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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K


ý

 

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

o

 

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

For the transition period from            to          

Commission file number: 001-34892

Rhino Resource Partners LP
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  27-2377517
(I.R.S. Employer
Identification No.)

424 Lewis Hargett Circle, Suite 250
Lexington, KY

(Address of principal executive offices)

 

40503
(Zip Code)

Registrant's telephone number, including area code: (859) 389-6500

         Securities registered pursuant to Section 12(b) of the Act:

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 o    No ý

         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 o    No ý

         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. Yes ý    No o

         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). Yes ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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. o

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

Large accelerated filer o   Accelerated filer ý   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

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

         As of June 30, 2011, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's equity held by non-affiliates of the registrant was approximately $90.2 million based on the closing price of the registrant's common units on the New York Stock Exchange. As of March 9, 2012, the registrant had 15,318,178 common units and 12,397,000 subordinated units outstanding.

         DOCUMENTS INCORPORATED BY REFERENCE

         Documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K

   


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TABLE OF CONTENTS

PART I

 

Item 1.

 

Business

    1  

Item 1A.

 

Risk Factors

    26  

Item 1B.

 

Unresolved Staff Comments

    55  

Item 2.

 

Properties

    55  

Item 3.

 

Legal Proceedings

    58  

Item 4.

 

Mine Safety Disclosure

    58  


PART II


 

Item 5.

 

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

    59  

Item 6.

 

Selected Financial Data

    62  

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

    66  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

    97  

Item 8.

 

Financial Statements and Supplementary Data

    98  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    98  

Item 9A.

 

Controls and Procedures

    98  

Item 9B.

 

Other Information

    100  


PART III


 

Item 10.

 

Directors, Executive Officers and Corporate Governance

    100  

Item 11.

 

Executive Compensation

    106  

Item 12.

 

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

    119  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    121  

Item 14.

 

Principal Accounting Fees and Services

    124  


PART IV


 

Item 15.

 

Exhibits, Financial Statement Schedules

    125  


FINANCIAL STATEMENTS


 

 

Index to Financial Statements

    F-1  

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GLOSSARY OF KEY TERMS

        ash:    Inorganic material consisting of iron, alumina, sodium and other incombustible matter that are contained in coal. The composition of the ash can affect the burning characteristics of coal.

        assigned reserves:    Proven and probable reserves that have the permits and infrastructure necessary for mining.

        as received:    Represents an analysis of a sample as received at a laboratory.

        Btu:    British thermal unit, or Btu, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

        Central Appalachia:    Coal producing area in eastern Kentucky, Virginia and southern West Virginia.

        coal seam:    Coal deposits occur in layers typically separated by layers of rock. Each layer is called a "seam." A seam can vary in thickness from inches to a hundred feet or more.

        coke:    A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel.

        EIA:    Energy Information Administration.

        fossil fuel:    A hydrocarbon such as coal, petroleum or natural gas that may be used as a fuel.

        GAAP:    Generally accepted accounting principles in the United States.

        high-vol metallurgical coal:    Metallurgical coal that has a volatility content of 32% or greater of its total weight.

        Illinois Basin:    Coal producing area in Illinois, Indiana and western Kentucky.

        limestone:    A rock predominantly composed of the mineral calcite (calcium carbonate (CaCO3)).

        lignite:    The lowest rank of coal. It is brownish-black with a high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu.

        low-vol metallurgical coal:    Metallurgical coal that has a volatility content of 17% to 22% of its total weight.

        mid-vol metallurgical coal:    Metallurgical coal that has a volatility content of 23% to 31% of its total weight.

        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.

        non-reserve coal deposits:    Non-reserve coal deposits are coal-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrants further exploration stage work. However, this coal does not qualify as a commercially viable coal reserve as prescribed by standards of the SEC until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geologic limitations, or both.

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        non-reserve limestone deposits:    Similar to non-reserve coal deposits, non-reserve limestone deposits are limestone-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling, and underground workings to assume continuity between sample points, and therefore warrants further exploration stage work. However, this limestone does not qualify as a commercially viable limestone reserve as prescribed by standards of the SEC until a final comprehensive evaluation based on unit cost per ton, recoverability, and other material factors concludes legal and economic feasibility. Non-reserve limestone deposits may be classified as such by either limited property control or geologic limitations, or both.

        Northern Appalachia:    Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

        overburden:    Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

        preparation plant:    Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process separates higher ash coal and may also remove some of the coal's sulfur content.

        probable (indicated) reserves:    Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

        proven (measured) reserves:    Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

        reclamation:    The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes "recontouring" or reshaping the land to its approximate original contour, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations, but the majority of reclamation costs are incurred once mining operations cease. Reclamation is closely regulated by both state and federal laws.

        reserve:    That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

        steam coal:    Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

        sulfur:    One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide (SO2) is produced as a gaseous by-product of coal combustion.

        surface mine:    A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil overburden. Surface mines are also known as open-pit mines.

        tons:    A "short" or net ton is equal to 2,000 pounds. A "long" or British ton is 2,240 pounds. A "metric" tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.

        Western Bituminous region:    Coal producing area located in western Colorado and eastern Utah.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

        This report contains "forward-looking statements." Statements included in this report 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 our plans, strategies, prospects and expectations concerning our business, operating results, financial condition and similar matters, 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 or our ability to predict. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

    changes in governmental regulation of the mining industry or the electric utility industry;

    adverse weather conditions and natural disasters;

    weakness in global economic conditions;

    decreases in demand for electricity and changes in demand for coal;

    poor mining conditions resulting from geological conditions or the effects of prior mining;

    equipment problems at mining locations;

    the availability of transportation for coal shipments;

    the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives;

    the availability and prices of competing electricity generation fuels;

    our ability to secure or acquire high-quality coal reserves;

    our ability to successfully diversify our operations into other non-coal natural resources;

    our ability to find buyers for coal under favorable supply contracts; and

    certain factors discussed elsewhere in this report, including those factors listed under "Risk Factors."

        Readers are cautioned not to place undue reliance on forward-looking statements. The forward-looking statements speak only as of the date made, 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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PART I

        Unless the context clearly indicates otherwise, references in this report to "Rhino Predecessor," "we," "our," "us" or similar terms when used for periods prior to the completion of the initial public offering of common units of Rhino Resource Partners LP on October 5, 2010 (the "IPO") refer to Rhino Energy LLC and its subsidiaries. When used for periods subsequent to the completion of the IPO, "we,""our,""us," or similar terms refer to Rhino Resource Partners LP and its subsidiaries. References to our "general partner" refer to Rhino GP LLC, the general partner of Rhino Resource Partners LP.

Item 1.    Business.

        We are a growth oriented Delaware limited partnership formed to control and operate coal properties and invest in other natural resource assets. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition to operating coal properties, we manage and lease coal properties and collect royalties from such management and leasing activities. We have also invested in oil and gas mineral rights that we expect to generate royalty revenues in future periods.

        We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2011, we controlled an estimated 437.0 million tons of proven and probable coal reserves, consisting of an estimated 415.6 million tons of steam coal and an estimated 21.4 million tons of metallurgical coal. In addition, as of December 31, 2011, we controlled an estimated 417.1 million tons of non-reserve coal deposits. As of December 31, 2011, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and for which we serve as manager, controlled an estimated 43.4 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 17.9 million tons of non-reserve coal deposits. As of December 31, 2011, we operated ten mines, including five underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. In addition, our joint venture operates one underground mine in West Virginia. During 2010, we operated one underground mine in Colorado, but we temporarily idled this mine at year end 2010 and this mine remained idle at the end of 2011. The number of mines that we operate may vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. Excluding results from the joint venture, for the year ended December 31, 2011, we produced approximately 4.6 million tons of coal, purchased approximately 0.3 million tons of coal and sold approximately 4.9 million tons of coal. Additionally, the joint venture produced and sold approximately 0.3 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2011. Additionally, lessees produced approximately 2.0 million tons of coal from our Elk Horn properties for the year ended December 31, 2011.

        Our principal business strategy is to safely, efficiently and profitably produce, sell and lease both steam and metallurgical coal from our diverse asset base in order to maintain, and, over time, increase our quarterly cash distributions. In addition, we intend to expand our operations through strategic acquisitions, including the acquisition of stable, cash generating natural resource assets. We believe that such assets would allow us to grow our cash available for distribution and enhance stability of our cash flow.

History

        Our predecessor was formed in April 2003 by Wexford Capital LP ("Wexford Capital", and together with certain of its affiliates and principals, "Wexford"). Wexford Capital is an SEC registered investment advisor which was formed in 1994 and manages a series of investment funds and has over $5.6 billion of assets under management. Since the formation of our predecessor, we have significantly grown our coal reserves. Since April 2003, we have completed numerous coal asset acquisitions with a


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total purchase price of approximately $353.0 million. Through these acquisitions and coal lease transactions, we have substantially increased our proven and probable coal reserves and non-reserve coal deposits. In addition, we have successfully grown our production through internal development projects.

        Included in our coal asset acquisitions, in June 2011 we completed the acquisition of 100% of the ownership interests in The Elk Horn Coal Company ("Elk Horn") for approximately $119.7 million in cash consideration. Elk Horn is primarily a coal leasing company located in eastern Kentucky that provides us with coal royalty revenues, which we believe helps to diversify our income stream while limiting our direct operational risk.

        In addition to our coal acquisitions, in 2011 we invested in oil and gas mineral rights in the Utica Shale region of eastern Ohio as well as the Cana Woodford region of western Oklahoma. During 2011, we invested a total of approximately $28.0 million in oil and gas mineral rights in these regions. While we continue to evaluate our options for our investments in these regions, we expect that royalty revenues can be generated in future periods from these investments, which we believe would help to further diversify our income stream.

        On October 5, 2010, we completed our IPO, in which we sold an aggregate of 3,730,600 common units to the public. Our common units are listed on the New York Stock Exchange under the symbol "RNO". In connection with the IPO, Wexford contributed their membership interests in Rhino Energy LLC to us, and we issued 12,397,000 subordinated units representing limited partner interests in us and 8,666,400 common units to Wexford and issued incentive distribution rights to our general partner. Principals of Wexford Capital, including certain directors of our general partner, own the majority of the membership interests in our general partner.

        In addition, on July 18, 2011, we completed a public offering of 2,875,000 common units, representing limited partner interests in us, at a price of $24.50 per common unit. Of the common units issued, 375,000 units were issued in connection with the exercise of the underwriters' option to purchase additional units.

        We are managed by the board of directors and executive officers of our general partner. Our operations are conducted through, and our operating assets are owned by, our wholly owned subsidiary, Rhino Energy LLC, and its subsidiaries.

Coal Operations

Mining and Leasing Operations

        As of December 31, 2011, we operated four mining complexes located in Central Appalachia (Tug River, Rob Fork, Deane and Rhino Eastern (owned by the joint venture with an affiliate of Patriot Coal Corporation, or "Patriot")) along with our Elk Horn coal leasing operations in Central Appalachia that were purchased in June 2011. In addition, we operated two mining complexes located in Northern Appalachia (Hopedale and Sands Hill). In the Western Bituminous region, we operated one mining complex beginning in early 2011 located in Emery and Carbon Counties, Utah (Castle Valley) that was purchased out of bankruptcy in August 2010. During 2010, we operated one mine located in the Western Bituminous region in Colorado (McClane Canyon) that has been temporarily idled since the end of 2010 and remained idle at the end of 2011. We have received a conditional permit to build a rail loadout at this location, pending bonding, and we plan to restart production at the McClane Canyon mine when market conditions are favorable.

        We define a mining complex as a central location for processing raw coal and loading coal into railroad cars or trucks for shipment to customers. These mining complexes include six active preparation plants and/or loadouts (including one owned by our joint venture partner), each of which receive, blend, process and ship coal that is produced from one or more of our active surface and

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underground mines. All of the preparation plants are modern plants that have both coarse and fine coal cleaning circuits. In addition to our six active preparation plants and/or loadouts, we are currently constructing an additional preparation plant at our Tug River mining complex that we expect to be operating in the second quarter of 2012. As of December 31, 2011, we had capital expenditure commitments of approximately $12.2 million related to completing the construction of the preparation plant.

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        The following map shows the location of our coal mining and leasing operations as of December 31, 2011:

GRAPHIC

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        Our surface mines include area mining and contour mining. These operations use truck and wheel loader equipment fleets along with large production tractors and shovels. Our underground mines utilize the room and pillar mining method. These operations generally consist of one or more single or dual continuous miner sections which are made up of the continuous miner, shuttle cars, roof bolters, feeder and other support equipment. We currently own most of the equipment utilized in our mining operations. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well-maintained. The rebuild programs are performed either by an on-site shop or by third-party manufacturers. The mobile equipment utilized at our mining operations is scheduled for replacement on an on-going basis with new, more efficient units according to a predetermined schedule.

        The following table summarizes our and the joint venture's mining complexes and production by region as of December 31, 2011. The tons produced by the Elk Horn lessees are not included in the table below since we did not directly mine these tons, but rather collected royalty revenues from the lessees.

 
   
   
  Number and
Type of Active Mines(2)
   
 
 
   
   
  Tons Produced
for the
Year Ended
December 31,
2011(3)
 
Region
  Preparation
Plants and
Loadouts
  Transportation
to Customers(1)
  Company
Operated
Mines
  Contractor
Operated
Mines
  Total
Mines
 
 
   
   
   
   
   
  (in million tons)
 

Central Appalachia

                                 

Tug River Complex (KY, WV)

  Jamboree(4)   Truck, Barge, Rail (NS)     1S         1S     0.4  

Rob Fork Complex (KY)

  Rob Fork   Truck, Barge, Rail (CSX)     1U, 2S         1U, 2S     1.3  

Deane Complex (KY)

  Rapid Loader   Rail (CSX)     1U     1U     2U     0.3  

Northern Appalachia

                                 

Hopedale Complex (OH)

  Nelms   Truck, Rail (OHC, WLE)     1U         1U     1.3  

Sands Hill Complex (OH)

  Sands Hill(5)   Truck, Barge     2S         2S     0.7  

Illinois Basin

                                 

Taylorville Field (IL)

  n/a   Rail (NS)                  

Western Bituminous

                                 

Castle Valley Complex (UT)

  Truck loadout   Truck     1U         1U     0.6  

McClane Canyon Mine (CO)(6)

  n/a   Truck                  
                           

Total

            4U,5S     1U     5U,5S     4.6  
                           

Central Appalachia

                                 

Rhino Eastern Complex (WV)(7)

  Rocklick   Truck, Rail (NS, CSX)     2U         2U        

(1)
NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE = Wheeling & Lake Erie Railroad.

(2)
Numbers indicate the number of active mines. U = underground; S = surface.

(3)
Total production based on actual amounts and not rounded amounts shown in this table.

(4)
Includes only a loadout facility.

(5)
Includes only a preparation plant.

(6)
The McClane Canyon mine was temporarily idled as of December 31, 2010 and remained idle as of December 31, 2011.

(7)
Owned by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the production. The Rocklick preparation plant is owned and operated by our joint venture partner with whom the joint venture has a transloading agreement for use of the facility.

        Central Appalachia.    As of December 31, 2011, we operated four mining complexes located in Central Appalachia consisting of five active underground mines, four of which are company-operated and one that is contractor-operated. In addition, we operated three company-operated surface mines. For the year ended December 31, 2011, the mines at our Tug River, Rob Fork and Deane mining complexes produced an aggregate of approximately 1.3 million tons of steam coal and an estimated 0.7 million tons of metallurgical coal, and the underground mines at the Rhino Eastern mining

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complex, owned by the joint venture in which we have a 51% membership interest and for which we serve as manager, produced approximately 0.3 million tons of metallurgical coal. In addition, for the year ended December 31, 2011, lessees of our Elk Horn properties produced approximately 2.0 million tons of coal since our acquisition of Elk Horn in June 2011.

        Tug River Mining Complex.    Our Tug River mining complex consists of property in Kentucky and West Virginia that borders the Tug River. Our Tug River mining complex produces coal from one company-operated surface mine. Coal production from this mine is delivered by truck to the Jamboree loadout for blending and loading or to the Rob Fork facilities for processing, blending and loading. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit train loadout with batch weighing equipment. The Jamboree loadout is used primarily to process surface mined coal which is sold as steam coal to electric utilities. This mining complex produced approximately 0.3 million tons of steam coal and approximately 0.1 million tons of metallurgical coal for the year ended December 31, 2011. As mentioned earlier, we are currently constructing an additional preparation plant at our Tug River mining complex that we expect to be operating in the first quarter of 2012. This new preparation plant will allow us to discontinue our need to transport coal from this complex to our Rob Fork preparation plant, which we believe will provide us cost savings in future periods.

        Rob Fork Mining Complex.    Our Rob Fork mining complex is located in eastern Kentucky and currently produces coal from two company-operated surface mines and one company-operated underground mine. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers' needs. The Rob Fork mining complex produced approximately 0.8 million tons of steam coal and 0.5 million tons of metallurgical coal for the year ended December 31, 2011.

        Deane Mining Complex.    Our Deane mining complex is located in eastern Kentucky and produces steam coal from one company-operated underground mine and one contractor-operated underground mine. The infrastructure consists of a preparation plant utilizing heavy media circuitry capable of cleaning coarse and fine coal size fractions, as well as a unit train loadout facility with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in approximately four hours. The facility has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers' needs. The Deane complex produced approximately 0.3 million tons of steam coal for the year ended December 31, 2011.

        Rhino Eastern Mining Complex.    The Rhino Eastern mining complex is located in Raleigh and Wyoming Counties, West Virginia. We have a 51% membership interest in, and serve as manager for, the joint venture that owns the Rhino Eastern mining complex. Pursuant to the terms of a coal purchase agreement entered into under the joint venture agreement, an affiliate of our joint venture partner, Patriot, controls the amount and terms of sales of the coal produced from the Rhino Eastern mining complex.

        The Rhino Eastern mining complex currently produces premium metallurgical coal from two company-operated underground mines. Raw coal is trucked from the mine to a facility owned by our joint venture partner to be sized, washed and shipped by truck or via one of two rail loadouts, located on the CSX Railroad and the Norfolk Southern Railroad. The Rhino Eastern mining complex produced approximately 0.3 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2011.

        Elk Horn Coal Leasing.    In June 2011, we completed the acquisition of 100% of the ownership interests in Elk Horn for approximately $119.7 million in cash consideration. Elk Horn is a primarily coal leasing company located in eastern Kentucky that provides us with coal royalty revenues. For the

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year ended December 31, 2011, Elk Horn lessees produced approximately 2.0 million tons of coal from our Elk Horn properties.

        Northern Appalachia.    We operate two mining complexes located in Northern Appalachia consisting of one company-operated underground mine and two company-operated surface mines. For the year ended December 31, 2011, these mines produced an aggregate of approximately 2.1 million tons of steam coal.

        Hopedale Mining Complex.    The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad in Cadiz, Ohio and then shipped by train or truck to our customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 1.3 million tons of steam coal for the year ended December 31, 2011.

        Sands Hill Mining Complex.    We operate two surface mines at our Sands Hill mining complex, located near Hamden, Ohio. In 2009, we completed construction of a river-front barge and dock facility on the Ohio River. The infrastructure also includes a preparation plant. The Sands Hill mining complex produced approximately 0.7 million tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2011.

        Western Bituminous Region.    In January 2011, we began production at an underground mine in Emery and Carbon Counties, Utah. During 2010, we operated an underground mine in the Western Bituminous region of Colorado, which has been temporarily idled.

        Castle Valley Mining Complex.    In August 2010, we completed the acquisition of certain mining assets of C.W. Mining Company out of bankruptcy. The assets acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. In January 2011, we began production at one underground mine at this complex. The Castle Valley mining complex produced approximately 0.6 million tons of steam coal for the year ended December 31, 2011.

        McClane Canyon Mine.    The McClane Canyon mine is located near Loma, Colorado and is on property leased from the Bureau of Land Management ("BLM"). We temporarily idled production at this mine at the end of 2010 and the mine remained idle at the end of 2011. We have received a conditional permit to build a rail loadout at this location, pending bonding, and we believe access to a rail loadout will enable us to expand our customer base. We plan to restart production at the McClane Canyon mine when market conditions are favorable.

        In addition to the McClane Canyon mine, we currently control three nearby federal leases consisting of approximately 7,600 acres, two of which have the potential to support a future underground coal mining operation with procurement of an adjacent federal leasehold. We began the permitting process and leasehold procurement in 2005 and expect the process to last approximately one to three more years. We are currently in an exploration process to define the volume, quality, and mineability of the coal reserves.

Other Non-Mining Operations

        In addition to our mining operations, we operate several subsidiaries which provide auxiliary services for our coal mining operations. Rhino Trucking provides our Kentucky coal operations with dependable, safe coal hauling to our preparation plants and loadout facilities and our southeastern Ohio coal operations with reliable transportation to our customers where rail is not available. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining reclamation. Through Rhino Services, we plan and monitor each phase of our mining projects as well

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as the post-mining reclamation efforts. We also perform the majority of our drilling and blasting activities at our company-operated surface mines in-house rather than contracting to a third party. Our Triad Roof Support Systems subsidiary manufactures roof control products used in underground coal mining.

Other Natural Resource Assets

Oil and Gas

        In addition to our coal operations, we have invested in oil and gas mineral rights that we expect to generate royalty revenues in future periods, which we believe will help to diversify our income stream.

        We and an affiliate of Wexford Capital have participated with Gulfport Energy, a publicly traded company, to acquire an interest in a portfolio of oil and gas leases in the Utica Shale. As of February 20, 2012, an affiliate of Wexford Capital owned approximately 13.3% of the common stock of Gulfport Energy. During 2011, we completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $19.9 million.

        During 2011, we completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. We expect royalty revenues to be generated from these mineral rights in future periods.

Limestone

        Incidental to our coal mining process, we mine limestone from reserves located at our Sands Hill mining complex and sell it as aggregate to various construction companies and road builders that are located in close proximity to the mining complex when market conditions are favorable. We believe that our production of limestone provides us with an additional source of revenues at low incremental capital cost.

Customers

General

        Our primary customers for our steam coal are electric utilities, and the metallurgical coal we produce is sold primarily to domestic and international steel producers. Excluding results from the joint venture, for the year ended December 31, 2011, approximately 87% of our coal sales tons consisted of steam coal and approximately 13% consisted of metallurgical coal. For the year ended December 31, 2011, 100% of the joint venture's coal sales tons consisted of metallurgical coal. For the year ended December 31, 2011, excluding results from the joint venture, approximately 63% of our coal sales tons that we produced were sold to electric utilities. The majority of our electric utility customers purchase coal for terms of one to three years, but we also supply coal on a spot basis for some of our customers. Excluding the results from the joint venture, for the year ended December 31, 2011, we derived approximately 82.1% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 44.8% of our coal revenues for that period: GenOn Energy, Inc. (fka Mirant Corporation) (17.1%); PPL Corporation (14.3%); and American Electric Power Company, Inc. (13.4%). Additionally, pursuant to the terms of a coal purchase agreement entered into under the joint venture agreement, we sell 100% of the joint venture's production to an affiliate of our joint venture partner, Patriot, which controls the amount and terms of sales of the coal produced from the joint venture. Incidental to our coal mining process, we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to our Sands Hill mining complex.

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Coal Supply Contracts

        For the years ended December 31, 2011 and 2010, approximately 77% and 96%, respectively, of our aggregate coal tons sold were sold through supply contracts. We expect to continue selling a significant portion of our coal under supply contracts.

        Quality and volumes for the coal are stipulated in coal supply contracts, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply 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. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Some of our contracts specify approved locations from which coal may be sourced. 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 serious transportation problems that affect us or unanticipated plant outages that may affect the buyers.

        The terms of our coal supply contracts result from competitive bidding procedures and extensive negotiations with customers. As a result, the terms of these contracts, including price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions, vary significantly by customer.

Lease Agreements

        With respect to our Elk Horn leasing operations, we enter into leases with coal mine operators granting them the right to mine and sell coal from our Elk Horn properties in exchange for a royalty payment. Generally the lease terms provide us with a royalty fee of 6% to 9% of the gross sales price of the coal, with a minimum royalty fee ranging from $1.85 to $4.75 per ton. The terms of such leases vary from five years to the life of the reserves. A minimum royalty is required annually or monthly whether or not the property is mined.

Transportation

        We ship coal to our customers by rail, truck or barge. For the year ended December 31, 2011, the majority of our coal sales tonnage was shipped by rail. The majority of our coal is transported to customers by either the CSX Railroad or the Norfolk Southern Railroad in eastern Kentucky and by the Ohio Central Railroad or the Wheeling & Lake Erie Railroad in Ohio. In addition, in southeastern Ohio, we use our own trucking operations to transport coal to our customers where rail is not available. We used third-party trucking to transport coal to our customers in Utah. We temporarily idled the McClane Canyon mine at December 31, 2010, and we have received a conditional permit to build a rail loadout at this location, pending bonding. This mine remained idle at December 31, 2011. In addition, coal from certain of our mines is located within economical trucking distance to the Big Sandy River and/or the Ohio River and can be transported by barge. It is customary for customers to pay the transportation costs to their location.

        We believe that we have good relationships with rail carriers and truck companies due, in part, to our modern coal-loading facilities at our loadouts and the working relationships and experience of our transportation and distribution employees.

Suppliers

        Principal supplies used in our business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance structures, ventilation supplies and

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lubricants. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction.

        We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods and to support the mining and coal preparation plants. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Competition

        The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States and we compete with many of these producers. Our main competitors include Alliance Resource Partners LP, Alpha Natural Resources, Inc., Arch Coal, Inc., Booth Energy Group, CONSOL Energy Inc., James River Coal Company, Murray Energy Corporation, Oxford Resource Partners, LP, Patriot and TECO Energy, Inc.

        The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and the 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, availability, quality and price of competing sources of fuel such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power.

Regulation and Laws

        The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:

    employee health and safety;

    mine permits and other licensing requirements;

    air quality standards;

    water quality standards;

    storage, treatment, use and disposal of petroleum products and other hazardous substances;

    plant and wildlife protection;

    reclamation and restoration of mining properties after mining is completed;

    the discharge of materials into the environment, including waterways or wetlands;

    storage and handling of explosives;

    wetlands protection;

    surface subsidence from underground mining;

    the effects, if any, that mining has on groundwater quality and availability; and

    legislatively mandated benefits for current and retired coal miners.

        In addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal.

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The possibility exists that new laws or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a significant impact on our mining operations or our customers' ability to use coal.

        We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. Violations, including violations of any permit or approval, can result in substantial civil and in severe cases, criminal fines and penalties, including revocation or suspension of mining permits. None of the violations to date have had a material impact on our operations or financial condition.

        While it is not possible to quantify the costs of compliance with applicable federal and state laws and regulations, those costs have been and are expected to continue to be significant. Nonetheless, capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of estimated cost of reclamation and mine closings, including the cost of treating mine water discharge when necessary. The accruals for reclamation and mine closing costs are based upon permit requirements and the costs and timing of reclamation and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if we later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.

Mining Permits and Approvals

        Numerous governmental permits or approvals are required for coal mining operations. When we apply for these permits and approvals, we are often required to assess the effect or impact that any proposed production of coal may have upon the environment. The permit application requirements may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. Future laws and regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Laws and regulations, as well as future interpretations or enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs, or delays, interruptions or terminations of operations, the extent of any of which cannot be predicted. The permitting process for certain mining operations can extend over several years, and can be subject to judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We may experience difficulty and/or delay in obtaining mining permits in the future.

        Regulations provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, we have been cited for violations in the ordinary course of business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

        Before commencing mining on a particular property, we must obtain mining permits and approvals by state regulatory authorities of a reclamation plan for restoring, upon the completion of mining, the mined property to its approximate prior condition, productive use or other permitted condition.

Mine Health and Safety Laws

        Stringent safety and health standards have been in effect since the adoption of the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (the "Mine Act"), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards and imposed comprehensive safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in

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mining operations and other matters. The Mine Safety and Health Administration ("MSHA") monitors compliance with these laws and regulations. In addition, the states where we operate also have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal industry are complex, rigorous and comprehensive, and have a significant effect on our operating costs.

        The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that a standard has been violated. A penalty is required to be imposed for each cited violation. Negligence and gravity assessments result in a cumulative enforcement scheme that may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act contains criminal liability provisions. For example, criminal liability may be imposed for corporate operators who knowingly or willfully authorize, order or carry out violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations.

        We have developed a health and safety management system that, among other things, educates our employees about health and safety requirements including those arising under federal and state laws that apply to our mines. In addition, our health and safety management system tracks the performance of each operational facility in meeting the requirements of safety laws and company safety policies. As an example of the resources we allocate to health and safety matters, our safety management system includes a company-wide safety director and local safety directors who oversee safety and compliance at operations on a day-to-day basis. We continually monitor the performance of our safety management system and from time-to-time modify that system to address findings or reflect new requirements or for other reasons. We have even integrated safety matters into our compensation and retention decisions. For instance, our bonus program includes a meaningful evaluation of each eligible employee's role in complying with, fostering and furthering our safety policies.

        We evaluate a variety of safety-related metrics to assess the adequacy and performance of our safety management system. For example, we monitor and track performance in areas such as "accidents, reportable accidents, lost time accidents and the lost-time accident frequency rate" and a number of others. Each of these metrics provides insights and perspectives into various aspects of our safety systems and performance at particular locations or mines generally and, among other things, can indicate where improvements are needed or further evaluation is warranted with regard to the system or its implementation. An important part of this evaluation is to assess our performance relative to certain national benchmarks.

        Our non-fatal days lost time incidence rate for all operations for the year ended December 31, 2011 was 1.64 as compared to the most recent national average of 2.44, as reported by MSHA, or 32.8% below this national average. Non-fatal days lost incidence rate is an industry standard used to describe occupational injuries that result in loss of one or more days from an employee's scheduled work. In addition, for the year ended December 31, 2011 our average MSHA violations per inspection day was 0.75 as compared to the most recent national average of 0.82 violations per inspection day as reported by MSHA, or 8.5% below this national average.

        In 2006, in response to underground mine accidents, the Mine Improvement and New Emergency Response Act of 2006, or MINER Act, was enacted. The MINER Act significantly amended the Mine Act, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since passage of the MINER Act, enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. Various states also have

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enacted their own new laws and regulations addressing many of these same subjects. MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards. Among these new proposed regulations is MSHA's proposed rule titled "Lowering Miner's Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors." The rule, which is in the final rule stage, would require a 50% reduction in the allowable respirable coal mine dust exposure limits and require each operation to significantly increase the number of respirable coal mine dust samples taken. The rule would also increase oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine. MSHA also adopted a final rule incorporating the requirements contained in the 2010 Emergency Temporary Standard that requires the application and continued maintenance of a significantly increased amount of rock dust throughout underground coal mines. Another proposal in the final rule stage is titled "Examinations of Work Areas in Underground Coal Mines for Violations of Mandatory Health or Safety Standards," and would require mine operators to locate, record, and correct all violations of mandatory health or safety standards, and no longer focus on hazardous conditions. The rule would also require that mine operators review with mine examiners, on a quarterly basis, all citations and orders issued in areas where examinations are required.

        Mining accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, have resulted in more inspection hours at mine sites, increased number of inspections and increased issuance of the number and severity of enforcement actions and the passage of new laws and regulations. These trends are likely to continue.

        Following the April 5, 2010 Upper Big Branch mine incident, public scrutiny of large mining operations has increased among government officials as well as regulatory agencies. On April 14, 2010, U.S. Representative George Miller publicly released a list of mining operations which would have faced "pattern of violation" sanctions were it not for contested notices of violation. This list included our Mine 28 in Pike County, Kentucky. After additional inspections on April 20, 2010, MSHA issued various citations related to Mine 28. Although we took steps to immediately abate certain of these citations, we may incur various penalties or sanctions, in part due to MSHA's proposed rule on pattern of violations ("POV"). Under the rule, which is in the final rule stage, MSHA may consider non-final citations and orders when determining POV status. In addition, mine operators would no longer receive notice of a potential POV, and thus not have the opportunity to mitigate the problem by developing a remediation plan. Instead, operators would be expected to monitor compliance by reviewing criteria for POV posted on MSHA's website.

        From time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order to address a compliance requirement or because of an accident. For instance, MSHA issues orders pursuant to Section 103(k) that, among other things, call for operations in the area of the mine at issue to suspend operations until compliance is restored. Likewise, if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance leading to the accident has been resolved. During the fiscal year ended December 31, 2011 (as in earlier years), we received such orders from government agencies and have experienced accidents within our mines requiring the suspension or shutdown of operations in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances that caused such an accident were being addressed, other areas of the mine could and did remain operational. These circumstances did not require us to suspend

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operations on a mine-wide level or otherwise entail material financial or operational consequences for us. Any suspension of operations at any one of our locations that may occur in the future may have material financial or operational consequences for us.

        It is our practice to contest notices of violations in cases in which we believe we have a good faith defense to the alleged violation or the proposed penalty and/or other legitimate grounds to challenge the alleged violation or the proposed penalty. In December 2008 and March 2009, MSHA assessed proposed penalties in excess of $100,000 with regard to three separate notices of violation, all of which relate to our operations at Mine 28. Each of these notices of violation alleged an "unwarrantable failure" under the Mine Act with specific regard to the accumulation of combustible materials. The combustible materials typically underlying such citations are coal, loose coal, and float coal dust. We have contested these violations on grounds that the underlying circumstances did not support the issuance of a notice of violation and/or the gravity of the proposed penalty. These contests are still pending and we cannot predict the outcome of these proceedings or assure you that the fines and penalties will not be assessed in full against us. These alleged violations were abated at the time or immediately after the notices of violation were issued, and we have not been issued any notices of violation from MSHA proposing a penalty in excess of $100,000 since March 2009.

        We exercise substantial efforts toward achieving compliance at our mines. In light of the recent citations issued with respect to our mines, we have further increased our focus with regard to health and safety at all of our mines and at Mine 28 and Eagle #1 Mine in particular. These efforts include hiring additional skilled personnel, providing training programs, hosting quarterly safety meetings with MSHA personnel and making capital expenditures in consultation with MSHA aimed at increasing mine safety. We believe that these efforts have contributed, and continue to contribute, positively to safety and compliance at our mines.

        Implementing and complying with these state and federal safety laws and regulations could adversely affect our results of operations and financial position. Some safety measures may decrease our production rates or cause us not to pursue certain reserves due to safety concerns, adversely affecting our revenues.

Black Lung Laws

        Under federal black lung benefits laws, businesses that conduct current mining operations must make payments of black lung benefits to coal miners with black lung disease and to some survivors of a miner who dies from this disease. To help fund these benefits, a tax is levied on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, some claims for which coal operators had previously been responsible will be obligations of the government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent. In 2011, we recorded approximately $3.0 million of expense related to this excise tax.

        On March 23, 2010, President Obama signed into law health care reform legislation, known as the Patient Protection and Affordable Care Act, which includes significant changes to the federal black lung program. Among other things, these changes include provisions, retroactive to 2005, which would (1) provide an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim, without requiring proof that the death was due to pneumoconiosis and (2) establish a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine

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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.

        For miners last employed as miners after 1969 and who are determined to have contracted black lung, we maintain insurance coverage sufficient to cover the cost of present and future claims or we participate in state programs that provide this coverage. We may also be liable under state laws for black lung claims and are covered through either insurance policies or state programs. Congress and state legislatures regularly consider various items of black lung legislation, which, if enacted, could adversely affect our business, results of operations and financial position.

Workers' Compensation

        We are required to compensate employees for work-related injuries under various state workers' compensation laws. The states in which we operate consider changes in workers' compensation laws from time to time. Our costs will vary based on the number of accidents that occur at our mines and other facilities, and our costs of addressing these claims. We are insured under the Ohio State Workers Compensation Program for our operations in Ohio. Our remaining operations, including Central Appalachia and the Western Bituminous region, are insured through Rockwood Casualty Insurance Company.

Surface Mining Control and Reclamation Act ("SMCRA")

        SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we reclaim and restore the mined areas by grading, shaping and preparing the soil for seeding. Upon completion of mining, reclamation generally is completed by seeding with grasses or planting trees for a variety of uses, as specified in the approved reclamation plan. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

        SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires that we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Mine operators can also be responsible for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of long-wall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed prior to SMCRA's adoption in 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. As of December 31, 2011, we had accrued approximately $34.1 million for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

        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 a SMCRA mine permit application to take over two years to prepare and review, depending on the size and complexity of the mine, and another two years or even longer for the permit to be issued. The variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities' discretion in the handling of comments and objections relating to the

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project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of judicial challenges related to the specific permit or another related company's permit.

        Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being "permit blocked" under the federal Applicant Violator Systems, or AVS. Thus, non-compliance with SMCRA can provide the bases to deny the issuance of new mining permits or modifications of existing mining permits, although we know of no basis by which we would be (and we are not now) permit-blocked.

        In addition, on November 30, 2009, the Office of Surface Mining Reclamation and Enforcement ("OSM") published an advance notice of proposed rulemaking to revise the "stream buffer zone rule," or SBZ Rule, that prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality. OSM had previously issued a Stream Buffer Zone rule in December 2008 that would have provided certain exemptions to the requirement for a 100-foot buffer around all waters, including streams, lakes, ponds, and wetlands. OSM announced on April 29, 2010 its intention to propose a new Stream Protection Rule in 2011, to be finalized in 2012, and to prepare an Environmental Impact Statement evaluating the environmental consequences of the proposed rule. The new rule is anticipated to be much more stringent than the December 2008 rule and eliminate many of the exemptions in that rule. The new rule has not yet been proposed or finalized. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities near streams, and additional enforcement actions. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams. The requirements of the revised Stream Protection Rule or future legislation, when adopted, will likely be stricter than the prior SBZ Rule to further protect streams from the impact of surface mining, and may adversely affect our business and operations.

Surety Bonds

        Federal and 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. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

        As of December 31, 2011, we had approximately $69.9 million in surety bonds outstanding to secure the performance of our reclamation obligations. We may be required to increase these amounts as a result of recent developments in West Virginia and Kentucky. In 2011, West Virginia passed legislation that provides for a minimum incremental bonding rate in lieu of a minimum bond amount that applies regardless of acreage. In addition, the Kentucky Department for Natural Resources and the Office of Surface Mining Reclamation and Enforcement Lexington Field Office executed an Action Plan for Improving the Adequacy of Kentucky Performance Bond Amounts, which provides for, among other things, revised bond computation protocols.

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Air Emissions

        The Federal Clean Air Act, or the CAA, and similar state and local laws and regulations, which regulate emissions into the air, affect coal mining operations both directly and indirectly. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other industrial consumers of coal, including air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds. There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Stricter air emission regulation would impact the operation of existing power plants and the construction of new power plants and may lead to changes in our customers' cost structure and purchasing patterns. Coal-fired power plants without up-to-date pollution controls may have to continue to install pollution control technology and upgrades, and might not be able to recover costs for these upgrades in the prices they charge for power due, in part, to the control exercised by state public utility commissions over such rate matters. As a result, the regulation of emissions under the CAA may impact our operations due to any resulting change in the use and demand for coal by our steam coal customers, which could have a material adverse effect on our business, financial condition and results of operations.

        EPA's Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility's sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA's Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or "scrubbers," or by reducing electricity generating levels.

        EPA has promulgated rules, referred to as the "NOx SIP Call," that require coal-fired power plants in 22 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control measures will make it more costly to operate coal-fired power plants, potentially making coal a less attractive fuel.

        Additionally, in March 2005, EPA issued the final Clean Air Interstate Rule, or CAIR, which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. CAIR required those states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered "cap-and-trade" program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the caps under CAIR may have required many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal capability required by the rule could have resulted in decreased demand for lower sulfur coal, which may have potentially driven down prices for lower sulfur coal. A December 2008 court decision found flaws in CAIR, but kept CAIR requirements in place temporarily while directing the EPA to issue a replacement rule.

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        On July 6, 2011, EPA finalized a rule intended to replace CAIR called the Cross-State Air Pollution Rule, or CSAPR, which requires 28 states in the eastern half of the US to reduce power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. CSAPR was scheduled to replace CAIR starting January 1, 2012. However, on December 30, 2011, the U.S. Court of Appeals for the D.C. Circuit stayed the implementation of CSAPR pending judicial review. This was not a decision on the merits of the rule. While this decision delays implementation of CSAPR, it also leaves CAIR in place while the court considers the merits of the legal challenges to CSAPR. For states to meet their requirements under CSAPR, a number of coal-fired power plants will likely need to be retired, rather than be retrofitted with the necessary emission control technologies, reducing the demand for steam coal.

        On February 16, 2012, the EPA formally adopted its "MATS rule," which imposes a new suite of limits on coal- and oil-fired electric generating unit ("EGU") emissions of mercury, other metals, acid gases, and organic air toxics. As specified under the CAA, all regulated EGUs have three years to comply with MATS, starting on April 16, 2012. Affected power plants must comply with the MATS requirements by April 16, 2015 except where the deadlines have been extended pursuant to mechanisms in the act. Under MATS, state permitting authorities may grant a fourth-year to achieve compliance to sources that require extra time to install controls. The EPA also signed revisions to the new source performance standards (NSPS) for fossil-fuel-fired EGUs. This NSPS revises the standards that new coal-fired and oil-fired power plants must meet for particulate matter, sulfur dioxide, and nitrogen oxides. Currently, the MATS rule is subject to various judicial and administrative challenges, and challenges at the congressional level that seek to block or repeal the regulations, the outcome of which cannot be determined at this time.

        In addition, on March 21, 2011, the EPA issued new MACT standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters (Boiler MACT), which would have required significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. On May 18, 2011, the EPA stayed the effective date of the Boiler MACT. On January, 9, 2012, the federal district court for the District of Columbia issued a decision vacating and remanding the May 2011 delay notice. However, on February 7, 2012, the EPA issued a "No Action Assurance" letter regarding the original deadlines indicating it will exercise enforcement discretion not to pursue enforcement for violations of deadlines that occurred during the stay. The EPA has indicated they will revise the Boiler MACT rules in the Spring of 2012. The effect of the regulatory proceedings will depend on the final form of the revised regulations and the outcome of any legal challenges and cannot be determined at this time.

        The EPA has adopted new, more stringent national air quality standards, or NAAQS, for ozone, fine particulate matter, and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards. For example, in December 2004, the EPA designated specific areas in the United States as in "non-attainment" with the new NAAQS for fine particulate matter. In March 2007, the EPA published final rules addressing how states would implement plans to bring applicable non-attainment regions into compliance with the new air quality standard. On June 3, 2010, the EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Attainment designations will be made pursuant to the modified standards by June 2012. States with non-attainment areas will have until 2014 to submit SIP revisions which must meet the modified standard by August 1, 2017; for all other areas, states will be required to submit "maintenance" SIPs by 2013. The EPA also plans to address the secondary sulfur dioxide standard, which continues to be under review. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and customers could be affected when the standards are implemented by the applicable states.

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        In June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected states were required to develop SIPs by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Demand for our steam coal could be affected when these standards are implemented by the applicable states.

        The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected.

        On June 16, 2010, several environmental groups petitioned the EPA to list coal mines as a source of air pollution and establish emissions standards under the CAA 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. These same groups filed suit against the EPA in November of 2011in the federal court for the District of Columbia seeking the EPA's listing of coal mines as a New Source Performance Standard category. 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 CAA. 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 reducing our revenues and adversely affecting our operations.

Carbon Dioxide Emissions

        One by-product of burning coal is carbon dioxide, which EPA considers a greenhouse gas ("GHG") and a major source of concern with respect to climate change and global warming.

        Future regulation of GHG in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. The Obama Administration has indicated its support for a mandatory cap and trade program to reduce GHG emissions and it is possible federal legislation could be adopted in the future. Passage of any comprehensive climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

        Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions pursuant to the CAA based on the April 2007 United States Supreme Court ruling in Massachusetts, et al. v. EPA that the EPA has authority to regulate carbon dioxide emissions. EPA's GHG regulations consist of seven main rules:

            (1)   the October 2009 Mandatory Reporting Rule, which requires GHG sources above certain thresholds to monitor and report their emissions;

            (2)   the December 2009 "Endangerment Finding," determining that air pollution from six GHGs endangers public health and welfare, and that mobile sources cause or contribute to that air pollution;

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            (3)   the May 2010 "Tailpipe Rule," issued jointly with the National Highway Traffic Safety Administration setting GHG emission and fuel economy standards for new light-duty vehicles;

            (4)   the June 2010 "Final Mandatory Reporting of GHGs Rule," requiring all stationary sources that emit more than 25,000 tons of GHGs per year to collect and report to the EPA data regarding such emissions. This rule affects many of our customers, as well as additional source categories, including all underground mines subject to quarterly methane sampling by MSHA. Underground mines subject to this rule were required to begin monitoring GHG emissions on January 1, 2011 and must begin reporting to the EPA on March 31, 2012.

            (5)   the April 2010 "Timing Rule," concluding that stationary source regulation under Titles I and V of the CAA (involving Prevention of Significant Deterioration regulations and operating permits, respectively) must regulate GHG emissions beginning when such emissions are subject to controls under the mobile source provisions of the Act;

            (6)   the June 2010 "Tailoring Rule," temporarily exempting small stationary sources from PSD and Title V requirements through regulations modifying the CAA's emissions thresholds; and

            (7)   the December 2010 "SIP Call" rule, finding 13 SIPs inadequate because they did not regulate GHGs from stationary sources, and directing those States to correct the inadequacies or face federalization of their permitting programs.

        All of these regulations are subject to legal challenges, but the D.C. Circuit has refused to stay their implementation while the challenges are pending. Finally, in December 2010, the EPA issued its plan to update New Source Performance Standards (NSPS) for fossil fuel power plants. The EPA had stated its intention to propose standards for power plants by July of 2011 and issue final standards in May 2012 and November 2012, respectively. However, the EPA confirmed in September that it would miss a September 30, 2011 deadline extension to propose the NSPS to regulate GHG from new and existing power plants. As of early December 2011, the EPA reportedly had prepared a proposal to regulate GHG emissions from only new plants, not existing ones, but that proposal is pending review at the Office of Management and Budget, and is not yet public. The EPA's failure to propose rules by the required date will delay final action, as well. Any new NSPS, along with the current EPA's GHG regulations, could adversely affect the demand for coal.

        Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities. For example, in December 2005, seven northeastern states signed the Regional Greenhouse Gas Initiative agreement, or RGGI, calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.

        Following the RGGI model, seven Western states and four Canadian provinces launched the Western Regional Climate Action Initiative to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. At a January 12, 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. Similarly in 2007, six Midwestern states and one Canadian province signed the Midwestern Greenhouse Gas Reduction Accord (MGGRA) to develop and implement steps to reduce GHG emissions. A Final Model Rule was released in April 2010 and calls for a 20% reduction below 2005 emissions levels by 2020 and additional reductions to 80% below 2005 emissions levels by 2050, and implementation of a cap and

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trade program. Though MGGRA has not been formally suspended, participating states are no longer pursuing it. However, it is likely that these regional efforts will continue.

        Our customers' coal-fired coal plants have also come under additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to greenhouse gas emissions. For instance, in October 2007, state regulators in Kansas denied an air emissions construction permit for a new coal-fueled power plant based on the plant's projected emissions of carbon dioxide. Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA's Environmental Appeals Board. In addition, 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 by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. 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. Finally, a federal appeals court has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds. On June 20, 2011, the U.S. Supreme Court ruled unanimously in AEP v. Connecticut that the authority to regulate large stationary sources of GHG emissions granted to the EPA under the CAA displaces federal common law public nuisance claims against those sources.

        If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. On February 3, 2010, President Obama sent a memorandum to the heads of fourteen Executive Departments and Federal Agencies establishing an Interagency Task Force on Carbon Capture and Storage ("CCS"). The goal was to develop a comprehensive and coordinated Federal strategy to speed the commercial development and deployment of clean coal technologies. On August 12, 2010, the Task Force delivered a series of recommendations on overcoming the barriers to the widespread, cost-effective deployment of CCS within ten years. The report concludes that CCS can play an important role in domestic GHG emissions reductions while preserving the option of using abundant domestic fossil energy resources. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

Clean Water Act

        The Federal Clean Water Act, or the CWA, and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the U.S. The CWA establishes in-stream water quality and treatment standards for wastewater discharges that are applied to wastewater dischargers through Section 402 National Pollutant Discharge Elimination System, or NPDES, permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into waters of the U.S. including wetlands, streams, and other areas meeting the regulatory definition. Our surface coal mining and preparation plant

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operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA, or a state that has been delegated such authority by the EPA, issues NPDES permits for the discharge of pollutants into navigable waters, while the U.S. Army Corps of Engineers, or the Corps, issues dredge and fill permits under Section 404 of the CWA. Where Section 402 NPDES permitting authority has been delegated to a state, the EPA retains a limited oversight role. The CWA also gives the EPA an oversight role in the Section 404 permitting program, including drafting substantive rules governing permit issuance by the Corps, providing comments on proposed permits, and, in some cases, exercising the authority to delay or pre-empt Corps issuance of a Section 404 permit. The EPA has recently asserted these authorities more forcefully to question, delay, and prevent issuance of some Section 402 and 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

        For instance, even though the Commonwealth of Kentucky and the State of West Virginia have been delegated the authority to issue NPDES permits for coal mines in those states, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. The EPA has stated that it plans to review all applications for NPDES permits and has formally objected to the issuance of numerous NPDES permits in Kentucky, requiring those permits to go through additional regulatory reviews and putting into doubt their ultimate issuance. Indeed, final guidance issued by the EPA on July 21, 2011, encourages EPA Regions 3, 4 and 5 to (1) object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA, and (2) exercise a greater degree of oversight with regard to state issued general Section 404 permits. This final guidance followed and confirmed an interim final guidance document that was originally issued on April 1, 2010.

        In addition, the July 21, 2011 final guidance also addresses the Regions' involvement in Section 404 permitting decisions. This guidance expands on the June 11, 2009 Memorandum of Understanding among the EPA, the Corps, and the U.S. Department of the Interior, which established the Enhanced Coordination Process ("ECP") for the issuance of Section 404 permits, whereby the EPA undertook a new level of review of certain Section 404 permits than was significantly greater than it had previously undertaken. On October 6, 2011, the District Court for the District of Columbia granted partial summary judgment rejecting the EPA's ECP on several different legal grounds including the lack of authority under the CWA and the failure to provide appropriate notice and comment pursuant to the Administrative Procedures Act. The challenge to the July 21, 2011 final guidance is still pending, and the EPA continues to apply that guidance to its review of Section 402 and 404 permits for surface coal mining in Appalachia.

        The EPA also has statutory "veto" power to effectively revoke a previously issued Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an "unacceptable adverse effect." On January 14, 2011, the EPA exercised its Section 404(c) authority to withdraw or restrict the use of a previously issued permit for the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA's exercise of this authority is currently pending in the federal District Court in the District of Columbia. More frequent use of the EPA's Section 404 "veto" power as well as the increased risk of application of this power to previously permitted projects could create uncertainty with regard to our lessees' continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal royalties revenues.

        These various initiatives by the EPA have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with

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obtaining and complying with those permits will increase substantially. It is possible that some of our projects may not be able to obtain these permits because of the manner in which these rules are being interpreted and applied. It is also possible that we may be unable to obtain or may experience delays in securing, utilizing or renewing additional Section 404 individual permits for surface mining operations due to agency or court decisions stemming from the above developments.

        The Corps is authorized to issue general "nationwide" permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. We may no longer seek general permits under Nationwide Permit 21, or NWP 21, because on June 17, 2010, the Corps suspended the use of NWP 21, but NWP 21 authorizations already granted remain in effect. While the suspension is in effect, proposed surface coal mining projects that involve discharges of dredged or fill material into waters of the United States will have to obtain individual permits from the Corps subject to the additional EPA measures discussed below with the uncertainties and delays attendant to that process.

        We currently have a number of Section 404 permit applications pending with the Corps. Not all of these permit applications seek approval for valley fills or other obvious "fills"; some relate to other activities, such as mining through streams and the associated post-mining reconstruction efforts. We sought to prepare all pending permit applications consistent with the requirements of the Section 404 program. Our five year plan of mining operations does not rely on the issuance of these pending permit applications. However, the Section 404 permitting requirements are complex, and regulatory scrutiny of these applications, particularly in Appalachia, has increased such that our applications may not be granted or, alternatively, the Corps may require material changes to our proposed operations before it grants permits. While we will continue to pursue the issuance of these permits in the ordinary course of our operations, to the extent that the permitting process creates significant delay or limits our ability to pursue certain reserves beyond our current five year plan, our revenues may be negatively affected.

        Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that a water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. This process applies to those waters that states have designated as impaired (i.e., as not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL load allocations for these stream segments. The adoption of new TMDLs and load allocations for streams near our coal mines could limit our ability to obtain NPDES permits, require more costly water treatment, and adversely affect our coal production.

        Under the CWA, states also must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state's antidegradation regulations must prohibit the diminution of water quality in these streams absent an analysis of alternatives to the discharge and a demonstration of the socio-economic necessity for the discharge. Several environmental groups and individuals have challenged West Virginia's antidegradation policy. In general, waters discharged from coal mines to high quality streams in West Virginia will be required to meet or exceed new "high quality" standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits in West Virginia, and could adversely affect our coal production. Several other environmental groups also challenged the EPA's approval of Kentucky's antidegradation policy, including its alternative antidegradation implementation methodology for permits associated with coal mining discharges, which recognized that those discharges are subject to comparable regulation under SMCRA and Section 404 of the CWA. As a result of this litigation, in 2011 Kentucky finalized revisions to its antidegradation rules that no longer include the alternative implementation methodology for coal mining discharges. The elimination of the alternative implementation methodology for coal mining discharges and other changes to Kentucky's antidegradation rules could mean that our operations in Kentucky may be

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required to comply with more complex and costly antidegradation procedures and cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits in Kentucky, and thereby adversely affect our coal production.

Hazardous Substances and Wastes

        The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Some products used by coal companies in operations generate waste containing hazardous substances. We are not aware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

        The federal Resource Conservation and Recovery Act, or RCRA, and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous wastes. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

        On June 21, 2010, EPA released a proposed rule to regulate the disposal of certain coal combustion by-products, or CCB. The proposed rule sets forth two proposed avenues for the regulation of CCB under RCRA. The first option calls for regulation of CCB under Subtitle C as a hazardous waste, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option calls for regulation of CCB under Subtitle D as a solid waste, which gives EPA authority to set performance standards for solid waste management facilities and would be enforced primarily through state agencies and citizen suits. Under both options, the EPA would establish dam safety requirements to address structural integrity of surface impoundments to prevent catastrophic releases. The proposal leaves intact the Bevill exemption for beneficial uses of CCB, except for land application. If CCB were re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCB, 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.

        It is not possible to determine with certainty the potential permitting requirements or performance standards that may be imposed on the disposal of CCB by future regulations or lawsuits. Any costs associated with new requirements applicable to CCB handling or disposal could increase our customers' operating costs and potentially reduce their ability to purchase coal.

National Environmental Policy Act

        Certain of our planned activities and operations include acreage located on federal land and, thus, require governmental approvals that are subject to the requirements of the National Environmental

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Policy Act ("NEPA"). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions such as issuing an approval that have the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an environmental assessment to assess the potential direct, indirect and cumulative impacts of a proposed project. Where the activities in question have significant impacts to the environment, the agency, in this instance, must prepare an environmental impact statement, or EIS. The preparation of an EIS can be time consuming and may result in the imposition of mitigation measures that could affect the amount of coal that we are able to produce from mines on federal lands. Moreover, an EIS is subject to protest, appeal or litigation, which can delay or halt projects. Our proposed Red Cliffs project, which includes acreage on federal land in Colorado, is subject to NEPA. The BLM has published a draft EIS for the Red Cliffs project. Although we do not expect any delays in our development of the Red Cliffs project because of the NEPA review process, the NEPA review may extend the time and/or increase the costs for obtaining the necessary governmental approvals.

Endangered Species Act

        The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Use of Explosives

        We use explosives in connection with our surface mining activities. The Federal Safe Explosives Act, or SEA, applies to all users of explosives. Knowing or willful violations of the SEA may result in fines, imprisonment, or both. In addition, violations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials.

        The storage of explosives is also subject to regulatory requirements. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review in order to help determine whether there is a high level of security risk, such that a security vulnerability assessment and a site security plan will be required. It is possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security's new chemical facility security regulatory program.

        The costs of compliance with these requirements should not have a material adverse effect on our business, financial condition or results of operations.

Other Environmental and Mine Safety Laws

        We are required to comply with numerous other federal, state and local environmental and mine safety laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these requirements should not have a material adverse effect on our business, financial condition or results of operations.

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Employees

        To carry out our operations, our general partner and our subsidiaries employed 1,033 full-time employees as of December 31, 2011. None of the employees are subject to collective bargaining agreements. We believe that we have good relations with these employees and since our inception we have had no history of work stoppages or union organizing campaigns.

Available Information

        Our internet address is http://www.rhinolp.com, and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and Forms 3, 4 and 5 for our Section 16 filers (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Also included on our website are our "Code of Business Conduct and Ethics", our "Insider Trading Policy," "Whistleblower Policy" and our "Corporate Governance Guidelines" adopted by the board of directors of our general partner and the charters for the Audit Committee and Compensation Committee. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

        We file or furnish annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934, or the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Additionally, the SEC's website, http://www.sec.gov, contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

Item 1A.    Risk Factors.

        In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below, which could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected.

Risks Inherent in Our Business

We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

        We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.445 per unit, or $1.78 per unit per year, which will require us to have available cash of approximately $12.6 million per quarter, or $50.3 million per year, based on the number of common and subordinated units outstanding as of December 31, 2011 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

    the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

    the price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

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    the level of our operating costs, including reimbursement of expenses to our general partner and its affiliates. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed;

    the proximity to and capacity of transportation facilities;

    the price and availability of alternative fuels;

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

    the level of worldwide energy and steel consumption;

    prevailing economic and market conditions;

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

    the effects of new or expanded health and safety regulations;

    domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility industry or the steel industry;

    changes in tax laws;

    weather conditions; and

    force majeure.

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

        Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. The prices we receive for coal depend upon factors beyond our control, including:

    the supply of domestic and foreign coal;

    the demand for domestic and foreign coal, which is significantly affected by the level of consumption of steam coal by electric utilities and the level of consumption of metallurgical coal by steel producers;

    the proximity to, and capacity of, transportation facilities;

    domestic and foreign governmental regulations, particularly those relating to the environment, climate change, health and safety;

    the level of domestic and foreign taxes;

    the price and availability of alternative fuels for electricity generation;

    weather conditions;

    terrorist attacks and the global and domestic repercussions from terrorist activities; and

    prevailing economic conditions.

        Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, the recent global economic downturn, coupled with the global financial and credit market disruptions, has had an impact on the coal industry generally and may continue to do so. The demand for electricity may remain at low levels or further decline if economic conditions remain weak. If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years. Recent low prices for natural gas, which is a

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substitute for coal generated power, may also lead to continued decreased coal consumption by electricity-generating utilities. A substantial or extended decline in the prices we receive for our coal supply contracts could materially and adversely affect our results of operations.

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

        We compete with coal producers in various regions of the United States and overseas for domestic and international sales. The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry and the domestic steel industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric power and other renewable energy sources. Consumption by the domestic steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and automobiles. In recent years, the competitive environment for coal was impacted by sustained growth in a number of the largest markets in the world, including the United States, China, Japan and India, where demand for both electricity and steel have supported prices for steam and metallurgical coal. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. The cost of ocean transportation and the value of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of our coal as we compete on price with foreign coal producing sources. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely impacting our results of operations and cash available for distribution.

        Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on prevailing market conditions. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, potentially reducing the price we could obtain for this coal and adversely impacting our cash flows, results of operations and cash available for distribution.

Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.

        The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant and time-consuming and may delay commencement or continuation of our operations. Moreover, the possibility exists that new laws or regulations (or new judicial interpretations or enforcement policies of existing laws and regulations) could materially affect our mining operations, results of operations and cash available for distribution to our unitholders, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers' use of coal. Although we believe that we are in substantial compliance with existing laws and regulations, we may, in the future, experience violations that would subject us to administrative, civil and criminal penalties

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and a range of other possible sanctions. The enforcement of laws and regulations governing the coal mining industry has increased substantially. As a result, the consequences for any noncompliance may become more significant in the future.

        Our operations use petroleum products, coal processing chemicals and other materials that may be considered "hazardous materials" under applicable environmental laws and have the potential to generate other materials, all of which may affect runoff or drainage water. In the event of environmental contamination or a release of these materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and cleanup of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire.

The government extensively regulates mining operations, especially with respect to mine safety and health, which imposes significant actual and potential costs on us, and future regulation could increase those costs or limit our ability to produce coal.

        Coal mining is subject to inherent risks to safety and health. As a result, the coal mining industry is subject to stringent safety and health standards. Fatal mining accidents in the United States in recent years have received national attention and have led to responses at the state and federal levels that have resulted in increased regulatory scrutiny of coal mining operations, particularly underground mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Moreover, future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

        Within the last few years, the industry has seen enactment of the Federal Mine Improvement and New Emergency Response Act of 2006, or the MINER Act, subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act, which, among other things, imposes new mine safety information reporting requirements. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977, or the Mine Act, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration, or MSHA, issued new or more stringent rules and policies on a variety of topics, including:

    sealing off abandoned areas of underground coal mines;

    mine safety equipment, training and emergency reporting requirements;

    substantially increased civil penalties for regulatory violations;

    training and availability of mine rescue teams;

    underground "refuge alternatives" capable of sustaining trapped miners in the event of an emergency;

    flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and

    post-accident two-way communications and electronic tracking systems.

        Subsequent to passage of the MINER Act, various coal producing states, including West Virginia, Ohio and Kentucky, have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Additional federal and state legislation that would further

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increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has also been considered.

        MSHA is also considering a new rule regarding respirable coal mine dust that, if promulgated, would lower the allowable average concentration of respirable dust, allow for single shift sampling to determine noncompliance and establish regulations for the use of Continuous Personal Dust Monitors (CPDM), among other things. Although still in the comment stage, this proposed rule could require significant expenditures in order to comply.

        Although we are unable to quantify the full impact, implementing and complying with these new laws and regulations could have an adverse impact on our results of operations and cash available for distribution to our unitholders and could result in harsher sanctions in the event of any violations. Please read "Item 1. Business—Regulation and Laws" of our Annual Report on Form 10-K.

Penalties, fines or sanctions levied by MSHA could have a material adverse effect on our business, results of operations and cash available for distribution.

        Surface and underground mines like ours are continuously inspected by MSHA, which often leads to notices of violation. Recently, MSHA has been conducting more frequent and more comprehensive inspections.

        On November 19, 2010, Rhino Eastern received an MSHA notification of a potential pattern of violations under Section 104(e) of the Mine Act for Rhino Eastern's Eagle #1 Mine located in Bolt, West Virginia, based on MSHA's initial screening of compliance records for the twelve months ended August 31, 2010 and of accident and employment records for the twelve months ended June 30, 2010. On December 7, 2010, Rhino Eastern submitted a Corrective Action Plan to MSHA and this plan became effective on December 31, 2010. In a letter dated March 15, 2011, MSHA notified Rhino Eastern that MSHA concluded that Rhino Eastern's Eagle #1 Mine achieved the target for its significant and substantial ("S&S") violations during the potential pattern of violations period. Because Rhino Eastern reduced its S&S violations to the targeted rate of S&S violations, MSHA decided to not consider Eagle #1 Mine for a pattern of violations notice pursuant to Section 104(e)(1) of the Mine Act at such time. We cannot predict whether or not future violations would cause MSHA to reconsider Eagle #1 Mine for a pattern of violations notice.

        On March 18, 2011, Rhino Eastern received two imminent danger orders under Section 107(a) of the Mine Act for Eagle #1 Mine. The orders stated that mining was being conducted beneath a previously mined area that was holding an unspecified amount of water and that water was observed entering the mine through the roof. According to MSHA, the water entering the mine has created a risk for miners working in the mine. On April 8, 2011, MSHA terminated the imminent danger orders after we successfully drained the pools of water that caused MSHA to issue the two imminent danger orders, which allowed Rhino Eastern to resume production at the Eagle #1 Mine.

        On June 24, 2011, our subsidiary, CAM Mining LLC received notice that on June 23, 2011, MSHA commenced an action in the United States District Court of the Eastern District of Kentucky seeking injunctive relief as a result of alleged violations of Sections 103, 104, and 108 of the Mine Act occurring at Mine 28 in connection with an inspection on June 17, 2011 by MSHA inspectors. More specifically, MSHA was notified that CAM Mining LLC employees had allegedly been smoking underground at Mine 28, which has an alleged history of methane and hydrocarbon production and ignition. The complaint alleges that when MSHA inspectors arrived at Mine 28 to inspect the mine with respect to the smoking allegation, CAM Mining LLC employees gave advance notice of the inspection to miners working underground and that this advance notice hindered, interfered with and delayed the inspection by MSHA. The complaint asserts that the MSHA inspectors did not find any evidence of smoking paraphernalia during the inspection, which was allegedly the result of this advance notice. Although the mine safety laws permit MSHA to pursue a number of remedies for violations of

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the advance warning prohibitions, the complaint seeks an injunction to enjoin CAM Mining LLC from any further violations of Sections 103, 104, and 108 of the Mine Act. On June 30, 2011, MSHA obtained a temporary restraining order prohibiting such further violations. We are currently investigating the allegations in the complaint and intends to continue to fully cooperate with MSHA to ensure that all mine safety and health regulations are being complied with at its mines.

        As a result of these and future inspections and alleged violations and potential violations, we could be subject to material fines, penalties or sanctions. Any of our mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our business, results of operations and cash available for distribution.

We may be unable to obtain and/or renew permits necessary for our operations, which could prevent us from mining certain reserves.

        Numerous governmental permits and approvals are required for mining operations, and we can face delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in the future.

        Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and discharge dredged or fill material into waters of the United States. Our surface coal mining operations typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

        Please read "Part I, Item 1. Business—Regulation and Laws—Clean Water Act" for a discussion of recent litigation and regulatory developments related to the CWA. An inability to obtain the necessary permits to conduct our mining operations or an inability to comply with the requirements of applicable permits would reduce our production and cash flows, which could limit our ability to make distributions to our unitholders.

Our mining operations are subject to operating risks that could adversely affect production levels and operating costs.

        Our mining operations are subject to conditions and events beyond our control that could disrupt operations, resulting in decreased production levels and increased costs.

        These risks include:

    unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;

    inability to acquire or maintain necessary permits or mining or surface rights;

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    changes in governmental regulation of the mining industry or the electric utility industry;

    adverse weather conditions and natural disasters;

    accidental mine water flooding;

    labor-related interruptions;

    transportation delays;

    mining and processing equipment unavailability and failures and unexpected maintenance problems; and

    accidents, including fire and explosions from methane.

        Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

        In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workmen's compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shut-down could give rise to liabilities for failure to meet the requirements of coal-supply agreements especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, including business interruption insurance, but those policies are subject to various exclusions and limitations and we cannot assure you that we will receive coverage under those policies for any personal injury, property damage or business interruption claims that may arise out of such an accident. Moreover, certain potential liabilities such as fines and penalties are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our results of operations and cash available for distribution.

Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

        Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer's purchasing decision. Increases in transportation costs could make coal a less competitive energy source or could make our coal production less competitive than coal produced from other sources.

        Significant decreases in transportation costs could result in increased competition from coal producers in other regions. For instance, coordination of the many eastern U.S. coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing regions limited the use of western coal in certain eastern markets. The increased competition could have an adverse effect on our results of operations and cash available for distribution to our unitholders.

        We depend primarily upon railroads, barges and trucks to deliver coal to our customers. Disruption of any of these services due to weather-related problems, strikes, lockouts, accidents, mechanical difficulties and other events could temporarily impair our ability to supply coal to our

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customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

        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 other states 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 our results of operations and cash available for distribution.

A shortage of skilled labor in the mining industry could reduce productivity and increase operating costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.

        Efficient coal mining using modern techniques and equipment requires skilled laborers. The coal industry is experiencing a shortage of skilled labor as well as rising labor and benefit costs, due in large part to demographic changes as existing miners retire at a faster rate than new miners are entering the workforce. If the shortage of experienced labor continues or worsens or coal producers are unable to train enough skilled laborers, there could be an adverse impact on labor productivity, an increase in our costs and our ability to expand production may be limited. If coal prices decrease or our labor prices increase, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Unexpected increases in raw material costs, such as steel, diesel fuel and explosives could adversely affect our results of operations.

        Our coal mining operations are affected by commodity prices. We use significant amounts of steel, diesel fuel, explosives and other raw materials in our mining operations, and volatility in the prices for these raw materials could have a material adverse effect on our operations. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other industries. Shortages in raw materials used in the manufacturing of explosives, which, in some cases, do not have ready substitutes, or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of us or our contractors to obtain these supplies. Future volatility in the price of steel, diesel fuel, explosives or other raw materials will impact our operating expenses and could adversely affect our results of operations and cash available for distribution.

If we are not able to acquire replacement coal reserves that are economically recoverable, our results of operations and cash available for distribution to our unitholders could be adversely affected.

        Our results of operations and cash available for distribution to our unitholders depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we fail to acquire or develop additional reserves, our existing reserves will eventually be 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. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our results of operations and cash available for distribution to our unitholders. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt

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agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

Inaccuracies in our estimates of coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs.

        We base our and the joint venture's coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff, which is periodically audited by independent engineering firms. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, recently acquired coal reserves and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating quantities and qualities of coal reserves and non-reserve coal deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results. These factors and assumptions relate to:

    quality of coal;

    geological and mining conditions and/or effects from prior mining that may not be fully identified by available exploration data or which may differ from our experience in areas where we currently mine;

    the percentage of coal in the ground ultimately recoverable;

    the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

    historical production from the area compared with production from other similar producing areas;

    the timing for the development of reserves; and

    assumptions concerning equipment and productivity, future coal prices, operating costs, capital expenditures and development and reclamation costs.

        For these reasons, estimates of the quantities and qualities of the economically recoverable coal attributable to any particular group of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery, estimated cost of production and estimates of net cash flows expected from particular reserves as prepared by different engineers or by the same engineers at different times may vary materially due to changes in the above factors and assumptions. Actual production from identified coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures associated with our and the joint venture's mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our and the joint venture's actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our and the joint venture's coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.

We invest in non-coal natural resource assets, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

        Part of our business strategy is to expand our operations through strategic acquisitions, which includes investing in non-coal natural resources assets. Our executive officers do not have experience

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investing in or operating non-coal natural resources assets and we may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural resource assets could expose us to new and additional operating and regulatory risks, including commodity price risk, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

        During 2011, we invested approximately $8.1 million and $19.9 million for mineral rights in the Cana Woodford region of Oklahoma and oil and gas leases in the Utica Shale region of northeastern Ohio, respectively. The oil and natural gas markets are highly volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Such fluctuations could cause us not to realize the full benefits from such investments.

        In addition, the natural gas industry could be impacted by the controversy surrounding hydraulic fracturing to extract shale gas. This could include additional regulations imposed on the industry.

The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

        Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment. Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus is $16 to $19 million for 2012. This amount is based on our current estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity, which we believe to be reasonable. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. The amount of our estimated maintenance capital expenditures may be more than our actual maintenance capital 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 maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please read "—Risks Inherent in an Investment in Us—Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner."

Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations and cash available for distribution to our unitholders.

        Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other consumers of our coal. These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. Accordingly, these laws

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and regulations may affect demand and prices for our higher sulfur coal. Please read "Part I, Item 1. Business—Regulation and Laws."

Federal and state laws restricting the emissions of greenhouse gases in areas where we conduct our business or sell our coal could adversely affect our operations and demand for our coal.

        Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere and impacting climate. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of GHG. Many states have already taken legal measures to reduce emissions of GHG, primarily through the development of regional GHG cap-and-trade programs.

        In the wake of the Supreme Court's April 2, 2007 decision in Massachusetts, et al. v. EPA, which held that GHG fall under the definition of "air pollutant" in the federal Clean Air Act, or CAA, in December 2009 the EPA issued a final rule declaring that six GHG, including carbon dioxide and methane, "endanger both the public health and the public welfare of current and future generations." The issuance of this "endangerment finding" allows the EPA to begin regulating GHG emissions under existing provisions of the CAA. There are many regulatory approaches currently in effect or being considered to address GHG, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA.

        The permitting of new coal-fired power plants has also been contested by state regulators and environmental organizations for concerns related to GHG emissions from the new plants. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to EPA's Environmental Appeals Board. As state permitting authorities continue to consider GHG control requirements as part of major source permitting Best Available Control Technology (BACT) requirements, costs associated with new facility permitting and use of coal could increase substantially. A growing concern is the possibility that BACT will be determined to be the use of an alternative fuel to coal.

        As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less GHG emissions, possibly further reducing demand for our coal, which could adversely affect our results of operations and cash available for distribution to our unitholders. Please read "Part I, Item 1. Business—Regulation and Laws—Carbon Dioxide Emissions."

Federal and state laws require bonds to secure our obligations to reclaim mined property. Our inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

        We are required under federal and state laws to place and maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as "reclamation") and to satisfy other miscellaneous obligations. Federal and state governments could increase bonding requirements in the future. Certain business transactions, such as coal leases and other obligations, may also require bonding. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including supporting letters of credit or posting cash collateral, or other terms less favorable to us upon those renewals. The failure to maintain or the inability to acquire sufficient surety bonds, as required

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by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:

    the lack of availability, higher expense or unreasonable terms of new surety bonds;

    the ability of current and future surety bond issuers to increase required collateral; and

    the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

        We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. 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 or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. As of December 31, 2011, we had $69.9 million in reclamation surety bonds, secured by $21.3 million in letters of credit outstanding under our credit agreement. Our credit agreement provides for a $300 million working capital revolving credit facility, of which up to $75.0 million may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations. For more information, please read "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement." If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

We depend on a few customers for a significant portion of our revenues. If a substantial portion of our supply contracts terminate or if any of these customers were to significantly reduce their purchases of coal from us, and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations and cash available for distribution to our unitholders could be adversely affected.

        We sell a material portion of our coal under supply contracts. As of December 31, 2011 we had sales commitments for approximately 93% of our estimated coal production (including purchased coal to supplement our production and excluding results from the joint venture) for the year ending December 31, 2012. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of these committed tons, under the terms of the supply contracts, we will ship 44% in 2012, 33% in 2013, 20% in 2014 and 3% in 2015. We derived approximately 82.1% of our total revenues from coal sales (excluding results from the joint venture) to our ten largest customers for the year ended December 31, 2011, with affiliates of our top three customers accounting for approximately 44.8% of our coal revenues during that period.

        In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply contracts or may significantly reduce their purchases of coal from us. In addition, interruption in the purchases by or operations of our principal customers could significantly affect our results of operations and cash available for distribution. Unscheduled maintenance outages at our customers' power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases. The amount and terms of sales of coal produced from our Rhino Eastern mining complex are controlled by an affiliate of Patriot pursuant to the joint venture agreement. We cannot guarantee that Patriot will be successful in obtaining coal supply contracts at favorable prices, if at all, which could have a material adverse effect on our results

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of operations and cash available for distribution to our unitholders. For additional information relating to these contracts, please read "Part I, Item 1. Business—Customers—Coal Supply Contracts."

Any change in consumption patterns by utilities away from the use of coal, such as resulting from current low natural gas prices, could affect our ability to sell the coal we produce, which could adversely affect our results of operations and cash available for distribution to our unitholders.

        Excluding results from the joint venture, steam coal accounted for approximately 87% of our coal sales volume for the year ended December 31, 2011. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

        Price adjustment, "price re-opener" and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our results of operations and cash available for distribution to our unitholders.

        Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our supply contracts permit the customer to terminate the agreement in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit.

Our lessees' mining operations and their financial condition and results of operations are subject to some of the same risks and uncertainties that we face as a mine operator.

        The mining operations and financial condition and results of operations of our lessees are subject to the same risks and uncertainties that we face as a mine operator. If any such risks were to occur, the business, financial condition and results of operations of the lessees could be adversely affected and as a result our coal royalty revenues and cash available for distribution could be adversely affected.

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If our lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.

        We depend on our lessees to effectively manage their operations on the leased properties. The lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

    marketing of the coal mined;

    mine plans, including the amount to be mined and the method of mining;

    processing and blending coal;

    expansion plans and capital expenditures;

    credit risk of their customers;

    permitting;

    insurance and surety bonding;

    acquisition of surface rights and other coal estates;

    employee wages;

    transportation arrangements;

    compliance with applicable laws, including environmental laws; and

    mine closure and reclamation.

        A failure on the part of one of the lessees to make royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we might not be able to find a replacement lessee or enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.

Lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.

        Coal supply contracts often require operators to satisfy their obligations to their customers with resources mined from specific reserves or may provide the operator flexibility to source the coal from various reserves. Several factors may influence a lessee's decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee's lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues.

A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

        We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any

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undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with the lessees, or internal control deficiencies.

Disruption in supplies of coal produced by contractors operating at our mines could temporarily impair our ability to fill our customers' orders or increase our costs.

        We at times use contractors to operate certain of our mines. For the year ended December 31, 2011, approximately 4% of our total coal production was from contractor-operated mines. Disruption in our supply of coal produced by these contractors could temporarily impair our ability to fill our customers' orders or require us to pay higher prices in order to obtain the required coal from other sources. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers and other factors beyond our control could affect the availability, pricing and quality of coal produced by our contractors. Any increase in the prices we pay for contractor-produced coal could increase our costs and therefore adversely affect our results of operations and cash available for distribution to our unitholders.

Defects in title in the properties that we own or loss of any leasehold interests could limit our ability to mine these properties or result in significant unanticipated costs.

        We conduct a significant part of our mining operations on leased properties. A title defect or the loss of any lease could adversely affect our ability to mine the associated reserves. Title to most of our owned and leased properties and the associated mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our grantors or lessors, as the case may be. Our right to mine some reserves would be adversely affected by defects in title or boundaries or if a lease expires. Any challenge to our title or leasehold interest could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on a lease that we are unable to renew on terms at least as favorable, if at all. In such event, we may have to close down or significantly alter the sequence of mining operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur liability for such mining. Our sponsor, Wexford Capital, will not indemnify us for losses attributable to title defects in the properties that we own or lease.

Our work force could become unionized in the future, which could adversely affect our production and labor costs and increase the risk of work stoppages.

        Currently, none of our employees are represented under collective bargaining agreements. However, all of our work force may not remain union-free in the future. If some or all of our work force were to become unionized, it could adversely affect our productivity and labor costs and increase the risk of work stoppages.

We depend on key personnel for the success of our business.

        We depend on the services of our senior management team and other key personnel. The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available.

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If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

        The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed both periodically by our management and annually by independent third-party engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Please read "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Asset Retirement Obligations." Wexford will not indemnify us against any reclamation or mine closing liabilities associated with our assets.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

        Our level of indebtedness could have important consequences to us, including the following:

    our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

    covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

    we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, distributions to unitholders and future business opportunities;

    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.

        Increases in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, 2011 our current portion of long-term debt that will be funded from cash flows from operating activities during 2012 was approximately $1.3 million. Our ability to service our indebtedness 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 current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities and limit our ability to pay distributions upon the occurrence of certain events.

        The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to

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engage, expand or pursue our business activities. For example, our credit agreement restricts our ability to:

    incur additional indebtedness or guarantee other indebtedness;

    grant liens;

    make certain loans or investments;

    dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;

    change the line of business conducted by us or our subsidiaries;

    enter into a merger, consolidation or make acquisitions; or

    make distributions if an event of default occurs.

        In addition, our payment of principal and interest on our debt will reduce cash available for distribution on our units. Our credit agreement limits our ability to pay distributions upon the occurrence of the following events, among others, which would apply to us and our subsidiaries:

    failure to pay principal, interest or any other amount when due;

    breach of the representations or warranties in the credit agreement;

    failure to comply with the covenants in the credit agreement;

    cross-default to other indebtedness;

    bankruptcy or insolvency;

    failure to have adequate resources to maintain, and obtain, operating permits as necessary to conduct our operations substantially as contemplated by the mining plans used in preparing the financial projections; and

    a change of control.

        Any subsequent refinancing of our current debt or any new debt could have similar restrictions. Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders' commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders could seek to foreclose on such assets. For more information, please read "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement."

Risks Inherent in an Investment in Us

Wexford owns and controls our general partner. Our general partner has fiduciary duties to its owners, and the interests of its owners may differ significantly from, or conflict with, the interests of our public common unitholders.

        Wexford owns and controls our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its

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owners. Therefore, conflicts of interest may arise between its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our common unitholders. These conflicts include the following situations:

    our general partner is allowed to take into account the interests of parties other than us, such as its owners, 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 Wexford to pursue a business strategy that favors us;

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

    except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

    our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

    our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus;

    our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

    our partnership agreement permits us to distribute up to $25.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;

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

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

    our general partner intends to limit its liability regarding our contractual and other obligations;

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

    our general partner controls the enforcement of obligations that it and its affiliates owe to us;

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

    our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general

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      partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

        In addition, Wexford currently holds substantial interests in other companies in the energy and natural resource sectors. We may compete directly with entities in which Wexford has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us. Please read "—Our sponsor, Wexford Capital, and affiliates of our general partner may compete with us."

Common units held by unitholders who are not eligible citizens will be subject to redemption.

        In order to comply with U.S. laws with respect to the ownership of interests in mineral leases on federal lands, we have adopted certain requirements regarding those investors who own our common units. As used in this report, an eligible citizen means a person or entity qualified to hold an interest in mineral leases on federal lands. As of the date hereof, an eligible citizen must be: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an eligible citizen run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

        In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our

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credit agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner's fiduciary duties to holders of our common and subordinated units.

        Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

    how to allocate business opportunities among us and its affiliates;

    whether to exercise its limited call right;

    how to exercise its voting rights with respect to the units it owns;

    whether to exercise its registration rights;

    whether to elect to reset target distribution levels; and

    whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

        By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

    provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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

    provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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    provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

    (1)
    approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

    (2)
    approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

    (3)
    on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

    (4)
    fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (3) and (4) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our sponsor, Wexford Capital, and affiliates of our general partner may compete with us.

        Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. Affiliates of our general partner, including our sponsor, Wexford Capital, and its investment funds, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Through its investment funds, Wexford Capital currently holds substantial interests in other companies in the energy and natural resources sectors. Wexford Capital, through its investment funds and managed accounts, makes investments and purchases entities in the coal and oil and natural gas sectors. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, Wexford Capital may compete with us for investment opportunities and Wexford may own an interest in entities that compete with us.

        Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and Wexford Capital. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

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

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) 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 will retain its then-current general partner interest. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an 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. 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 incentive distributions 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 to our general partner in connection with resetting the target distribution levels.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Wexford, as a result of it owning our general partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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

        If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of March 9, 2012, Wexford owned an aggregate of approximately 72% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no

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units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a "change of control" without the vote or consent of the unitholders.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. As of March 9, 2012, Wexford owned an aggregate of approximately 54% of our common units and approximately 95% of our subordinated units.

We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

        Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

    our existing unitholders' proportionate ownership interest in us will decrease;

    the amount of cash available for distribution on each unit may decrease;

    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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    the ratio of taxable income to distributions may increase;

    the relative voting strength of each previously outstanding unit may be diminished; and

    the market price of the common units may decline.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Wexford or other large holders.

        As of December 31, 2011, we had 15,318,178 common units and 12,397,000 subordinated units outstanding. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. Sales by Wexford or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to Wexford. Under our agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.

        Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

        While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Wexford) after the subordination period has ended. As of March 9, 2012, Wexford owned approximately 54% of the outstanding common units and 95% of our outstanding subordinated units.

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

        Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible 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. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

        It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner, (ii) approve some amendments to our partnership agreement or (iii) take other action under our partnership agreement constitutes "participation in the control" of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.

The New York Stock Exchange does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

        Because we are a publicly traded limited partnership, the New York Stock Exchange, or NYSE, does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

We may not be able to establish and maintain effective internal controls in accordance with applicable federal securities laws and regulations, and we may incur significant costs in our efforts.

        We have only recently become subject to the public reporting requirements of the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. Although we have taken measures to improve our internal control over financial reporting, material weaknesses may result in a material misstatement of our financial statements in the future.

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Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we become subject to additional amounts of entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a "qualifying income" requirement. Based on our current operations we believe that we are treated as a partnership rather than a corporation for such purposes; however, a change in our business 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 U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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.

        Current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subjecting us to entity-level taxation. Additionally, the present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or judicial interpretation at any time. For example, at the federal level, legislation has been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to us as considered, it could be reintroduced and amended prior to enactment in a manner that does apply to us. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of such change, or other proposals, will ultimately be enacted. Any such change could negatively impact the value of an investment in our common units.

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 additional amounts of entity-level taxation for federal or state tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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If 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 U.S. 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. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact 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.

Unitholders' share of our income will be taxable for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

        Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from such income.

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 U.S. federal income tax purposes equal to the difference between the amount you realize on the sale 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 units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion and depreciation recapture. In addition, because the amount realized includes your share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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 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 tax rate, and non-U.S. persons will be required to file U.S. federal 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.

        Due to a number of factors, including our inability to match transferors and transferees of common units, 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 the month, instead of on the basis of the date a particular unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change our allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those 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 units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller 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 borrowing their units.

We will adopt certain valuation methodologies, for U.S. federal income tax purposes, that may result in a shift of income, gain, loss and deduction between our general partner and the 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

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deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

        A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have technically terminated for U.S. 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 a technical tax termination has occurred, a sale or exchange of 50% or more of the total interests in our capital and profits could occur if, for example, Rhino Energy Holdings LLC, which currently owns approximately 67% of the total interests in our capital and profits, sells or exchanges a majority of the interests it owns in us within a period of twelve months of the total interests in our capital and profits, sells or exchanges a majority of the interests it owns in us within a period of twelve months. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, 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) 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 the unitholder's taxable income for the year of termination. A technical termination 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 technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.

        President Obama's Proposed Fiscal Year 2012 budget recommends elimination of certain key U.S. federal income tax preferences relating to coal exploration and development (the "Budget Proposal"). The Budget Proposal would (1) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal and lignite royalties, and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or

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any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

        In addition to U.S. federal income taxes, 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 do business or control property now or in the future, even if they do not live in any of those jurisdictions. 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, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in a number of states, most of which also impose an income tax on corporations and other entities. In addition, many of these states also impose 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.

Item 1B.    Unresolved Staff Comments

        None.

Item 2.    Properties.

        See "Part I, Item 1. Business" for information about our mining operations.

Coal Reserves and Non-Reserve Coal Deposits

        We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, coal reserves recently acquired and estimated costs of production and sales prices. Changes in mining methods may increase or decrease the recovery basis for a coal seam as will plant processing efficiency tests. We maintain reserve and non-reserve coal deposit information in secure computerized databases, as well as in hard copy. The ability to update and/or modify the estimates of our coal reserves and non-reserve coal deposits is restricted to a few individuals and the modifications are documented.

        Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our and the joint venture's coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc., as of December 31, 2011, and covered a majority of the coal reserves and non-reserve coal deposits that we and the joint venture controlled as of such date. The coal reserve and non-reserve coal deposit estimates for the Castle Valley mining complex in Utah were audited by Norwest Corporation as of December 31, 2011 due to this firm's familiarity with the coal reserves at this location, as Norwest Corporation performed the initial coal reserve audit when we purchased Castle Valley in August 2010. Additionally, the coal reserve and non-reserve coal deposit information for our Elk Horn operation was audited by John T. Boyd Company in September 2011 in connection with our acquisition of Elk Horn in June 2011. Our estimates as of December 31, 2011 for Elk Horn's reserves

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were prepared by our staff of geologists and engineers. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

        As of December 31, 2011, we controlled an estimated 437.0 million tons of proven and probable reserves and an estimated 417.1 million tons of non-reserve coal deposits. As of December 31, 2011, the joint venture controlled an estimated 43.4 million tons of proven and probable coal reserves and an estimated 17.9 million tons of non-reserve coal deposits.

Coal Reserves

        The following table provides information as of December 31, 2011 on the type, amount and ownership of the coal reserves:

 
  Proven and Probable Reserves(1)  
Region
  Total(3)   Proven   Probable   Assigned   Unassigned   Owned   Leased   Steam(2)   Metallurgical(2)  
 
  (in million tons)
 

Central Appalachia

                                                       

Tug River Complex (KY, WV)

    23.0     17.8     5.2     19.0     4.0     5.0     18.0     17.2     5.8  

Rob Fork Complex (KY)

    24.5     20.8     3.7     24.5         7.6     16.9     17.5     7.0  

Deane Complex (KY)

    39.5     23.8     15.7     7.1     32.4     39.5         39.5      

Rich Mountain Field (WV)

    8.6     1.5     7.1         8.6     8.6             8.6  

Elk Horn (KY)

    117.5     80.1     37.4     58.1     59.4     115.1     2.4     117.5      
                                       

Total Central Appalachia(3)

    213.1     144.0     69.1     108.7     104.4     175.8     37.3     191.7     21.4  
                                       

Northern Appalachia

                                                       

Hopedale Complex (OH)

    27.7     21.0     6.7     10.5     17.2     11.2     16.5     27.7      

Sands Hill Complex (OH)

    10.7     9.1     1.6     10.7         1.4     9.3     10.7      

Leesville Field (OH)

    27.0     7.8     19.2         27.0     27.0         27.0      

Springdale Field (PA)

    13.8     8.8     5.0         13.8     13.8         13.8      
                                       

Total Northern Appalachia(3)

    79.2     46.7     32.5     21.2     58.0     53.4     25.8     79.2      
                                       

Illinois Basin

                                                       

Taylorville Field (IL)

    111.0     38.7     72.3         111.0         111.0     111.0      

Western Bituminous

                                                       

Castle Valley Complex (UT)

    27.2     15.7     11.5     27.2             27.2     27.2      

McClane Canyon Mine (CO)

    6.5     4.4     2.1     6.5         0.2     6.3     6.5      
                                       

Total Western Bituminous(3)

    33.7     20.1     13.6     33.7         0.2     33.5     33.7      
                                       

Total(3)

    437.0     249.5     187.5     163.6     273.4     229.4     207.6     415.6     21.4  
                                       

Percentage of total(3)

          57.1 %   42.9 %   37.4 %   62.6 %   52.5 %   47.5 %   95.1 %   4.9 %

Central Appalachia

                                                       

Rhino Eastern Complex (WV)(4)

    43.4     23.7     19.7     38.7     4.7         43.4         43.4  

Percentage of total(3)

          54.6 %   45.4 %   89.2 %   10.8 %       100 %       100 %

(1)
Represents recoverable tons.

(2)
For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. All other coal reserves are defined as steam coal. However, some of the reserves in the metallurgical category can also be used as steam coal.

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(3)
Totals and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

(4)
Owned by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the reserves.

        The majority 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 the terms of the lease are complied with. Some of our leases have terms denominated in years rather than mine-to-exhaustion provisions, but in all such cases, we believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan. Consistent with industry practice, we conduct only limited investigations of title to our and the joint venture's coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our and the joint venture's leased priorities are not completely verified until we prepare to mine those reserves.

        The following table provides information on particular characteristics of our and the joint venture's coal reserves as of December 31, 2011:

 
  As Received Basis(1)   Proven and Probable Coal Reserves(2)(3)  
 
   
   
   
   
   
  Sulfur Content  
 
   
   
   
  S02/mm
Btu
   
 
Region
  % Ash   % Sulfur   Btu/lb.   Total   <1%   1 - 1.5%   >1.5%   Unknown  
 
   
   
   
   
   
  (in million tons)
   
 

Central Appalachia

                                                       

Tug River Complex (KY, WV)

    10.61 %   1.23 %   12,899     1.91     23.0     13.7     5.5     2.5     1.3  

Rob Fork Complex (KY)

    6.04 %   1.17 %   13,395     1.74     24.5     14.8     5.8     2.3     1.6  

Deane Complex (KY)

    5.39 %   0.91 %   13,442     1.35     39.5     21.0     11.5     0.9     6.1  

Rich Mountain Field (WV)

    6.56 %   0.64 %   13,509     0.94     8.6     8.6              

Elk Horn (KY)

    11.80 %   1.50 %   13,047     2.30     117.5     19.8     42.3     55.0     0.4  
                                       

Total Central Appalachia(3)

    9.76 %   1.30 %   13,154     1.98     213.1     77.9     65.1     60.7     9.4  
                                       

Northern Appalachia

                                                       

Hopedale Complex (OH)

    6.59 %   2.25 %   12,999     3.46     27.7             27.7      

Sands Hill Complex (OH)

    9.29 %   3.13 %   11,779     5.31     10.7             10.2     0.5  

Leesville Field (OH)

    6.21 %   2.21 %   13,152     3.36     27.0             27.0      

Springdale Field (PA)

    6.63 %   1.72 %   13,443     2.55     13.8             13.8      
                                       

Total Northern Appalachia(3)

    6.82 %   2.26 %   12,972     3.48     79.2             78.7     0.5  
                                       

Illinois Basin

                                                       

Taylorville Field (IL)

    7.75 %   3.53 %   11,057     6.38     111.0             111.0      

Western Bituminous

                                                       

Castle Valley Complex (UT)

    10.99 %   0.72 %   12,127     1.16     27.2     27.0     0.2          

McClane Canyon Mine (CO)

    11.19 %   0.57 %   11,241     1.01     6.5     6.5              
                                       

Total Western Bituminous(3)

    11.03 %   0.69 %   11,957     1.16     33.7     33.5     0.2          
                                       

Total(3)

    8.79 %   2.01 %   12,481     3.22     437.0     111.4     65.3     250.4     9.9  
                                       

Percentage of total(3)

                                  25.5 %   14.9 %   57.3 %   2.3 %

Central Appalachia

                                                       

Rhino Eastern Complex (WV)(4)

    4.42 %   0.68 %   14,019     0.97     43.4     38.0     4.9         0.5  

(1)
As received represents an analysis of a sample as received at a laboratory.

(2)
Represents recoverable tons.

(3)
Totals and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

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(4)
Owned by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the reserves.

Non-Reserve Coal Deposits

        The following table provides information on our and the joint venture's non-reserve coal deposits as of December 31, 2011:

 
  Non-Reserve Coal Deposits  
 
   
  Total Tons  
 
  Total Tons  
Region
  Owned   Leased  
 
  (in million tons)
 

Central Appalachia

    177.6     166.4     11.2  

Northern Appalachia

    30.8     25.8     5.0  

Illinois Basin

    33.0         33.0  

Western Bituminous

    175.7         175.7  
               

Total

    417.1     192.2     224.9  
               

Percentage of total

          46.1 %   53.9 %

Rhino Eastern (Central Appalachia)(1)

    17.9         17.9  

(1)
Owned by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the non-reserve coal deposits.

        The joint venture leased all of its non-reserve coal deposits from third-party landowners. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to lands and non-reserve coal deposits of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine the coal.

Office Facilities

        We lease office space in Lexington, Kentucky for our executives and administrative support staff. We lease our executive office space at 424 Lewis Hargett Circle, Lexington, Kentucky, which lease expires August 2013, subject to us having two consecutive three-year renewal options. In addition, we lease a building primarily for our administrative support staff at 265 Hambley Boulevard, Pikeville, Kentucky, which lease expires June 2015, subject to us having a five-year renewal option.

Item 3.    Legal Proceedings

        We may, from time to time, be involved in various legal proceedings and claims arising out of our operations in the normal course of business. While many of these matters involve inherent uncertainty, we do not believe that we are a party to any legal proceedings or claims that will have a material adverse impact on our business, financial condition or results of operations.

Item 4.    Mine Safety Disclosure

        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 for the year ended December 31, 2011 is included in Exhibit 95.1 to this report.

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our Limited Partnership Interests

        Our common units began trading on the NYSE under the symbol "RNO" on September 30, 2010. On March 9, 2012, the closing market price for our common units was $20.17 per unit. The following table sets forth the range of the daily high and low sales prices and cash distribution per common unit for the periods indicated:

 
  Price Range    
 
 
  Cash
Distribution(1)
 
 
  High   Low  

Year ended December 31, 2011

                   

Fourth Quarter

  $ 22.68   $ 15.02   $ 0.4800  

Third Quarter

  $ 28.23   $ 17.05   $ 0.4800  

Second Quarter

  $ 26.43   $ 21.55   $ 0.4550  

First Quarter

  $ 27.31   $ 22.78   $ 0.4550  

Year ended December 31, 2010

                   

Fourth Quarter (from September 30, 2010)

  $ 24.86   $ 21.10   $ 0.4208 (2)

(1)
Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a calendar quarter are paid in the following calendar quarter.

(2)
The distribution of $0.4208 per common unit corresponds to the minimum quarterly distribution of $0.445 per unit prorated for the portion of the quarter after October 5, 2010, the closing date of our IPO.

        As of March 9, 2012, we had outstanding 15,318,178 common units, 12,397,000 subordinated units, a 2% general partner interest and incentive distribution rights, or IDRs. As of March 9, 2012, Rhino Energy Holdings LLC owned approximately 49.8% of our outstanding common units and 87.9% of our subordinated units. Our general partner currently owns a 2.0% general partner interest in us and all of our IDRs.

        As of March 9, 2012, there were 64 holders of record of our common units. The number of record holders does not include holders of shares in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Cash Distribution Policy

        We will make a minimum quarterly distribution of $0.445 per common unit (or $1.78 per common unit on an annualized basis) to the extent we have sufficient available cash. Available cash is generally defined as cash from operations after establishment by our general partner of cash reserves 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 unitholders for any one or more of the next four quarters, and payment of costs and expenses, including reimbursement of expenses to our general partner and its affiliates. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish or the amount of expenses for which our general partner and its affiliates may be reimbursed. 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. We

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may also borrow to fund distributions in quarters when we generate less available cash than necessary to sustain or grow our cash distributions per unit.

        There is no guarantee that we will distribute quarterly cash distributions to our unitholders. Our distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

    Our cash distribution policy is subject to restrictions on distributions under our credit agreement. Our credit agreement contains financial tests and covenants that we must satisfy. These financial tests and covenants are described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement." Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit agreement, we would be prohibited from making cash distributions notwithstanding our cash distribution policy.

    Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.

    Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.

    While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Wexford) after the subordination period has ended. Wexford currently owns approximately 54% of the outstanding common units and 95% of our outstanding subordinated units.

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

    Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or selling, general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

    If we make distributions out of capital surplus, as opposed to operating surplus, such distributions will result in a reduction in the minimum quarterly distribution and the target distribution levels. However, we do not anticipate that we will make any distributions from capital surplus.

    Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make

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      distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

        Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner:

    first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.445 plus any arrearages from prior quarters;

    second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.445; and

    third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.51175.

        If cash distributions to our unitholders exceed $0.51175 per unit in any quarter, our unitholders and our general partner will receive distributions according to the following percentage allocations:

 
  Marginal Percentage
Interest in
Distributions
 
Total Quarterly Distribution Target Amount
  Unitholders   General
Partner
 

Above $0.51175 up to $0.55625

    85.0 %   15.0 %

Above $0.55625 up to $0.6675

    75.0 %   25.0 %

Above $0.6675

    50.0 %   50.0 %

        The percentage interest shown of our general partner include its 2.0% general partner interest. Our general partner is entitled to 2.0% of all distributions that we make prior to our liquidation. Our partnership agreement provides our general partner the right, but not the obligation, to contribute capital to maintain its 2.0% general partner interest in us if we issue additional units in the future. Thus, if our general partner elects not to make such a capital contribution, its interest will be proportionately reduced.

        During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the minimum quarterly distribution plus any arrearages in distributions from prior quarters. The subordination period will end on the first business day after we have earned and paid at least (i) $1.78 (the minimum quarterly distribution on an annualized basis) on each outstanding unit and the corresponding distribution on our general partner's general partner interest for each of three consecutive, non-overlapping four quarter periods ending on or after September 30, 2013 or (ii) $2.67 (150.0% of the annualized minimum quarterly distribution) on each outstanding unit and the corresponding distributions on our general partner's general partner interest and the incentive distribution rights for the four-quarter period immediately preceding that date. The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

        We will pay our distributions on or about the 15th day of each of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.

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Item 6.    Selected Financial Data.

        The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidated financial statements. On October 5, 2010, we closed our IPO of 3,730,600 common units. In conjunction with the IPO, on September 29, 2010 Wexford became obligated to contribute their membership interests in Rhino Energy LLC to us. For ease of reference, we present the historical results of Rhino Energy LLC as our historical results which also includes the portion of fiscal year 2010 results prior to the IPO that contributed to the total 2010 figures presented below as a total for us. The selected historical consolidated financial data presented as of December 31, 2009, 2008 and 2007 and for the years ended December 31, 2008 and 2007 are derived from the audited historical consolidated financial statements of Rhino Energy LLC that are not included in this report. The selected historical consolidated financial data presented for the year ended December 31, 2009 are derived from the audited historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this report. The selected historical consolidated financial data presented as of December 31, 2011 and 2010 and for the years ended December 31, 2011 and 2010 are derived from our audited historical consolidated financial statements that are included elsewhere in this report.

        The following selected consolidated financial data should be read in conjunction with "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8. Financial Statements and Supplementary Data."

        The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business as it is an important supplemental measure of our performance and liquidity. Adjusted EBITDA represents net income before interest expense, income taxes and depreciation, depletion and amortization ("DD&A"), including our proportionate share of DD&A and interest expense for our Rhino Eastern joint venture that is accounted for under the equity method. Adjusted EBITDA also excludes the effect of certain non-recurring items. This measure is not calculated or presented in accordance with GAAP. We explain this measure under "—Non-GAAP Financial Measure" and

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reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

 
  For the Year Ended December 31,  
(in thousands, except per unit and per ton data)
  2011   2010   2009   2008   2007  

Statement of Operations Data:

                               

Total revenues

  $ 367,221   $ 305,647   $ 419,790   $ 438,924   $ 403,452  

Costs and Expenses:

                               

Cost of operations (exclusive of depreciation, depletion and amortization)

    267,180     220,756     336,335     364,912     318,405  

Freight and handling costs

    4,329     2,634     3,991     10,223     4,021  

Depreciation, depletion and amortization

    36,325     34,108     36,279     36,428     30,750  

Selling, general and administrative (exclusive of depreciation, depletion and amortization)

    21,815     16,449     16,754     19,042     15,370  

Asset impairment loss

        652              

(Gain) loss on sale/acquisition of assets—net

    (3,172 )   (10,716 )   1,710     451     (944 )
                       

Total costs and expenses

    326,477     263,883     395,069     431,056     367,602  
                       

Income from operations

    40,744     41,764     24,721     7,868     35,850  

Interest and other income (expense):

                               

Interest expense and other

    (6,062 )   (5,338 )   (6,222 )   (5,500 )   (5,579 )

Interest income and other

    51     24     70     148     317  

Equity in net income (loss) of unconsolidated affiliate(1)

    3,338     4,699     893     (1,587 )    
                       

Total interest and other income (expense)

    (2,673 )   (615 )   (5,259 )   (6,939 )   (5,262 )
                       

Income before income tax

    38,071     41,149     19,462     929     30,588  

Income taxes

                    (126 )
                       

Net income

  $ 38,071   $ 41,149   $ 19,462   $ 929   $ 30,714  
                       

Basic and diluted net income per limited partner common unit(1)

  $ 1.43   $ 0.22     n/a     n/a     n/a  

Distributions paid per limited partner unit

  $ 1.8108     n/a     n/a     n/a     n/a  

Weighted average number of limited partner common units outstanding:

                               

Basic

    13,725     12,400     n/a     n/a     n/a  

Diluted

    13,744     12,413     n/a     n/a     n/a  

Balance Sheet Data:

                               

Cash and cash equivalents

  $ 449   $ 76   $ 687   $ 1,937   $ 3,583  

Property and equipment, net

    450,116     282,577     270,680     282,863     211,657  

Total assets

    538,794     358,645     339,984     352,536     275,992  

Total liabilities

    231,696     111,028     201,583     234,225     158,152  

Total debt—short term and long term

    143,098     36,528     122,138     138,027     83,954  

Partners' capital/Members' equity

  $ 307,098   $ 247,617   $ 138,401   $ 118,311   $ 117,841  

Operating Data(2):

                               

Tons of coal sold

    4,876     4,306     6,699     7,977     8,159  

Tons of coal produced/purchased

    4,873     4,312     6,732     8,017     8,024  

Coal revenues per ton(3)

  $ 68.47   $ 67.32   $ 59.98   $ 51.25   $ 48.30  

Cost of operations per ton(4)

  $ 54.79   $ 51.27   $ 50.21   $ 45.75   $ 39.02  

Other Financial Data:

                               

Net cash provided by operating activities

  $ 66,916   $ 55,001   $ 41,495   $ 57,211   $ 52,493  

Net cash used in investing activities

    (188,024 )   (37,644 )   (27,344 )   (106,638 )   (28,098 )

Net cash provided by (used in) financing activities

    121,481     (17,968 )   (15,401 )   47,781     (21,192 )

Adjusted EBITDA

    81,994     71,473     63,643     43,134     66,917  

Capital expenditures(5)

  $ 211,473   $ 41,250   $ 29,657   $ 92,741   $ 32,773  

(1)
Basic and diluted earnings per unit for 2010 reflects the period from October 6, 2010 to December 31, 2010, which is the period that net income was attributable to us as a publicly traded partnership.

(2)
In May 2008, we entered into a joint venture with an affiliate of Patriot that acquired the Rhino Eastern mining complex, which commenced production in August 2008. We have a 51% membership interest in, and

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    serve as manager for, the joint venture. The operating data do not include data with respect to the Rhino Eastern mining complex. The joint venture produced and sold approximately 0.3 million tons of premium mid-vol metallurgical coal for the years ended December 31, 2011 and 2010.

(3)
Coal revenues per ton represent total coal revenues derived from the sale of coal from all business segments, divided by total tons of coal sold for all segments.

(4)
Cost of operations per ton represents the cost of operations (exclusive of depreciation, depletion and amortization) from all business segments divided by total tons of coal sold for all segments.

(5)
The following table presents a reconciliation of total capital expenditures to net cash used for capital expenditures on a historical basis for each of the periods indicated:

 
  For the Year Ended December 31,  
 
  2011   2010   2009   2008   2007  
 
  (in thousands)
 

Reconciliation of total capital expenditures to net cash used for capital expenditures:

                               

Additions to property, plant and equipment

  $ 91,856   $ 26,248   $ 27,836   $ 78,076   $ 14,599  

Acquisitions of coal companies and coal properties

    119,617     15,002         14,665     18,174  

Acquisition of roof bolt manufacturing company

            1,821          
                       

Total capital expenditures

  $ 211,473   $ 41,250   $ 29,657   $ 92,741   $ 32,773  
                       

Non-GAAP Financial Measure

        The following tables present reconciliations of Adjusted EBITDA to the most directly comparable GAAP financial measures for each of the periods indicated. We believe the presentation of Adjusted EBITDA that includes our proportionate share of DD&A and interest expense for our Rhino Eastern joint venture is appropriate since our portion of Rhino Eastern's net income that is recognized as a single line item in our financial statements is affected by these expense items. Since we do not reflect these proportionate expense items of DD&A and interest expense in our consolidated financial statements, we believe that the adjustment for these expense items in the Adjusted EBITDA calculation is more representative of how we review our results and also provides investors with additional information that they can use to evaluate our results. Adjusted EBITDA also excludes the effect of certain non-recurring items.

        Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income, income from operations and cash flows from operating activities, and these measures may vary among other companies.

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  For the Year Ended December 31,  
(in thousands)
  2011   2010   2009   2008   2007  

Reconciliation of Adjusted EBITDA to net income:

                               

Net income

  $ 38,071   $ 41,149   $ 19,462   $ 929   $ 30,714  

Plus:

                               

DD&A

    36,325     34,108     36,279     36,428     30,750  

Interest expense

    6,062     5,338     6,222     5,501     5,579  

Less:

                               

Income tax benefit

                    126  
                       

EBITDA(a)

  $ 80,458   $ 80,595   $ 61,964   $ 42,858   $ 66,917  
                       

Plus: Rhino Eastern DD&A-51%

    1,509     1,630     1,460     260      

Plus: Rhino Eastern interest expense-51%

    27     37     219     16      

Less: Gain from Castle Valley acquisition(b)

        (10,789 )            
                       

Adjusted EBITDA(a)

  $ 81,994   $ 71,473   $ 63,643   $ 43,134   $ 66,917  
                       

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:

                               

Net cash provided by (used in) operating activities

  $ 66,916   $ 55,001   $ 41,495   $ 57,211   $ 52,493  

Plus:

                               

Increase in net operating assets

    8,889     10,260     17,190         10,553  

Decrease in provision for doubtful accounts

    19                 175  

Gain on sale of assets

    3,172                 944  

Gain on acquisition

        10,789              

Gain on retirement of advance royalties

                    115  

Amortization of deferred revenue

    532                  

Interest expense

    6,062     5,338     6,222     5,501     5,579  

Settlement of litigation

            1,773          

Equity in net income of unconsolidated affiliate

    3,338     4,699     893          

Less:

                               

Decrease in net operating assets

                10,440      

Accretion on interest-free debt

    210     206     200     569     360  

Amortization of advance royalties

    1,104     865     215     471     700  

Amortization of debt issuance costs

    1,043     844              

Increase in provision for doubtful accounts

            19          

Equity-based compensation

    727     291              

Loss on sale of assets

        73     1,710     451      

Loss on asset impairments

        652              

Loss on retirement of advance royalties

    79     396     712     45      

Income tax benefit

                    126  

Accretion on asset retirement obligations

    1,956     2,165     2,753     2,709     1,757  

Equity in net loss of unconsolidated affiliate

                1,587      

Distributions from unconsolidated affiliate

    3,351                  

Payment of abandoned public offering expenses(c)

                3,582      
                       

EBITDA(a)

  $ 80,458   $ 80,595   $ 61,964   $ 42,858   $ 66,917  
                       

Plus: Rhino Eastern DD&A-51%

    1,509     1,630     1,460     260      

Plus: Rhino Eastern interest expense-51%

    27     37     219     16      

Less: Gain from Castle Valley acquisition(b)

        (10,789 )            
                       

Adjusted EBITDA(a)

  $ 81,994   $ 71,473   $ 63,643   $ 43,134   $ 66,917  
                       

(a)
Calculated based on actual amounts and not the rounded amounts presented in this table. Totals may not foot due to rounding.

(b)
During 2010, we acquired certain assets for cash consideration of approximately $15.0 million from the Trustee of the Federal Bankruptcy Court charged with the sale of the C.W. Mining Company assets, located in Emery and Carbon Counties, Utah (referred to as our Castle Valley mining complex).

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    Because the fair value of the assets acquired exceeded the purchase price, we recorded a non-cash gain of $10.8 million that is reflected in our 2010 financial results. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy. Management believes that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors' understanding of how management assesses the performance of our business. Management believes the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, management believes the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results

(c)
In 2008, we attempted an initial public offering, which was not consummated. We recorded the related deferred costs as a selling, general and administrative expense in August of that year.

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

        For ease and comparability purposes in comparing 2011 to 2010 results and 2010 to 2009 results, the results of Rhino Resource Partners LP and Rhino Energy LLC for 2010 have been combined as if Rhino Resource Partners LP was in existence for the entirety of 2010. Since Rhino Resource Partners LP maintained the historical basis of the Rhino Predecessor's net assets, management believes that the combined Rhino Resource Partners LP and Rhino Predecessor results for 2011 are comparable with 2010, as well as 2010 to 2009. The following discussion of the historical financial condition and results of operations should be read in conjunction with the historical financial statements and accompanying notes included elsewhere in this report.

        In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. See "Cautionary Note Regarding Forward- Looking Statements." Factors that could cause actual results to differ include those risks and uncertainties discussed in Part I, Item 1A. "Risk Factors."

Overview

        We are a growth oriented Delaware limited partnership formed to control and operate coal properties and invest in other natural resource assets. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition to operating coal properties, we manage and lease coal properties and collect royalties from those management and leasing activities. In addition to our coal operations, we have invested in oil and gas mineral rights that we expect to generate royalty revenues in future periods.

        We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2011, we controlled an estimated 437.0 million tons of proven and probable coal reserves, consisting of an estimated 415.6 million tons of steam coal and an estimated 21.4 million tons of metallurgical coal. In addition, as of December 31, 2011, we controlled an estimated 417.1 million tons of non-reserve coal deposits. As of December 31, 2011, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 43.4 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 17.9 million tons of non-reserve coal deposits. As of December 31, 2011, we operated ten mines, including five underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. In addition, our joint venture operates one underground mine in West Virginia. During 2010, we operated one underground mine in Colorado, but we temporarily idled this mine at the end of 2010 and the mine remained idle at the end of 2011. The number of mines that we operate may vary from time to time

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depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

        Our principal business strategy is to safely, efficiently and profitably produce, sell and lease both steam and metallurgical coal from our diverse asset base in order to maintain and, over time, increase our quarterly cash distributions. In addition, we intend to expand our operations through strategic acquisitions, including the acquisition of stable, cash generating natural resource assets. We believe that such assets would allow us to grow our cash available for distribution and enhance stability of our cash flow.

        For the year ended December 31, 2011, we generated revenues of approximately $367.2 million and net income of approximately $38.1 million. Excluding results from the joint venture, for the year ended December 31, 2011, we produced approximately 4.6 million tons of coal, purchased approximately 0.3 million tons of coal and sold approximately 4.9 million tons of coal, approximately 77% of which were pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.3 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2011.

Recent Developments

Acquisitions

Acquisition of The Elk Horn Coal Company, LLC

        In June 2011, we completed the acquisition of 100% of the ownership interests in Elk Horn for approximately $119.7 million in cash consideration. Elk Horn is primarily a coal leasing company located in eastern Kentucky that is expected to provide us with royalty revenues in future periods. We believe there is potential upside from this acquisition to be provided by Elk Horn's currently unleased proven and probable reserves in Southern Floyd County, Kentucky ("Southern Floyd"). We also believe there are additional synergies to this acquisition as a large portion of Elk Horn's property is contiguous with our Deane complex property and the potential addition of infrastructure that would facilitate the increase of Southern Floyd production would also help accelerate development of our contiguous northern Deane complex properties. The Elk Horn acquisition was funded with borrowings available under our credit facility, which were subsequently repaid with proceeds from an offering of our common units.

Acquisition of Oil and Gas Mineral Rights

        During the year ended 2011, we completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. We expect royalty revenues to be generated from these mineral rights in future periods.

        We and an affiliate of Wexford Capital have participated with Gulfport Energy, a publicly traded company, to acquire an interest in a portfolio of oil and gas leases in the Utica Shale. As of February 20, 2012, an affiliate of Wexford Capital owned approximately 13.3% of the common stock of Gulfport Energy. During the year ended 2011, we completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $19.9 million.

Acquisition of Coal Property

        In August 2011, we purchased non-reserve coal deposits at our Sands Hill operation for approximately $2.5 million, which is estimated to include approximately 2.5 million tons.

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        In June 2011, we acquired approximately 32,600 acres and associated surface rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million. These development stage properties are not permitted and contain no infrastructure. We plan to fully explore these properties and intend to prove up additional mineable underground metallurgical coal reserves for future mining.

Acquisition of the C.W. Mining Company

        In August 2010, we acquired certain mining assets of C.W. Mining Company out of bankruptcy (the "Castle Valley Acquisition") for cash consideration of approximately $15.0 million. The assets acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. Production from these assets began at one underground mine in January 2011 and the steam coal produced is being sold into the utility and industrial markets.

Sale of Mining Assets

        In August 2011, we sold and assigned certain non-core mining assets and related liabilities located in the Phelps, Kentucky area of our Tug River mining complex for approximately $20 million. The mining assets included leasehold interests and permits to surface and mineral interests that included steam coal reserves and non-reserve coal deposits. Additionally, the sales agreement includes the potential for additional payments of approximately $8.75 million dependent upon the future issuance of certain permits and the commencement of mining activities by the purchaser. These contingent payments are being accounted for as gain contingencies and will be recognized in the future when and if the contingencies are resolved. The transaction also transferred certain liabilities related to the assets sold that we believe will positively impact future cash flows. Since we had limited mining operations on the assets that were sold, we believe the sale of these assets will not have a negative impact on our future financial results. In relation to the sale of these assets and transfer of liabilities, we recorded a gain of approximately $2.4 million.

        On February 29, 2012, the Partnership completed an agreement to sell certain non-core mining assets located in Pike County Kentucky to a third party for approximately $0.6 million. The transaction also extinguished certain liabilities related to the assets sold.

Lease of Mineral Acres

        On March 6, 2012, we completed a lease agreement with a third party for an estimated 1,500 acres we own in the Utica Shale region of Harrison County Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the third party to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay us the sum of $6,000 per acre as a lease bonus, of which $500,000 was paid at the signing of the lease agreement. The remainder of the lease bonus payment shall be paid by the third party to us within 90 days from the date the lease agreement was signed. In addition, the lease agreement stipulates that the third party shall pay us a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

Initial Public Offering

        On October 5, 2010, we completed our IPO, in which we sold an aggregate of 3,730,600 common units, representing limited partner interests in us, at a price of $20.50 per common unit. Of the common units issued, 486,600 units were issued in connection with the exercise of the underwriters' option to purchase additional units. Net proceeds from the offering were approximately $71.3 million, after deducting underwriting discounts of approximately $5.2 million, of which approximately $62.0 million was received by us and approximately $9.3 million was paid directly to our sponsor, Wexford

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Capital, as reimbursement for capital expenditures incurred by affiliates of Wexford Capital with respect to the assets contributed to us in connection with the offering. We used the net proceeds from this offering, less offering expenses of approximately $3.0 million incurred at the IPO date, and a related capital contribution by our general partner of approximately $10.4 million, to repay approximately $69.4 million of outstanding indebtedness under our credit facility. We paid additional offering expenses after the IPO date of approximately $0.7 million for total offering expenses of approximately $3.7 million.

        In connection with the closing of the IPO, the owners of Rhino Energy LLC contributed their membership interests in Rhino Energy LLC to us, and we issued 12,397,000 subordinated units representing limited partner interests in us and 8,666,400 common units to Rhino Energy Holdings LLC, an affiliate of Wexford Capital, and issued incentive distribution rights to our general partner.

Follow-on Offering

        On July 18, 2011, we completed a public offering of 2,875,000 common units, representing limited partner interests in us, at a price of $24.50 per common unit. Of the common units issued, 375,000 units were issued in connection with the exercise of the underwriters' option to purchase additional units. Net proceeds from the offering were approximately $66.4 million, after deducting underwriting discounts and offering expenses of approximately $4.1 million. We used the net proceeds from this offering, and a related capital contribution by our general partner of approximately $1.4 million, to repay approximately $67.8 million of outstanding indebtedness under our credit facility.

Credit Facility

        The original maximum availability under our credit facility with PNC Bank, N.A. as administrative agent, was $200.0 million. On June 8, 2011, with the consent of the lenders, we exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn acquisition.

        On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million.

Factors That Impact Our Business

        Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems at mining locations, (4) the availability of transportation for coal shipments or (5) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives.

        On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation, (2) the availability and prices of competing electricity-generation fuels, (3) our ability to secure or acquire high-quality coal reserves and (4) our ability to find buyers for coal under favorable supply contracts.

        We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of December 31, 2011, we had commitments under supply contracts to deliver annually scheduled base quantities of 4.5 million, 3.4 million, 2.0 million and 0.3 million tons of coal to 13 customers in 2012, 7 customers in 2013, 5 customers in 2014 and 2 customers in 2015,

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respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Results of Operations

    Segment Information

        We conduct business through four reportable business segments: Central Appalachia, Northern Appalachia, Eastern Met and Rhino Western. Additionally, we have an Other category that includes our ancillary businesses. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which, as of December 31, 2011, together included three underground mines, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, our Central Appalachia segment includes the Elk Horn operations. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex, the Leesville field and the Springdale field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of December 31, 2011. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2011. The Eastern Met segment includes our 51% equity interest in the results of operations of the joint venture, which owns the Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. As of December 31, 2011, this complex was comprised of two underground mines and a preparation plant and loadout facility (owned by our joint venture partner). Our Rhino Western segment includes our two underground mines in the Western Bituminous region that consist of our McClane Canyon mine in Colorado that has been temporarily idled since the end of 2010, and remained idle at the end of 2011, and our Castle Valley mining complex in Utah that began production in January 2011. Our Other category includes our ancillary businesses that consist of a roof bolt manufacturing operation, limestone operations and various businesses that provide support services such as reclamation, maintenance and transportation, the cost of which is reflected in our cost of operations.

    Evaluating Our Results of Operations

        Our management uses a variety of financial measurements to analyze our performance, including (1) Adjusted EBITDA, (2) coal revenues per ton and (3) cost of operations per ton.

        Adjusted EBITDA.    The discussion of our results of operations below includes references to, and analysis of, our segments' Adjusted EBITDA results. Adjusted EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization, including our proportionate share of these expense items from our Rhino Eastern LLC joint venture, while also excluding certain non-recurring items. Adjusted EBITDA is used by management primarily as a measure of our segments' operating performance. Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read "—Reconciliation of Adjusted EBITDA to Net Income by Segment" for reconciliations of Adjusted EBITDA to net income by segment for each of the periods indicated.

        Coal Revenues Per Ton.    Coal revenues per ton represents coal revenues divided by tons of coal sold. Coal revenues per ton is a key indicator of our effectiveness in obtaining favorable prices for our product.

        Cost of Operations Per Ton.    Cost of operations per ton sold represents the cost of operations (exclusive of DD&A) divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency of operations.

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Summary

        The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for years ended December 31, 2011, 2010 and 2009:

 
  Year Ended December 31,  
 
  2011   2010   2009  
 
  (in millions)
 

Statement of Operations Data:

                   

Total revenues

  $ 367.2   $ 305.6   $ 419.8  

Costs and expenses:

                   

Cost of operations (exclusive of DD&A shown separately below)

    267.2     220.8     336.3  

Freight and handling costs

    4.3     2.6     4.0  

DD&A

    36.3     34.1     36.3  

Selling, general and administrative (exclusive of DD&A shown separately above)

    21.8     16.4     16.8  

Asset impairment loss

        0.7      

(Gain) loss on sale/acquisition of assets

    (3.2 )   (10.7 )   1.7  
               

Income from operations

    40.8     41.7     24.7  

Interest and other income (expense):

                   

Interest expense and other

    (6.1 )   (5.3 )   (6.2 )

Interest income and other

    0.1         0.1  

Equity in net income of unconsolidated affiliate

    3.3     4.7     0.9  
               

Total interest and other income (expense)

    (2.7 )   (0.6 )   (5.2 )
               

Net income

  $ 38.1   $ 41.1   $ 19.5  
               

Other Financial Data

                   

Adjusted EBITDA

  $ 82.0   $ 71.5   $ 63.6  
               

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

        Summary.    For the year ended December 31, 2011, our total revenues increased to $367.2 million from $305.6 million for the year ended December 31, 2010. We sold 4.9 million tons of coal for the year ended December 31, 2011, which is 0.6 million more tons, or a 13.2% increase, than the 4.3 million tons of coal sold for the year ended December 31, 2010. The increase in tons sold was primarily the result of starting production at our Castle Valley operation in Utah.

        For the year ended December 31, 2011, our tons of coal inventories were relatively unchanged from the year ended December 31, 2010.

        Net income was $38.1 million for the year ended December 31, 2011compared to $41.1 million (or $30.3 million excluding a $10.8 million gain from the Castle Valley acquisition) for year ended December 31, 2010. Excluding the Castle Valley gain, net income increased in 2011 due to an increase in revenue from higher tons sold, partially offset by higher cost of operations, primarily in our Central Appalachia segment. Adjusted EBITDA increased to $82.0 million for the year ended December 31, 2011, from $71.5 million for the year ended December 31, 2010. The increase in Adjusted EBITDA was primarily due to an increase in net income, excluding the $10.8 million gain from the Castle Valley acquisition in 2010, along with higher DD&A and interest expense.

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        Tons Sold.    The following table presents tons of coal sold by reportable segment for the years ended December 31, 2011 and 2010:

Segment
  Year
Ended
December 31,
2011
  Year
Ended
December 31,
2010
  Increase
(Decrease)
Tons
  %*  
 
  (in millions, except %)
 

Central Appalachia

    2.3     2.2     0.1     7.0 %

Northern Appalachia

    2.1     1.9     0.2     5.9 %

Rhino Western

    0.5     0.2     0.3     150.6 %
                   

Total*†

    4.9     4.3     0.6     13.2 %
                   

*
Calculated percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts presented in this table.

Excludes tons sold by the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

        We sold 4.9 million tons of coal in the year ended December 31, 2011 as compared to 4.3 million tons sold for the year ended December 31, 2010. This increase in tons sold was primarily due to the start of production at our Castle Valley operation in Utah, partially offset by the idling of our McClane Canyon mine in Colorado. Tons of coal sold in our Central Appalachia segment increased by 0.1 million, or 7.0%, to 2.3 million tons for the year ended December 31, 2011 from 2.2 million tons for the year ended December 31, 2010. For our Northern Appalachia segment, tons of coal sold increased by 0.2 million, or 5.9%, to 2.1 million tons for the year ended December 31, 2011 from 1.9 million tons for the year ended December 31, 2010. Coal sales from our Rhino Western segment increased by 0.3 million, or 150.6%, to 0.5 million tons for the year ended December 31, 2011 from 0.2 million tons for the year ended December 31, 2010.

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        Revenues.    The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2011 and 2010:

 
   
   
  Increase/
(Decrease)
 
 
  Year
ended
December 31,
2011
  Year
ended
December 31,
2010
 
Segment
  $   %*  
 
  (in millions, except per ton data and %)
 

Central Appalachia

                         

Coal revenues

  $ 202.9   $ 194.9   $ 8.0     4.1 %

Freight and handling revenues

                n/a  

Other revenues

    16.3     0.7     15.6     2127.9 %
                     

Total revenues

  $ 219.2   $ 195.6   $ 23.6     12.1 %
                     

Coal revenues per ton*

  $ 87.92   $ 90.30   $ (2.38 )   (2.6 )%

Northern Appalachia

                         

Coal revenues

  $ 109.3   $ 86.2   $ 23.1     26.8 %

Freight and handling revenues

    5.7     4.2     1.5     37.8 %

Other revenues

    5.0     5.0         (2.0 )%
                     

Total revenues

  $ 120.0   $ 95.4   $ 24.6     25.7 %
                     

Coal revenues per ton*

  $ 53.00   $ 44.30   $ 8.70     19.6 %

Rhino Western

                         

Coal revenues

  $ 21.7   $ 8.8   $ 12.9     145.5 %

Freight and handling revenues

                n/a  

Other revenues

                22.2 %
                     

Total revenues

  $ 21.7   $ 8.8   $ 12.9     145.4 %
                     

Coal revenues per ton*

  $ 42.78   $ 43.67   $ (0.89 )   (2.0 )%

Other

                         

Coal revenues

    n/a     n/a     n/a     n/a  

Freight and handling revenues

    n/a     n/a     n/a     n/a  

Other revenues

  $ 6.3   $ 5.8   $ 0.5     8.6 %
                     

Total revenues

  $ 6.3   $ 5.8   $ 0.5     8.6 %
                     

Coal revenues per ton*

    n/a     n/a     n/a     n/a  

Total

                         

Coal revenues

  $ 333.9   $ 289.9   $ 44.0     15.2 %

Freight and handling revenues

    5.7     4.2     1.5     37.8 %

Other revenues

    27.6     11.5     16.1     138.1 %
                     

Total revenues

  $ 367.2   $ 305.6   $ 61.6     20.1 %
                     

Coal revenues per ton*

  $ 68.47   $ 67.32   $ 1.15     1.7 %

*
Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

        Our total revenues for the year ended December 31, 2011 increased by $61.6 million, or 20.1%, to $367.2 million from $305.6 million for the year ended December 31, 2010. The increase in coal revenues was due to increased volume in tons sold as well as higher contracted and spot prices for our steam coal. Coal revenues per ton were $68.47 for the year ended December 31, 2011, an increase of $1.15, or 1.7%, from $67.32 per ton for the year ended December 31, 2010. This increase in coal revenues per ton was primarily the result of higher contracted and spot prices for steam coal, partially offset by a lower mix of tons sold of metallurgical coal in 2011.

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        For our Central Appalachia segment, coal revenues increased by $8.0 million, or 4.1%, to $202.9 million for the year ended December 31, 2011 from $194.9 million for the year ended December 31, 2010 due to increased volume in tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $2.38, or 2.6%, to $87.92 per ton for the year ended December 31, 2011 as compared to $90.30 for the year ended December 31, 2010, primarily due to fewer tons of metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to coal royalty revenue from Elk Horn.

        For our Northern Appalachia segment, coal revenues were $109.3 million for the year ended December 31, 2011, an increase of $23.1 million, or 26.8%, from $86.2 million for the year ended December 31, 2010, primarily as a result of higher contracted and spot prices for steam coal. Coal revenues per ton for our Northern Appalachia segment increased by $8.70, or 19.6%, to $53.00 per ton for the year ended December 31, 2011 as compared to $44.30 per ton for the year ended December 31, 2010. This increase was primarily due to higher contracted and spot prices for steam coal.

        For our Rhino Western segment, coal revenues increased by $12.9 million, or 145.5%, to $21.7 million for the year ended December 31, 2011 from $8.8 million for the year ended December 31, 2010 due to the start of production at our Castle Valley operation. Coal revenues per ton for our Rhino Western segment were $42.78 for the year ended December 31, 2011, a decrease of $0.89, or 2.0%, from $43.67 for the year ended December 31, 2010. The decrease in coal revenues per ton was due to lower market prices for coal produced at our Castle Valley mine compared to coal sold from our McClane Canyon mine in 2010.

        Other revenues for our Other category increased by $0.5 million for the year ended December 31, 2011 from the year ended December 31, 2010. This increase was primarily due to an increase in sales from our roof bolt manufacturing operations.

        Central Appalachia Overview of Results by Product.    Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal ("met coal") and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)
  Year
ended
December 31,
2011
  Year
ended
December 31,
2010
  Increase
(Decrease)
%*
 

Met coal tons sold

    654.6     683.4     (4.2 )%

Steam coal tons sold

    1,653.4     1,474.5     12.1 %
               

Total tons sold†

    2,308.0     2,157.9     7.0 %
               

Met coal revenue

  $ 79,227   $ 88,570     (10.5 )%

Steam coal revenue

  $ 123,706   $ 106,281     16.4 %
               

Total coal revenue†

  $ 202,933   $ 194,851     4.1 %
               

Met coal revenues per ton

  $ 121.04   $ 129.59     (6.6 )%

Steam coal revenues per ton

  $ 74.82   $ 72.08     3.8 %
               

Total coal revenues per ton†

  $ 87.92   $ 90.30     (2.6 )%
               

Met coal tons produced

    660.5     700.2     (5.7 )%

Steam coal tons produced

    1,573.5     1,454.3     8.2 %
               

Total tons produced†

    2,234.0     2,154.5     3.7 %
               

*
Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

Excludes data for the Rhino Eastern mining complex located in West Virginia for which we serve as manager.

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        Costs and Expenses.    The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the years ended December 31, 2011 and 2010:

 
   
   
  Increase/(Decrease)  
 
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 
Segment
  $   %*  
 
  (in millions, except per ton data and %)
 

Central Appalachia

                         

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

  $ 154.2   $ 133.5   $ 20.7     15.5 %

Freight and handling costs

                n/a  

Depreciation, depletion and amortization

    22.1     20.1     2.0     10.1 %

Selling, general and administrative

    20.2     15.3     4.9     32.0 %

Cost of operations per ton*

  $ 66.79   $ 61.87   $ 4.92     7.9 %

Northern Appalachia

                         

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

  $ 75.1   $ 65.1   $ 10.0     15.5 %

Freight and handling costs

    4.3     3.1     1.2     39.1 %

Depreciation, depletion and amortization

    8.1     9.3     (1.2 )   (12.7 )%

Selling, general and administrative

    0.4     0.3     0.1     2.5 %

Cost of operations per ton*

  $ 36.45   $ 33.43   $ 3.02     9.0 %

Rhino Western

                         

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

  $ 17.9   $ 6.9   $ 11.0     159.5 %

Freight and handling costs

                n/a  

Depreciation, depletion and amortization

    3.1     0.6     2.5     414.6 %

Selling, general and administrative

    0.1     0.1         17.2 %

Cost of operations per ton*

  $ 35.42   $ 34.20   $ 1.22     3.6 %

Other

                         

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

  $ 20.0   $ 15.3   $ 4.7     30.7 %

Freight and handling costs

        (0.5 )   0.5     n/a  

Depreciation, depletion and amortization

    3.0     4.1     (1.1 )   (26.7 )%

Selling, general and administrative

    1.1     0.7     0.4     64.2 %

Cost of operations per ton**

    n/a     n/a     n/a     n/a  

Total

                         

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

  $ 267.2   $ 220.8   $ 46.4     21.0 %

Freight and handling costs

    4.3     2.6     1.7     64.3 %

Depreciation, depletion and amortization

    36.3     34.1     2.2     6.5 %

Selling, general and administrative

    21.8     16.4     5.4     32.6 %

Cost of operations per ton*

  $ 54.79   $ 51.27   $ 3.52     6.9 %

*
Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

**
Cost of operations presented for our Other category includes costs incurred by our ancillary businesses. The activities performed by these ancillary businesses do not directly relate to coal production. As a result, per ton measurements are not presented for this category.

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        Cost of Operations.    Total cost of operations was $267.2 million for the year ended December 31, 2011 as compared to $220.8 million for the year ended December 31, 2010. Our cost of operations per ton was $54.79 for the year ended December 31, 2011, an increase of $3.52, or 6.9%, from the year ended December 31, 2010. These overall increases in the cost of operations and cost of operations on a per ton basis were due to increased costs in our Rhino Western segment due to preparing our Castle Valley mine to begin production early in 2011 along with costs associated with temporarily idling our McClane Canyon mine. In addition, we experienced higher costs in our Central Appalachia operations due to an increased number of regulatory actions at Mine 28 in our Rob Fork mining complex along with increased transportation and maintenance costs from our Grapevine surface mine located in the Tug River complex. In our Northern Appalachia segment, we also experienced increased roof support costs at our Hopedale mine. Cost of operations also increased across all of the operating segments due to higher fuel prices.

        Our cost of operations for the Central Appalachia segment increased by $20.7 million, or 15.5%, to $154.2 million for the year ended December 31, 2011 from $133.5 million for the year ended December 31, 2010. Our cost of operations per ton increased to $66.79 per ton for the year ended December 31, 2011 from $61.87 per ton for year ended December 31, 2010. The increases in cost of operations and costs of operations per ton were primarily due to an increased number of regulatory actions at Mine 28 located in the Rob Fork mining complex along with increased transportation and maintenance costs from the Grapevine surface mine located in the Tug River complex.

        In our Northern Appalachia segment, our cost of operations increased by $10.0 million, or 15.5%, to $75.1 million for the year ended December 31, 2011 from $65.1 million for the year ended December 31, 2010. Our cost of operations per ton increased to $36.45 for the year ended December 31, 2011 from $33.43 for the year ended December 31, 2010, an increase of $3.02 per ton, or 9.0%. The increases in cost of operations and costs of operations per ton were primarily due to increased commodity prices driven by higher fuel costs as well as roof control and methane issues encountered at our Hopedale underground mine.

        Cost of operations in our Rhino Western segment increased by $11.0 million, or 159.5%, to $17.9 million for the year ended December 31, 2011 from $6.9 million for the year ended December 31, 2010. Our cost of operations per ton increased to $35.42 for the year ended December 31, 2011 from $34.20 for the year ended December 31, 2010, an increase of $1.22 per ton, or 3.6%. These increases in cost of operations and cost of operations per ton were primarily due to increased costs associated with preparing our Castle Valley mine to begin production early in 2011 along with costs associated with temporarily idling our McClane Canyon mine.

        Cost of operations in our Other category increased by $4.7 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. This increase was primarily due to an increase in amounts spent for professional fees and outside services.

        Freight and Handling.    Total freight and handling cost for the year ended December 31, 2011 increased by $1.7 million, or 64.3%, to $4.3 million from $2.6 million for the year ended December 31, 2010. This increase was primarily due to a 0.6 million increase in the number of tons sold for the year ended December 31, 2011 as compared to the year ended December 31, 2010, along with higher fuel prices.

        Depreciation, Depletion and Amortization.    Total DD&A expense for the year ended December 31, 2011 was $36.3 million as compared to $34.1 million for the year ended December 31, 2010.

        For the year ended December 31, 2011, our depreciation cost was $26.5 million as compared to $26.8 million for the year ended December 31, 2010. The decrease in depreciation cost in 2011 was primarily due to the disposal and idling of assets at certain less profitable surface mining operations.

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        For the year ended December 31, 2011, our depletion cost was $5.1 million as compared to $1.8 million for the year ended December 31, 2010. The increase in depletion cost in 2011 was primarily due to depletion cost incurred as a result of coal produced by lessees of our Elk Horn properties that was not included in our results in 2010, along with an increase in tons of coal produced at our other mining operations in 2011 when compared to 2010.

        For the year ended December 31, 2011, our amortization cost was $4.7 million as compared to $5.5 million for the year ended December 31, 2010. This decrease is primarily attributable to changes in the amortization for both mine development costs and asset retirement costs based on revisions to reserve valuations and useful lives.

        Selling, General and Administrative.    Selling, general and administrative ("SG&A") expense for the year ended December 31, 2011 was $21.8 million as compared to $16.4 million for the year ended December 31, 2010. The increase in SG&A expense is primarily attributable to the costs associated with being a publicly traded partnership, including an increase in expenditures for legal fees and other professional fees.

        Interest Expense.    Interest expense for the year ended December 31, 2011 was $6.1 million as compared to $5.3 million for the year ended December 31, 2010, an increase of $0.8 million, or 13.6%. This increase was the result of an increase in the balance outstanding under our credit facility, primarily resulting from the acquisition of Elk Horn.

        Eastern Met Supplemental Data.    Operational and financial data for the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager (referred to as the "Eastern Met" segment) is presented below. Our consolidated revenue and costs do not include any portion of the revenue or costs of Rhino Eastern since we account for this operation under the equity method. We only record our proportionate share of net income of Rhino Eastern as a single item in our financial statements, but we believe the presentation of these items for Rhino Eastern provides additional insight into how this operation contributes to our overall performance.

(In thousands, except per ton data and %)
  Year ended
December 31,
2011
  Year ended
December 31,
2010
  Increase
(Decrease)
%*
 

Eastern Met 100% Basis

                   

Coal revenues

  $ 49,999   $ 40,028     24.9 %

Total revenues

  $ 50,073   $ 40,094     24.9 %

Coal revenues per ton*

  $ 198.97   $ 158.74     25.3 %

Cost of operations

  $ 37,582   $ 25,153     49.4 %

Cost of operations per ton*

  $ 149.55   $ 99.75     49.9 %

Depreciation, depletion and amortization

  $ 2,959   $ 3,196     (7.4 )%

Interest expense

  $ 52   $ 72     (28.1 )%

Net income

  $ 6,545   $ 8,946     (26.8 )%

Partnership's portion of net income

  $ 3,338   $ 4,699     (26.8 )%

Tons produced

    266.2     258.6     3.0 %

Tons sold

    251.3     252.2     (0.3 )%

*
Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

        Rhino Eastern's Eagle #1 mine was removed from the potential pattern of violation list in March 2011 by MSHA. However, beginning on March 18, 2011, MSHA issued two orders requiring this mine to be idled until water located in previous mine works above the mine was removed. Rhino Eastern lost production at this mine for approximately three weeks while this water was removed. Additionally,

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on June 27, 2011, a fatality occurred at Rhino Eastern's Eagle #1 mine due to a rib fall that tragically killed one miner. Production was idled at this mine while we and MSHA investigated the events surrounding this accident. Production resumed at Rhino Eastern's Eagle #1 mine in July once the investigations were completed. On August 25, 2011, Rhino Eastern again received an MSHA notification of a potential pattern of violations based on MSHA's continued monitoring of the Eagle #1 Mine for long-term compliance after the evaluation period that ended in March 2011. Rhino Eastern developed a corrective action program in an effort to avoid a final finding of a pattern of violations and the imposition of sanctions. On January 19, 2012, MSHA notified Rhino Eastern that MSHA had determined not to consider Eagle #1 Mine for a pattern of violations. Despite the interruptions from the activities listed above, tons produced for the year ended December 31, 2011 increased slightly compared to the year ended December 31, 2010 while tons sold was relatively flat. Revenue increased year-to-year due to favorable pricing for coal sold in 2011, but net income decreased due to higher cost of operations, primarily from increased labor costs.

        Net Income (Loss).    The following table presents net income (loss) by reportable segment for the years ended December 31, 2011 and 2010:

Segment
  Year ended
December 31,
2011
  Year ended
December 31,
2010
  Increase
(Decrease)
 
 
  (in millions)
 

Central Appalachia

  $ 19.2   $ 20.6   $ (1.4 )

Northern Appalachia

    23.0     10.1     12.9  

Rhino Western*

    (2.8 )   11.2     (14.0 )

Eastern Met**

    3.3     4.7     (1.4 )

Other

    (4.6 )   (5.5 )   0.9  
               

Total

  $ 38.1   $ 41.1   $ (3.0 )
               

*
During the third quarter of 2010, we acquired certain assets for cash consideration of approximately $15.0 million from the Trustee of the Federal Bankruptcy Court charged with the sale of the C.W. Mining Company assets, located in Emery and Carbon Counties, Utah (referred to as our Castle Valley mining complex). Because the fair value of the assets acquired exceeded the purchase price, we recorded a non-cash gain of $10.8 million that is reflected in our 2010 financial results for Rhino Western. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy.

**
Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

        For the year ended December 31, 2011, total net income was $38.1 million compared to $41.1 million (or $30.3 million excluding the $10.8 million gain from the Castle Valley acquisition) for the year ended December 31, 2010. Excluding the Castle Valley gain from 2010 net income, net income increased in 2011 due to an increase in revenue from higher tons sold, partially offset by higher cost of operations, primarily in our Central Appalachia segment. For our Central Appalachia segment, net income decreased to $19.2 million for the year ended December 31, 2011, a decrease of $1.4 million, as compared to the year ended December 31, 2010. This decrease was primarily due to lower amounts of metallurgical coal sold and an increase in costs of operations, partially offset by coal royalty income generated from our Elk Horn operation. Net income in our Northern Appalachia segment increased by $12.9 million to $23.0 million for the year ended December 31, 2011, from $10.1 million for the year ended December 31, 2010. This increase was primarily the result of an increase in sales. Net income in our Rhino Western segment decreased by $14.0 million to a loss of $2.8 million for the year ended December 31, 2011, compared to income of $11.2 million for the year ended December 31, 2010. This

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decrease was primarily the result of the $10.8 million Castle Valley gain in 2010 along with an increase in costs associated with preparing our Castle Valley operation to begin production in early 2011. Our Eastern Met segment recorded net income of $3.3 million for the year ended December 31, 2011, a decrease of $1.4 million from $4.7 million recorded for the year ended December 31, 2010. For the Other category, we had a net loss of $4.6 million for the year ended December 31, 2011, a reduction of $0.9 million as compared to a net loss of $5.5 million for the year ended December 31, 2010. This decrease in the loss from year to year was primarily due to an asset impairment charge recorded for certain assets in two of our ancillary businesses in 2010, partially offset by an increase in costs of operations in 2011.

        Adjusted EBITDA.    The following table presents Adjusted EBITDA by reportable segment for the years ended December 31, 2011 and 2010:

Segment
  Year ended
December 31,
2011
  Year ended
December 31,
2010
  Increase
(Decrease)
 
 
  (in millions)
 

Central Appalachia

  $ 43.6   $ 43.0   $ 0.6  

Northern Appalachia

    33.2     21.4     11.8  

Rhino Western

    0.8     1.2     (0.4 )

Eastern Met*

    4.9     6.4     (1.5 )

Other

    (0.5 )   (0.5 )    
               

Total Adjusted EBITDA

  $ 82.0   $ 71.5   $ 10.5  
               

*
Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

        Total Adjusted EBITDA for the year ended December 31, 2011 was $82.0 million, an increase of $10.5 million from $71.5 million for the year ended December 31, 2010, primarily due to an increase in net income, excluding the $10.8 million gain from the Castle Valley acquisition in 2010, along with higher DD&A and interest expense. Please read "—Reconciliation of Adjusted EBITDA to Net Income by Segment" for reconciliations of Adjusted EBITDA to net income on a segment basis.

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

        Summary.    In the early part of 2009, we experienced eroding margins at certain operations in our Central Appalachia segment due to increased cost of operations when compared to committed sales prices. We made a strategic decision at that time to reduce production at those mines and purchase coal on the open market at prices that allowed us to sustain acceptable margins on these sales.

        For the year ended December 31, 2010, our total revenues decreased to $305.6 million from $419.8 million for the year ended December 31, 2009. We sold 4.3 million tons of coal for the year ended year ended December 31, 2010, which is 2.4 million fewer tons, or 35.7% less, than the 6.7 million tons of coal sold for the year ended December 31, 2009. These decreases were the result of a strategic decision made in 2010 to only sell tons that were contracted at acceptable margins based on current market conditions and increased cost of operations.

        For the year ended December 31, 2010, we increased our coal inventories by approximately 0.9 million tons while our coal inventories were approximately unchanged for the year ended December 31, 2009.

        Despite the decrease in the volume of tons sold, both net income and Adjusted EBITDA increased for the year ended December 31, 2010 from the year ended December 31, 2009. Net income increased to $41.1 million for year ended December 31, 2010 from $19.5 million for the year ended

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December 31, 2009. Adjusted EBITDA increased to $71.5 million for the year ended December 31, 2010, from $63.6 million for the year ended December 31, 2009. The increases in net income and Adjusted EBITDA were primarily due to increased revenue on a per ton basis and a reduction in the amount of coal purchased, offset by higher costs of operations in our Central Appalachia segment. Net income in 2010 also benefited by a $10.8 million gain recognized on the Castle Valley Acquisition.

        Tons Sold.    The following table presents tons of coal sold by reportable segment for the years ended December 31, 2010 and 2009:

Segment
  Year Ended
December 31,
2010
  Year Ended
December 31,
2009
  Increase
(Decrease)
Tons
  %*  
 
  (in millions, except %)
 

Central Appalachia

    2.2     4.2     (2.0 )   (49.5 )%

Northern Appalachia

    1.9     2.2     (0.3 )   (10.0 )%

Rhino Western

    0.2     0.3     (0.1 )   (23.6 )%
                   

Total*†

    4.3     6.7     (2.4 )   (35.7 )%
                   

*
Calculated percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts presented in this table.

Excludes tons sold by the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

        We sold 4.3 million tons of coal in the year ended December 31, 2010 as compared to 6.7 million tons sold for the year ended December 31, 2009. This decrease in tons sold was primarily due to management decisions made to match cost of operations with supply contracts that provided acceptable margins in our Central Appalachia segment. Tons of coal sold in our Central Appalachia segment decreased by 2.0 million, or 49.5%, to 2.2 million tons for the year ended December 31, 2010 from 4.2 million tons for the year ended December 31, 2009. For our Northern Appalachia segment, tons of coal sold decreased by 0.3 million, or 10.0%, to 1.9 million tons for the year ended December 31, 2010 from 2.2 million tons for the year ended December 31, 2009. Coal sales from our Rhino Western segment decreased by 0.1 million, or 23.6%, to 0.2 million tons for the year ended December 31, 2010 from 0.3 million tons for the year ended December 31, 2009.

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        Revenues.    The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2010 and 2009:

 
   
   
  Increase/
(Decrease)
 
 
  Year ended
December 31, 2010
  Year ended
December 31, 2009
 
Segment
  $   %*  
 
  (in millions, except per ton data and %)
 

Central Appalachia

                         

Coal revenues

  $ 194.9   $ 295.1   $ (100.2 )   (34.0 )%

Freight and handling revenues

                n/a  

Other revenues

    0.7     2.6     (1.9 )   (72.0 )%
                     

Total revenues

  $ 195.6   $ 297.7   $ (102.1 )   (34.3 )%
                     

Coal revenues per ton*

  $ 90.30   $ 69.10   $ 21.20     30.7 %

Northern Appalachia

                         

Coal revenues

  $ 86.2   $ 95.5   $ (9.3 )   (9.7 )%

Freight and handling revenues

    4.2     5.0     (0.8 )   (17.4 )%

Other revenues

    5.0     6.2     (1.2 )   (19.1 )%
                     

Total revenues

  $ 95.4   $ 106.7   $ (11.3 )   (10.6 )%
                     

Coal revenues per ton*

  $ 44.30   $ 44.12   $ 0.18     0.4 %

Rhino Western

                         

Coal revenues

  $ 8.8   $ 11.2   $ (2.4 )   (21.2 )%

Freight and handling revenues

                n/a  

Other revenues

                12.3 %
                     

Total revenues

  $ 8.8   $ 11.2   $ (2.4 )   (21.1 )%
                     

Coal revenues per ton*

  $ 43.67   $ 42.35   $ 1.32     3.1 %

Other

                         

Coal revenues

    n/a     n/a     n/a     n/a  

Freight and handling revenues

    n/a     n/a     n/a     n/a  

Other revenues

  $ 5.8   $ 4.2   $ 1.6     40.7 %
                     

Total revenues

  $ 5.8   $ 4.2   $ 1.6     40.7 %
                     

Coal revenues per ton*

    n/a     n/a     n/a     n/a  

Total

                         

Coal revenues

  $ 289.9   $ 401.8   $ (111.9 )   (27.8 )%

Freight and handling revenues

    4.2     5.0     (0.8 )   (17.4 )%

Other revenues

    11.5     13.0     (1.5 )   (10.8 )%
                     

Total revenues

  $ 305.6   $ 419.8   $ (114.2 )   (27.2 )%
                     

Coal revenues per ton*

  $ 67.32   $ 59.98   $ 7.34     12.2 %

*
Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

        Our total revenues for the year ended December 31, 2010 decreased by $114.2 million, or 27.2%, to $305.6 million from $419.8 million for the year ended December 31, 2009. The decrease in total revenues was due to the strategic decision to sell only tons that provided an acceptable margin as discussed earlier. Coal revenues per ton were $67.32 for the year ended December 31, 2010, an increase of $7.34, or 12.2%, from $59.98 per ton for the year ended December 31, 2009. This increase

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in coal revenues per ton was primarily the result of the sale of a higher percentage of metallurgical coal being sold and higher contracted prices for the steam coal.

        For our Central Appalachia segment, coal revenues decreased by $100.2 million, or 34.0%, to $194.9 million for the year ended December 31, 2010 from $295.1 million for the year ended December 31, 2009 due to strategic decisions made to match cost of operations with coal supply contracts that provided acceptable margins. Coal revenues per ton for our Central Appalachia segment increased by $21.20, or 30.7%, to $90.30 per ton for the year ended December 31, 2010 as compared to $69.10 for the year ended December 31, 2009, due to a higher percentage of metallurgical coal being sold and higher contracted prices for the steam coal.

        For our Northern Appalachia segment, coal revenues were $86.2 million for the year ended December 31, 2010, a decrease of $9.3 million, or 9.7%, from $95.5 million for the year ended December 31, 2009, due to market conditions. Coal revenues per ton for our Northern Appalachia segment increased by $0.18, or 0.4%, to $44.30 per ton for the year ended December 31, 2010 as compared to $44.12 per ton for the year ended December 31, 2009. This increase was primarily due to higher contracted prices on our supply contracts.

        For our Rhino Western segment, coal revenues decreased by $2.4 million, or 21.2%, to $8.8 million for the year ended December 31, 2010 from $11.2 million for the year ended December 31, 2009. Coal revenues per ton for our Rhino Western segment were $43.67 for the year ended December 31, 2010, an increase of $1.32, or 3.1%, from $42.35 for the year ended December 31, 2009 due to a contracted increase in the selling price to our customer for coal produced at our McClane Canyon mine.

        Other revenues for our Other category increased by $1.6 million for the year ended December 31, 2010 from the year ended December 31, 2009. This increase was primarily due to an increase in sales from our roof bolt manufacturing operations of $1.5 million.

        Central Appalachia Overview of Results by Product.    Additional information for the Central Appalachia segment detailing the types of coal produced and sold, met coal and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)
  Year
ended
December 31,
2010
  Year
ended
December 31,
2009
  Increase
(Decrease)
%*
 

Met coal tons sold

    683.4     353.7     93.2 %