,721        70,415   

Cost of purchased coal

     13,480        22,024        19,487        12,925        9,468        17,494   

Cost of transportation

     47,305        38,490        32,490        31,839        10,204        18,083   

Depreciation, depletion and amortization

     51,905        42,329        25,902        16,660        4,926        9,025   

Selling, general and administrative expenses

     13,739        14,757        13,242        9,577        2,114        3,643   

Contract termination and amendment expenses, net

     —          652        —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     398,849        347,720        261,819        222,422        67,433        118,660   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     1,528        8,858        32,025        8,067        5,502        (511

Interest income

     13        12        35        62        55        26   

Interest expense

     (9,870     (9,511     (6,484     (7,720     (3,498     (2,386

Gain on purchase of business(1)

     —          —          3,823        —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income

     (8,329     (641     29,399        409        2,059        (2,871

Less: Net income attributable to noncontrolling interest

     (4,748     (6,710     (5,895     (2,891     (537     (682
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income attributable to Oxford Resource Partners, LP unitholders

   $ (13,077   $ (7,351   $ 23,504      $ (2,482   $ 1,522      $ (3,553
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income allocated to general partner

   $ (261   $ (147   $ 467      $ (50   $ 30        n/a   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income allocated to limited partner

   $ (12,816   $ (7,204   $ 23,037      $ (2,432   $ 1,492        n/a   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income per limited partner unit:

            

Basic

   $ (0.62   $ (0.45   $ 2.09      $ (0.24   $ 0.17        n/a   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

   $ (0.62   $ (0.45   $ 2.08      $ (0.24   $ 0.17        n/a   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of limited partner units outstanding:

            

Basic

     20,641,127        15,887,977        11,033,840        10,104,324        8,922,801        n/a   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

     20,641,127        15,887,977        11,083,170        10,104,324        8,926,360        n/a   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributions paid per limited partner unit (2)

   $ 1.75      $ 0.58      $ 1.20      $ 1.26      $ —          n/a   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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SELECTED FINANCIAL AND OPERATING DATA - (continued)

 

     Oxford Resource Partners, LP
(Successor)
    Oxford Mining
Company
(Predecessor)
 
                             Period from  
     Years Ended December 31,     August 24,
2007 to
December 31,
    January 1,
2007 to

August 23,
 
     2011     2010     2009     2008     2007     2007  
           (in thousands, except per ton amounts)  

Statement of Cash Flows Data:

            

Net cash provided by (used in):

            

Operating activities

   $ 44,534      $ 40,268      $ 38,637      $ 33,992      $ (8,519   $ 17,634   

Investing activities

     (41,444     (84,894     (49,171     (23,942     (98,745     (16,619

Financing activities

     (947     42,149        (1,279     4,494        106,724        (234

Other Financial Data:

            

Adjusted EBITDA (3)

   $ 54,037      $ 51,617      $ 56,967      $ 24,686        8,120        10,691   

Distributable cash flow (4) (5)

     8,297        n/a        n/a        n/a        n/a        n/a   

Reserve replacement expenditures (6)

     5,797        3,353        3,057        2,526        163        1,297   

Other maintenance capital expenditures (6)

     32,159        25,028        25,657        25,321        7,420        11,305   

Balance Sheet Data (at period end):

            

Cash and cash equivalents

   $ 3,032      $ 889      $ 3,366      $ 15,179      $ 635      $ 1,175   

Trade accounts receivable

     28,388        28,108        24,403        21,528        17,547        18,396   

Inventory

     12,000        12,640        8,801        5,134        4,655        4,824   

Property, plant and equipment, net

     195,607        198,694        149,461        112,446        106,408        54,510   

Total assets

     261,265        261,071        203,363        171,297        146,774        90,893   

Total debt (current and long-term)

     143,755        102,986        95,711        83,977        75,529        43,165   

Operating Data:

            

Tons of coal produced (clean)

     7,987        7,470        5,846        5,089        1,634        2,693   

(Increase) decrease in inventory

     91        (53     (65     5        (1     (1

Tons of coal purchased

     380        734        530        434        305        641   

Tons of coal sold

     8,458        8,151        6,311        5,528        1,938        3,333   

Tons sold under long-term contracts (7)

     96.6     95.9     97.8     93.8     98.9     96.6

Average sales price per ton

            

(net of transportation expense) (8)

   $ 40.64      $ 38.22      $ 40.27      $ 35.04      $ 31.64      $ 29.04   

Cost of purchased coal sales per ton (9)

   $ 35.47      $ 30.00      $ 36.79      $ 29.81      $ 31.08      $ 27.29   

Cost of coal sales per ton produced (10)

   $ 33.72      $ 30.94      $ 29.52      $ 29.81      $ 24.93      $ 26.16   

Number of operating days

     278.5        275.5        274.5        280.0        97.5        181.5   

 

(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) 

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 its most directly comparable financial measures calculated and presented in accordance with GAAP, 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) 

We started calculating distributable cash flow in July 2010 and periods subsequent thereto during which we were a publicly traded partnership. We did not calculate distributable cash flow with respect to periods prior thereto, and thus we do not have any comparable amounts for the years ended December 31, 2010, 2009, 2008 and 2007.

(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

 

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  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 2011 and 2010 are estimated, while prior years are actual. Other maintenance capital expenditures for 2011 and 2010 include asset retirement obligations and mine development costs, while prior years do not.
(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, net of transportation expenses, 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 and such items as gain on purchase of business, acquisition costs which are required by GAAP to be expensed, contract termination and amendment expenses, net, amortization of below-market coal sales contracts, non-cash equity-based compensation expense, 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. 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. Adjusted EBITDA 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. 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 adjusted EBITDA to net income (loss) attributable to our unitholders, the most directly comparable measure as reported in accordance with GAAP, 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) and excluding amendment fees, 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 expenditures relating to our ARO. Distributable cash flow should not be considered as an alternative to net income (loss) attributable to our unitholders, income from

 

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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 distributable cash flow, the most directly comparable measure as reported in accordance with GAAP, to net income (loss) attributable to our unitholders for each of the periods indicated.

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
(Successor)
    Oxford Mining
Company
(Predecessor)
 
     Year
Ended
December  31,
    Year
Ended
December  31,
    Year
Ended
December  31,
     Year Ended
December 31,
    Period
from
August 24,  to
December 31,
    Period from
January 1, to
August 23,
 
     2011     2010     2009      2008     2007     2007  
     (in thousands)  

Net (loss) income attributable to Oxford Resource Partners, LP unitholders

   $ (13,077   $ (7,351   $ 23,504       $ (2,482   $ 1,522      $ (3,553

PLUS:

             

Interest expense, net of interest income

     9,857        9,499        6,449         7,658        3,443        2,360   

Depreciation, depletion and amortization

     51,905        42,329        25,902         16,660        4,926        9,025   

Non-cash equity compensation expense

     1,077        942        472         468        25        —     

Non-cash (gain) loss on asset disposals

     1,352        1,228        1,177         (1,407     (8     (25

Non-cash change in future asset retirement obligations

     3,355        5,742        4,991         4,560        167        2,884   

Acquisition costs

     507        —          —           —          —          —     

Contract termination and amendment expenses, net

     —          652        —           —          —          —     

LESS:

             

Gain on purchase of business

     —          —          3,823         —          —          —     

Amortization of below-market coal sales contracts

     939        1,424        1,705         771        1,955        —     
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Adjusted EBITDA (1)

     54,037      $ 51,617      $ 56,967       $ 24,686      $ 8,120      $ 10,691   
    

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

LESS:

             

Cash interest expense, net of interest income and excluding amendment fees

     7,784              

Estimated reserve replacement expenditures

     5,797              

Other maintenance capital expenditures

     32,159              
  

 

 

            

Distributable cash flow (1)

   $ 8,297              
  

 

 

            

 

(1) We started calculating distributable cash flow in July 2010 and periods subsequent thereto during which we were a publicly traded partnership. We did not calculate distributable cash flow with respect to periods prior thereto, and thus we do not have any comparable amounts for the years ended December 31, 2010, 2009, 2008 and 2007.

 

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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 primarily in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to our customers. All three subsidiaries share common customers, assets and employees.

We currently have 19 active surface mines, one of which became an active mine in the first quarter of 2012, that are managed as eight mining complexes. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During 2011, we produced 8.0 million tons of coal and sold 8.5 million tons of coal, including 0.4 million tons of purchased coal. As a result, our coal inventory on hand decreased by approximately 0.1 million tons. We purchase coal in the open market and under contracts to satisfy a portion of our sales commitments. As is customary in the coal industry, we have entered into long-term coal sales contracts with most 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, 2011, we had $131 million of borrowings outstanding under our $175 million credit facility, consisting of term loan borrowings of $51 million and revolving credit facility borrowings of $80 million.

Evaluating Our Results of Operations

We evaluate our results of operations based on several key measures:

 

   

our coal production, sales volume and average net 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, Sales Prices and Transportation Revenue and Expenses

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, many 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 and inflation. 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 and cost-of-living generally.

Our transportation revenue reflects the portion of our total revenues that is attributable to actual transportation costs. 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 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.

We evaluate the price we receive for our coal on an average sales price per ton basis, net of transportation expenses. Our average sales price per ton, net of transportation expenses, 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  
     Years Ended
December 31,
   

2011

vs.

   

2010

vs.

 
     2011     2010     2009     2010     2009  
     (tons in thousands)              

Tons of coal produced (clean)

     7,987        7,470        5,846        6.9     27.8

(Increase) decrease in inventory

     91        (53     (65     n/a        n/a   

Tons of coal purchased

     380        734        530        (48.2 %)      38.5

Tons of coal sold

     8,458        8,151        6,311        3.8     29.2

Tons sold under long-term contracts(1)

     96.6     95.9     97.8     0.7     (1.9 %) 

Average sales price per ton

   $ 46.23      $ 42.94      $ 45.42        7.7     (5.5 %) 

Transportation expenses per ton (2)

   $ 5.59      $ 4.72      $ 5.15        18.4     (8.3 %) 

Average sales price per ton

    (net of transportation expenses)

   $ 40.64      $ 38.22      $ 40.27        6.3     (5.1 %) 

Number of operating days

     278.5        275.5        274.5        n/a        n/a   

 

(1) 

Represents the percentage of the tons of coal we sold that were delivered under long-term coal sales contracts.

(2) 

Transportation expenses represent the costs we incur for transporting our coal from our mines to the points of sale specified in our contracts.

 

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Cost of Coal Sales

We evaluate our cost of coal sales, which excludes the costs of purchased coal and transportation expenses, depreciation, depletion and amortization (“DD&A”) and any other indirect costs not directly associated with the production of the coal such as selling, general and administrative expenses (“SG&A”), on a cost per ton basis. Our cost of coal sales per ton represents our cost of coal sales divided by the tons of coal we sold excluding purchased coal tons. 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 of coal sold, excluding purchased coal:

 

                          % Change  
     Years Ended
December 31,
    

2011

vs.

   

2010

vs.

 
     2011      2010      2009      2010     2009  
     (tons in thousands)               

Cost of coal sales per ton

   $ 33.72       $ 30.94       $ 29.52         9.0     4.8

Tons of coal sold, excluding purchased coal

     8,078         7,417         5,781         8.9     28.3

Cost of Purchased Coal

We purchase coal from third parties to fulfill a 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 the Illinois Basin assets from Phoenix Coal, we assumed a long-term coal purchase contract with a third party supplier that had favorable pricing terms relative to our production costs. Under this contract the third party supplier is obligated to deliver and we are obligated to purchase 0.4 million tons of coal each year until the coal reserves covered by this contract are depleted. We have experienced supplier performance issues under this contract which continued through 2011 and still persist in 2012. The supplier has asserted that this contract is terminated by its terms, while we have taken a contrary position. We are now working with the supplier to resolve the matter.

We evaluate our cost of purchased coal on a per ton basis. The following table provides summary information for the periods indicated for our cost of purchased coal per ton and tons of coal purchased:

 

                          % Change  
     Years Ended
December 31,
    

2011

vs.

   

2010

vs.

 
     2011      2010      2009      2010     2009  
     (tons in thousands)               

Cost of purchased coal per ton

   $ 35.47       $ 30.00       $ 36.79         18.2     (18.5 %) 

Tons of coal purchased

     380         734         530         (48.2 %)      38.5

Adjusted EBITDA

For a definition of adjusted EBITDA and a reconciliation of net income (loss) attributable to unitholders to adjusted EBITDA, please see Item 6: Selected Financial and Operating Data—Non-GAAP Financial Measures. Please also see “Results of Operations — 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 net income (loss) attributable to unitholders to distributable cash flow, please see Item 6: Selected Financial and Operating Data—Non-GAAP Financial Measures. Please also see “Results of Operations — Summary” for a reconciliation of net income (loss) attributable to our unitholders to distributable cash flow for the period indicated.

 

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Factors That Impact Our Business

For the past five years over 90% of our coal sales were made under long-term coal sales contracts and we intend to continue to enter into long-term coal sales contracts for substantially all of our annual coal production. We believe our long-term coal sales contracts reduce our exposure to fluctuations in the spot price for coal and provide us with a more 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.

For 2012, 2013, 2014 and 2015, we currently have long-term coal sales contracts for coal sales of 7.3 million tons, 6.5 million tons, 5.5 million tons and 4.0 million tons, respectively. These tonnages assume the successful renegotiation of some of our long-term coal sales contracts which contain provisions that provide for price reopeners. Two of our long-term coal sales contracts with the same customer provide for market-based adjustments to the initial contract price every three years. These two long-term coal sales contracts will terminate effective December 31, 2012 if we cannot agree upon a market-based price with the customer by September 30, 2012. In addition, we have one long-term coal sales contract with another customer that will terminate effective December 31, 2013 if we cannot agree upon a market-based price with the customer by June 30, 2013. The coal tonnage which is involved for these three contracts is 1.0 million tons for 2013, 1.4 million tons for 2014 and 0.9 million tons for 2015.

The terms of our coal sales contracts result from competitive bidding and negotiation 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 and/or cost adjustment provisions. For 2012, 2013, 2014 and 2015, 70%, 72%, 61% and 48% 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.

Some long-term coal sales contracts contain option provisions that give the customer the right to elect to purchase additional tons of coal during the contract term at the same price as the fixed tons provided for in the contract. We have outstanding option tons of 0.4 million for each of 2012 through 2014 and 0.7 million for 2015. If there are customer elections 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 concluded our long-standing negotiations with American Electric Power Service Corporation (“AEP”) to amend our long-term coal sales contract with them in October of 2011. The mutual goal of the parties was achieved to amend the contract to extend the term of the agreement, establish a future pricing methodology acceptable to both parties, and adjust the amounts of fixed and optional coal tonnage covered by the contract. In this amendment, the pricing is tied to and adjusted annually based on weekly indices reflecting current market pricing for the subsequent year which become the fixed contract price for the next year. Additionally, in exchange for market-based pricing, we no longer receive price and fuel adjusters under this contract. By reason of this amendment, the current term of the contract now runs through 2015, and it can be automatically extended for a further three-year term through 2018 if AEP gives us eighteen months advance notice of its election to extend the contract. Further, in more recent negotiations we have reached an agreement in principle to reduce the 2012 contract tonnage in exchange for a compensating increase in pricing, and we are working to formalize that arrangement in a contract amendment.

On March 2, 2012, we received a notice of contract termination from Big Rivers Electric Corporation (“Big Rivers”). The notice notified us that Big Rivers was terminating the Amended and Restated Coal Supply Agreement between Big Rivers and us (the “Big Rivers Agreement”) effective as of the close of business on March 2, 2012, pursuant to provisions of the Big Rivers Agreement permitting termination in certain circumstances where coal deliveries have not conformed to the quality specifications in the Big Rivers Agreement. The Big Rivers Agreement provides for us to supply to Big Rivers 800,000 tons of coal per year, and absent any termination thereof the term of the Big Rivers Agreement runs until December 31, 2015. We have met with representatives of Big Rivers on two occasions following this action (on March 7 and March 12, 2012), but have been unable to achieve any satisfactory resolution of the issues during these meetings. We are assessing the validity of the termination notice and any recourse that we may have under the Big Rivers Agreement or otherwise with respect to the actions by Big Rivers, including the termination. We are also assessing the financial and operational impact that such a termination would have on us and reviewing various alternatives, including without limitation mine closure(s) and related cost reduction measures, to compensate for and/or lessen any impact from such actions by Big Rivers and to bring our production and related cost structure in balance with our remaining contractual commitments.

We are currently experiencing a general softening of the coal markets and waning coal demand. As a result, it has been necessary to take steps to accommodate the changing supply profile of some customers. We are also focused on reviewing and modifying our operations to manage controllable costs and eliminate discretionary capital expenditures. We recently reached an agreement for 2012 and 2013 to purchase coal on more favorable terms rather than supplying our own washed coal on certain Illinois Basin customer contracts, enabling us to idle one of our mines and shut down a washplant for our Illinois Basin operations. These steps are expected to result in cost savings in 2012.

 

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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 transactions relating to the closing of our initial public offering and our $175 million credit facility in July 2010, (ii) the acquisition of Illinois Basin assets from Phoenix Coal on September 30, 2009 and (iii) an amendment to a long-term coal sales contract with a major customer in December 2008.

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 18 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.

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 and 2011. However, only three months of financial results from this acquisition are included in our consolidated financial statements for 2009.

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. This price increase contributed $13.3 million to revenue and adjusted EBITDA for 2009.

 

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Summary

The following table presents certain of our historical consolidated financial data for the periods indicated and contains both GAAP and non-GAAP financial measures:

 

     Years Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Statement of Operations Data:

      

Revenues:

      

Coal sales (1)

   $ 343,741      $ 311,567      $ 254,171   

Transportation revenue

     47,305        38,490        32,490   

Royalty and non-coal revenue

     9,331        6,521        7,183   
  

 

 

   

 

 

   

 

 

 

Total revenues

     400,377        356,578        293,844   

Costs and expenses:

      

Cost of coal sales (excluding DD&A, shown separately)

     272,420        229,468        170,698   

Cost of purchased coal

     13,480        22,024        19,487   

Cost of transportation

     47,305        38,490        32,490   

Depreciation, depletion and amortization

     51,905        42,329        25,902   

Selling, general and administrative expenses

     13,739        14,757        13,242   

Contract termination and amendment expenses, net

     —          652        —     
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

     398,849        347,720        261,819   

Income from operations

     1,528        8,858        32,025   

Interest income

     13        12        35   

Interest expense

     (9,870     (9,511     (6,484

Gain on purchase of business

     —          —          3,823   
  

 

 

   

 

 

   

 

 

 

Net (loss) income

     (8,329     (641     29,399   

Less: Net (loss) income attributable to noncontrolling interest

     (4,748     (6,710     (5,895
  

 

 

   

 

 

   

 

 

 

Net (loss) income attributable to Oxford Resource Partners, LP unitholders

   $ (13,077   $ (7,351   $ 23,504   
  

 

 

   

 

 

   

 

 

 

Other Financial Data:

      

Adjusted EBITDA(1) (2)

   $ 54,037      $ 51,617      $ 56,967   
  

 

 

   

 

 

   

 

 

 

 

(1) 

Included in the operating results for 2009 is $13.3 million of coal sales revenue related to a temporary price increase as discussed above in “Factors Affecting the Comparability of Our Results of Operations.”

(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 available to common 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 (loss) income attributable to unitholders to adjusted EBITDA for the periods indicated:

Reconciliation of net (loss) income attributable to Oxford Resource Partners, LP

unitholders to adjusted EBITDA

 

     Years Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Net (loss) income attributable to Oxford Resource Partners, LP unitholders (1)

   $ (13,077   $ (7,351   $ 23,504   

PLUS:

      

Interest expense, net of interest income

     9,857        9,499        6,449   

Depreciation, depletion and amortization

     51,905        42,329        25,902   

Non-cash equity-based compensation expense

     1,077        942        472   

Non-cash loss on asset disposals

     1,352        1,228        1,177   

Non-cash change in future asset retirement obligations

     3,355        5,742        4,991   

Acquisition costs

     507        —          —     

Contract termination and amendment expenses, net

     —          652        —     

LESS:

      

Gain on purchase of business

     —          —          3,823   

Amortization of below-market coalsales contracts

     939        1,424        1,705   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA (2)

   $ 54,037      $ 51,617      $ 56,967   
  

 

 

   

 

 

   

 

 

 

 

(1) 

Included in the operating results for 2009 is $13.3 million of coal sales related to a temporary price increase as discussed above in “– Factors Affecting the Comparability of Our Results of Operations.”

(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 available 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 loss attributable to unitholders to adjusted EBITDA and distributable cash flow for the periods indicated:

Reconciliation of net loss attributable to Oxford Resource Partners, LP unitholders to

adjusted EBITDA and distributable cash flow

 

     Year ended
December 31,
2011
 
     (in thousands)  

Net loss attributable to Oxford Resource Partners, LP unitholders

   $ (13,077

PLUS:

  

Interest expense, net of interest income

     9,857   

Depreciation, depletion and amortization

     51,905   

Non-cash equity-based compensation expense

     1,077   

Non-cash loss on asset disposals

     1,352   

Non-cash change in future asset retirement obligations

     3,355   

Acquisition costs

     507   

LESS:

  

Amortization of below-market sales contracts

     939   
  

 

 

 

Adjusted EBITDA

     54,037   

LESS:

  

Cash interest expense, net of interest income and excluding amendment fees

     7,784   

Estimated reserve replacement expenditures

     5,797   

Other maintenance capital expenditures

     32,159   
  

 

 

 

Distributable cash flow (1)

   $ 8,297   
  

 

 

 

 

 

(1)

We started calculating distributable cash flow in July 2010 and periods subsequent thereto during which we were a publicly traded partnership. We did not calculate distributable cash flow with respect to periods prior thereto, and thus we do not have any comparable amounts for the years ended December 31, 2010 and 2009.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Overview. The net loss for 2011 was $13.1 million, or $0.62 per diluted limited partner unit, compared to a net loss for 2010 of $7.4 million, or $0.45 per diluted limited partner unit. Adjusted EBITDA for 2011 was $54.0 million, up 4.7% from $51.6 million for 2010. Distributable cash flow for the year ended December 31, 2011 was $8.3 million, with no comparable amount for 2010.

Coal Production. Our tons of coal produced increased 6.9% to 8.0 million tons for 2011 from 7.5 million tons for 2010. This increase was primarily attributable to increased production at our Muhlenberg County complex resulting from the addition of major mining equipment and a reduction in strip ratio.

Sales Volume. Our sales volume increased 3.8% to 8.5 million tons for 2011 from 8.2 million tons for 2010. This increase was primarily attributable to the increase in our tons of coal produced and corresponding tons sold primarily from our Muhlenberg County complex.

Average Sales Price Per Ton (Net of Transportation Expenses). Our average sales price per ton (net of transportation expenses) increased 6.3% to $40.64 for 2011 from $38.22 for 2010. This $2.42 per ton increase was primarily attributable to the replacement of lower priced legacy contracts, higher contracted sales price realizations from fuel and other cost escalators and changes in customer mix. This increase is partially offset by higher transportation costs of $0.87 per ton.

 

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Coal Sales Revenue. Coal sales revenue for 2011 increased by $32.2 million, or 10.3%, to $343.7 million from $311.6 million for 2010. This increase was due to our higher average selling price of $2.42 per ton as well as the 3.8% increase in tons sold.

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 increased to $9.3 million for 2011 from $6.5 million for 2010. This increase primarily resulted from $2.0 million of higher revenue from the sale of limestone that we recover in connection with our coal mining operations combined with moderate increases in the fees that we receive for performing related services for others and the royalties received from subleasing our underground coal reserves.

Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased $43.0 million or 18.7% to $272.4 million for 2011 from $229.5 million for 2010. Cost of coal sales per ton increased 9.0% to $33.72 per ton for 2011 from $30.94 per ton for 2010. This $2.78 per ton increase resulted primarily from an increase in diesel fuel costs of $1.53 per ton, higher wages and benefits of $0.54 per ton, higher costs for repairs, maintenance and supplies of $0.43 per ton and higher royalty and production taxes of $0.23 per ton.

Cost of Purchased Coal. Cost of purchased coal decreased to $13.5 million for 2011 from $22.0 million for 2010. The decrease of $8.5 million was primarily attributable to a 71.7% or 423,000 ton reduction in the tons of coal purchased by our Muhlenberg County complex. We have experienced performance issues with a key supplier under a long-term contract which resulted in a reduction in tons available for purchase. The supplier has asserted that the contract is terminated by its terms, while we have taken a contrary position. We are now working with the supplier to resolve the matter. Our average cost of purchased coal for 2011 increased by 18.2% to $35.47 per ton due to fewer low cost tons being available for purchase from this key supplier.

Depreciation, Depletion and Amortization (DD&A). DD&A expense for 2011 was $51.9 million compared to $42.3 million for 2010, an increase of $9.6 million. This increase was primarily the result of increases in depreciation and amortization expenses of approximately $4.2 million and $5.6 million, respectively. The increase in depreciation expense primarily resulted from the full year impact of depreciation on previously leased and additional major mining equipment purchased in 2010 with the proceeds from our initial public offering and borrowings under our $175 million credit facility. The increase in amortization expense primarily resulted from the increase in cost estimates associated with measuring our asset retirement obligations.

Selling, General and Administrative Expenses (SG&A). SG&A expenses for 2011 were $13.7 million compared to $14.8 million for 2010, a decrease of $1.1 million. This decrease primarily resulted from reductions in public company costs of $0.8 million incurred in connection with our initial public offering in 2010.

Contract Termination and Amendment Expenses, Net. Contract termination and amendment expenses, net for 2011 were zero compared to $0.7 million for 2010. For 2010, there was a one-time charge of $2.5 million resulting from the termination of an advisory agreement with certain affiliates of AIM Oxford in connection with our initial public offering, offset by a $1.8 million reduction in a specific reserve for a below-market coal supply contract assumed in the purchase of our Illinois Basin assets that was amended to reset the price to a market rate during 2010.

Transportation Revenue and Expenses. Transportation revenue and expenses for 2011 increased 22.9% compared to 2010. This increase resulted from increases in the volume of our coal shipments and higher rates related to higher diesel fuel costs. Transportation expenses per ton sold increased 18.4% to $5.59 for 2011 from $4.72 for 2010, which negatively impacted our average sales price (net of transportation expenses) by $0.87 per ton.

Interest Expense (Net of Interest Income). Interest expense (net of interest income) for 2011 was $9.9 million compared to $9.5 million for 2010, an increase of $0.4 million. This increase was attributable to interest expense of $0.8 million resulting from higher borrowings outstanding, plus credit facility amendment fees and higher amortization of deferred financing costs incurred of $0.6 million and $0.4 million, respectively, in connection with our $175 million credit facility during 2011. These increases were partially offset by a loss on debt extinguishment of $1.3 million associated with the termination of our $115 million credit facility during 2010.

 

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Net Income Attributable to Noncontrolling Interest. For 2011 and 2010, the net income attributable to noncontrolling interest was $4.7 million and $6.7 million, respectively. This decrease resulted from lower production volumes as a result of a significant increase in the strip ratio in the area currently being mined. We anticipate that this increased strip ratio will remain for much of 2012 and consequently have a negative impact on production volumes and costs in 2012.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Overview. The net loss for 2010 was $7.4 million, or $0.45 per diluted limited partner unit, compared to 2009 net income of $23.5 million, or $2.08 per diluted limited partner unit. Adjusted EBITDA for 2010 was $51.6 million versus $57.0 million for 2009. Our distributable cash flow for the last half of 2010 during which we were a publicly traded partnership was $8.5 million. We did not calculate distributable cash flow for periods prior to becoming a publicly traded partnership, so there was no comparable amount for 2009.

Coal Production. Our tons of coal produced increased 27.8% to 7.5 million tons for 2010 from 5.8 million tons for 2009. This increase was primarily due to a full year of coal production of 1.7 million tons for 2010 as compared to 0.4 million tons for 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.

Sales Volume. Our sales volume increased 29.2% to 8.1 million tons for 2010 from 6.3 million tons for 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 (Net of Transportation Expenses). Our average sales price per ton (net of transportation expenses) decreased 5.1% to $38.22 for 2010 from $40.27 for 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 during 2009 as discussed above in “– Factors Affecting the Comparability of Our Results of Operations.” This decrease is partially offset by lower transportation costs of $0.43 per ton.

Coal Sales Revenue. Our coal sales revenue for 2010 increased by $57.4 million, or 22.6%, from $254.2 million for 2009. This increase was primarily attributable to a full year of coal sales of $74.3 million for 2010 as compared to $21.0 million for 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 realization during 2009 of $13.3 million of revenue relating to the temporary price increase previously discussed above in “– Factors Affecting the Comparability of Our Results of Operations.”

Royalty and Non-Coal Revenue. Our royalty and non-coal revenue decreased to $6.5 million for 2010 from $7.2 million for 2009. This decrease was primarily attributable to a $1.7 million temporary royalty revenue 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 for 2010 from $170.7 million for 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 for 2010 compared to $29.52 for 2009. This increase resulted in part from higher operating costs due to the delay of the Rose France mine permit at our Muhlenberg County complex, 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 for 2010 from $19.5 million for 2009. The increase of $2.5 million was primarily attributable to higher volumes purchased under a long-term coal purchase contract assumed in our acquisition of the Illinois Basin assets. Our average cost of purchased coal per ton decreased by 18.5% to $30.00 for 2010 due to a significant portion of our purchases for 2010 being supplied under the long-term coal purchase contract compared to higher-priced spot market purchases for 2009.

Depreciation, Depletion and Amortization (DD&A). DD&A expense for 2010 was $42.3 million compared to $25.9 million for 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 from our acquisition of the Illinois Basin assets, and the remaining increase of $8.5 million related primarily to full-year depreciation on equipment placed in service in late 2009 and depreciation on previously leased and additional major mining equipment that we purchased with proceeds of our initial public offering.

 

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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 due to an increase of $1.0 million in public company expenses and $0.6 million of additional administrative expenses associated with our then recently acquired Illinois Basin operations.

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 resulted 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 the Illinois Basin assets that was amended to reset the price to a market rate starting in 2010.

Transportation Revenue and Expenses. Transportation revenue and expenses for 2010 increased 18.5% compared to 2010. 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. Transportation expenses per ton sold decreased 8.3% to $4.72 for 2010 from $5.15 for 2009. This decrease of $0.43 per ton results from the full year impact of lower transportation expenses from our Muhlenberg County complex in the Illinois Basin, which had a favorable impact on our average sales price (net of transportation expenses).

Interest Expense (Net of Interest Income). Interest expense (net of interest income) 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. For 2010 and 2009, the net income attributable to noncontrolling interest was $6.7 million and $5.9 million, respectively. 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.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in mining our reserves, as well as complying with applicable environmental laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, service our debt and pay cash distributions to our unitholders. Our primary sources of liquidity to meet these needs have been cash generated by our operations, borrowings under our credit facilities and proceeds from our initial public offering as well as contributions from our partners prior to our initial public offering.

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. As of December 31, 2011, we had borrowing availability under our $175 million credit facility of $5.1 million. Our available liquidity as of December 31, 2011 was $8.1 million, which consisted of $3.0 million in cash on hand and the $5.1 million of borrowing availability under our $175 million credit facility.

On December 28, 2011, we entered into a Third Amendment to Credit Agreement (the "Third Amendment") with Citicorp USA, Inc., as administrative agent, and the lenders party thereto, amending the credit agreement for our $175 million credit facility. Pursuant to the terms of the Third Amendment, the parties agreed to modify certain financial covenants set forth in such credit agreement. These modifications included (i) increasing the existing leverage ratio of 2.75 to 1 to 3.25 to 1 for the period from January 1, 2012 through June 30, 2012 and to 3.00 to 1 for all periods thereafter and (ii) increasing the maximum scheduled amount of permitted capital expenditures for fiscal year 2011 from $40 million to $43 million. The definitions of and methods used to determine the leverage ratio and permitted capital expenditures remain unchanged and are set forth in such credit agreement. The resulting effect of this amendment was to increase our borrowing availability effective January 1, 2012 to $27.5 million.

 

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Going forward, we expect our sources of liquidity to include:

 

   

our working capital;

 

   

cash generated from operations;

 

   

borrowing under our $175 million credit facility;

 

   

issuances of additional partnership units; and/or

 

   

debt offerings.

Our ability to satisfy our working capital requirements and debt service obligations, fund planned capital expenditures and pay our quarterly distributions substantially depends upon our future operating performance (which may be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control. To the extent our operating cash flow or access to financing sources and the costs thereof are materially different than expected; our future liquidity may be adversely affected and may impair our future ability to meet all or a portion of our distributions to unitholders.

For the year ended December 31, 2011, our distributable cash flow covered 22.5% of our distributions to our common and subordinated unitholders and our general partner and 44.8% when considering only the distribution required to effect a distribution limited to our common unitholders and our general partner.

Please read “— Capital Expenditures” below for a further discussion on the impact of capital expenditures on liquidity.

Cash Flows

The following table reflects cash flows for the years indicated:

 

     Years Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Net cash provided by (used in):

      

Operating activities

   $ 44,534      $ 40,268      $ 38,637   

Investing activities

     (41,444     (84,894     (49,171

Financing activities

     (947     42,149        (1,279

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net cash provided by operating activities was $44.5 million for 2011, an increase of $4.2 million from net cash provided by operating activities of $40.3 million for 2010. This increase was primarily due to favorable working capital changes.

Net cash used in investing activities was $41.4 million for 2011, a decrease of $43.5 million from net cash used in investing activities of $84.9 million for 2010. This decrease was primarily attributable to the purchases of major mining equipment and the buy-out of equipment operating leases that occurred in the third quarter of 2010 from proceeds of our initial public offering and borrowings under our $175 million credit facility.

Net cash used in financing activities was $0.9 million for 2011 compared to net cash provided by financing activities of $42.1 million for 2010. This $43.0 million decrease was primarily attributable to the absence of initial public offering proceeds in 2011.

 

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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. This increase was primarily due to favorable working capital changes.

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 purchase of major mining equipment and the buy-out of equipment operating leases that occurred in the third quarter of 2010 from the proceeds of our initial public offering and borrowings under our $175 million credit facility, partially offset by the $18.3 million used in connection with our acquisition of the 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.

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, 2011, we had borrowings of $131 million outstanding under our $175 million credit facility, consisting of a $51 million term loan and borrowings of $80 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, 2011, we had letters of credit outstanding in support of these surety bonds of $7.5 million.

The term loan and revolving credit facility 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) as described below, 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. On December 28, 2011, we amended the credit agreement for our $175 million credit facility to modify certain financial covenants set forth in the credit agreement. These modifications included (i) increasing the existing leverage ratio of 2.75 to 1 to 3.25 to 1 for the period from January 1, 2012 through June 30, 2012 and to 3.00 to 1 for all periods thereafter and (ii) increasing the maximum scheduled amount of permitted capital expenditures for fiscal year 2011 from $40 million to $43 million. The definitions of and methods used to determine the leverage ratio and permitted capital expenditures remain unchanged and are set forth in such credit agreement.

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.

 

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Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations as of December 31, 2011 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

   $ 131,000       $ 6,000       $ 125,000       $ —         $ —     

Future interest obligations—long-term debt (1)

     12,980         7,314         5,666         —           —     

Other long-term debt (2)

     12,755         5,234         7,516         5         —     

Future interest obligations—other long-term debt

     900         544         356         —           —     

Fixed-price diesel fuel purchase contracts

     41,227         41,227         —           —           —     

Operating lease obligations

     11,400         3,324         6,607         1,452         17   

Long-term coal purchase contract (3) 

     67,548         18,548         19,600         19,600         9,800   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 277,810       $ 82,191       $ 164,745       $ 21,057       $ 9,817   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Interest on variable rate long-term debt was calculated using rates estimated by us at December 31, 2011 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 16 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Commitments and Contingencies.” We have experienced supplier performance issues under this contract which continued through 2011 and still persist in 2012. The supplier has asserted that this contract is terminated, while we have taken a contrary position. We are now working with the supplier to resolve the matter.

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.

At December 31, 2011, we had outstanding commitments for approximately $12.2 million of expansion capital expenditures and $0.3 million of other maintenance capital expenditures. For 2012, we expect to incur $4.0 to $5.0 million of reserve replacement expenditures, $27.0 to $32.0 million of other maintenance capital expenditures and $13.0 to $15.0 million of expansion capital expenditures. We expect to fund $20.0 to $22.0 million of our capital expenditures with operating leases which will lower both adjusted EBITDA and distributable cash flow by approximately $5.0 million.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, surety bonds, performance bonds and road bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

 

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Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond and we typically use bank letters of credit to secure our surety 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, 2011, we had approximately $38.5 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $7.5 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.

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. There was no allowance for doubtful accounts at December 31, 2011 and 2010.

 

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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 such as overhead and stripping costs incurred during 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, 2011 and 2010, 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 minimus 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.

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.

 

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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. 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, 2011, 2010 and 2009. 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 acquisition of Phoenix Coal. These intangible assets are being amortized over their expected useful lives. See the Below-Market 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.

Asset Retirement Obligations

Our asset retirement obligations (“ARO”) arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our ARO 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 at a lower cost to us. Hence, the estimated costs used in determining the carrying amount of our ARO may exceed the amounts that are eventually paid for reclamation costs if the reclamation work is performed using internal resources.

Effective June 30, 2011, we changed our method for estimating the ARO for our mines from the current disturbance method to the end of mine life method. This represents a change in accounting estimate effected by a change in method to a method which is a preferable method under GAAP. We believe the end of mine life method results in a more precise estimate and is more consistent with industry practice.

The end of mine life method focuses on estimating the liability based upon the productive life of the mine and more specifically the last pit(s) to be reclaimed once the mine is no longer producing coal as opposed to the individual pits created throughout the mine’s life under the current disturbance method.

The balance sheet effects of the change in accounting method resulted in a reclassification of approximately $6.2 million from the current portion of ARO to the long-term portion of ARO. The impact of the change in method was negligible to our consolidated statement of operations for the period ended June 30, 2011 and December 31, 2011. This change was accounted for in the quarter ended June 30, 2011 and all financial statement measurement periods subsequent thereto, in accordance with ASC 250.

 

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To determine the fair value of our ARO, we calculate on a mine-by-mine basis the present value of estimated reclamation cash flows. This process requires us to estimate the acreage subject to reclamation, estimate future reclamation costs and make assumptions regarding the mine’s productivity and related mining plan. 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 mine development 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. If the assumptions used to estimate the ARO liability 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 any changes to our mining plans and the timing of the expected reclamation expenditures.

In 2011, the revisions in estimated cash flows resulted in a net increase in the ARO of $13.7 million and was primarily attributable to mine development at eight new mines, as well as revisions to estimates of the expected costs for stream and wetland mitigation as regulatory requirements continue to evolve along with changes in estimated third-party unit costs. Adjustments to the ARO due to such revisions generally result in a corresponding adjustment to the related asset retirement cost in mine development. The portion of the revisions attributable to the change in method was negligible.

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 customer 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. The majority of the repayment was recognized in 2009 with the remaining $2,090,000 recognized in 2010.

Freight and handling costs paid to third party carriers and invoiced to customers are recorded as transportation expenses 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, service fees at one of our river barge loading facilities for loading services provided to a third party coal mining company 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. For the years ended December 31, 2011, 2010 and 2009, we received royalties of $3.2 million, $2.8 million and $4.5 million, respectively. In August 2011, we terminated the services agreement for providing landfill earth moving and transportation services which was set to expire on December 31, 2011 (see Note 18 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K under the heading “Related Party Transactions”).

 

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Below-Market Coal Sales Contracts

Our below-market coal sales contracts were acquired through the Phoenix Coal acquisition 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 fair value of our LTIP units 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.”

Noncontrolling Interest

We have adopted accounting guidance that establishes accounting and reporting standards for (1) noncontrolling interests in partially owned consolidated subsidiaries and (2) the loss of control of subsidiaries. This guidance requires noncontrolling interests (minority interests) to be reported as a separate component of equity. The amount of net income or loss attributable to the noncontrolling interests will be included in consolidated net income or loss on the face of the income statement. In addition, this guidance requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. Such gain or loss will be measured using the fair value of the noncontrolling equity investment on the deconsolidation date.

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 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 this guidance was permitted. The adoption of this guidance did not have a material effect on our consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement – Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards ("IFRSs"). This guidance amends certain accounting and disclosure requirements related to fair value measurements to ensure that fair value has the same meaning in U.S. GAAP and in IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective for public entities during interim and annual periods beginning after December 15, 2011. Early adoption of this guidance was not permitted. We do not believe that the adoption of this guidance will have a material impact on our consolidated financial statements.

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income – Presentation of Comprehensive Income, which amends current comprehensive income guidance. This guidance eliminates the option to present the components of other comprehensive income as part of the statement of shareholders' equity. Instead, comprehensive income must be reported in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance is effective for public companies during the interim and annual periods beginning after December 15, 2011. Early adoption of this guidance was permitted. We do not believe that the adoption of this guidance will have a material impact on our consolidated financial statements.

There were various other updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries. We do not believe that the adoption of the guidance provided by these updates 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 with fuel cost pass through or cost adjustment provisions and varying terms and durations. Additionally, we enter into fixed price fuel purchase contracts to hedge our commodity price risk where we do not have fuel cost pass through or cost adjustment provisions in our long-term sales contracts. There is a risk with these fuel purchase contracts that the counterparty will be unable to or otherwise fails to perform.

 

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We believe that the price risks associated with our diesel fuel expense is significant. Taking into account our fixed price fuel purchase contracts, we estimate that a hypothetical increase of $0.30 per gallon of diesel fuel would have increased our fuel and hauling costs and reduced net income attributable to our unitholders by $4.8 million for the year ended December 31, 2011. If this hypothetical increase had occurred, we estimate that fuel cost pass through or cost adjustment provisions in our long-term coal sales contracts would have provided a corresponding increase in revenue and net income attributable to our unitholders in amounts equal to the amounts referred to above for the year ended December 31, 2011.

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 $50.0 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 fair value of the derivative liability of $156,000 and $108,000 was recorded in other liabilities as of December 31, 2011 and 2010, respectively. The increase in value of $48,000 and $108,000 was recorded in interest expense for the year ended December 31, 2011 and 2010, respectively. The balance of the amortizing interest rate swap agreement was $41.0 million at December 31, 2011.

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 mark-to-market decrease in value of $51,000 was recorded to interest expense in the consolidated statements of operations for the year ended December 31, 2009.

We entered into an interest rate swap agreement on August 24, 2007 that had an original notional principal amount of $67.5 million and matured in August 2009. Under the swap agreement, we paid interest at a fixed rate of 4.83% and received interest at a variable rate equal to LIBOR (1.43% as of December 31, 2008), based on the notional amount. The change in the fair value and settlement of the swap agreement decreased interest expense by $1,681,000 for the year ended December 31, 2009.

At December 31, 2011, the variable interest rate on our debt under the $175 million credit facility was 5.5%, calculated at the 30-day LIBOR rate, subject to a floor of 1.0%, plus the applicable margin of 4.5%. Based on our borrowings at the end of 2011, a hypothetical 100 basis point increase in short term interest rates would result, over the subsequent twelve-month period, in reduced net income attributable to our unitholders of approximately $0.2 million. At December 31, 2011, the 30 day LIBOR was 71 basis points below the 1% LIBOR floor. As a result, the $0.2 million hypothetical reduction noted above represents the 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 29 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, 2011 and 2010 and the related consolidated statements of operations, partners’ equity and cash flows for the years ended December 31, 2011, 2010 and 2009, together with the report of the independent registered public accounting firm thereon, appear on pages F-1 through F-32 hereof and are incorporated herein by reference.

 

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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, 2011, 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.

Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Our internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of the end of the period covered by this report, our management carried out an evaluation, with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon that evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.

The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by Grant Thornton, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm included in this Annual Report on Form 10-K.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Oxford Resource Partners, LP

We have audited Oxford Resource Partners, LP’s (a Delaware limited partnership) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Oxford Resource Partners, LP’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on Oxford Resource Partners, LP’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Oxford Resource Partners, LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oxford Resource Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2011, and our report dated March 14, 2012 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 14, 2012

 

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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, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

ITEM 9B. OTHER INFORMATION

Effective March 14, 2012, our general partner entered into new employment agreements (the “New Agreements”) with each of the following named executive officers: (i) Charles C. Ungurean, President and Chief Executive Officer, (ii) Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer, (iii) Gregory J. Honish, Senior Vice President, Operations, and (iv) Daniel M. Maher, Senior Vice President, Chief Legal Officer and Secretary (individually a “Referenced Officer” and collectively the “Referenced Officers”). The New Agreements establish customary employment terms for the Referenced Officers including base salaries, bonuses and other incentive compensation and other benefits and provision for duties and titles, and replace and supersede the prior employment agreements which had been in effect between our general partner and each of the Referenced Officers (individually a “Prior Agreement” and collectively the “Prior Agreements”).

The primary reasons for entering into the New Agreements were twofold. First, the Prior Agreements had terms expiring July 19, 2012 (except for Mr. Maher’s Prior Agreement where the term was expiring on December 31, 2012), and, notwithstanding the automatic extension provisions set forth in the Prior Agreements, our general partner’s Board of Directors (the “Board”) and the Compensation Committee of the Board (the “Compensation Committee”) considered it advisable to extend the terms early, consistent with their practice of seeking to extend the terms of executive employment agreements that they wish to have extended before the operation of automatic extension provisions. And second, in the latter part of 2011 the Compensation Committee retained a leading compensation consultant to assist it in evaluating certain aspects of the compensation program for our named executive officers, and as a result of that evaluation process the Compensation Committee identified specific compensation changes for implementation in the New Agreements.

The principal changes from the Prior Agreements made in all of the New Agreements for the Referenced Officers include (i) extending the initial terms thereof to run until December 31, 2013, (ii) clarifying the roles that the Compensation Committee and the Board play in the annual base salary, bonus and other incentive compensation decisions for the Referenced Officers and (iii) providing that their rights to severance benefits apply on the same basis at the time of termination of employment upon or following and notwithstanding expiration of the term of their New Agreements.

The other principal changes from the Prior Agreements made in various of the New Agreements are as follows:

 

   

Increasing the standard severance payment for each of Messrs. Gutman and Maher to two times his annual base salary in the event his employment is terminated by the Company without “Cause” (as defined in their respective New Agreements) or he terminates his employment for “Good Reason” (as defined in their respective New Agreements). For Mr. Gutman, the standard severance payment is reduced by any Supplemental Severance Payment described below that he receives. These standard severance benefits provided for in each of the applicable New Agreements continue to be conditioned on the applicable Referenced Officer executing a release of claims in favor of our general partner and its affiliates. Such severance payment benefit has existed previously for Mr. Charles Ungurean and another named executive officer, Thomas T. Ungurean, and for Mr. Charles Ungurean has been continued in his New Agreement.