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

Form 10-K

Commission file number: 001-34892

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

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

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

         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 o    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. ý

         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.

         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, 2010, the last business day of the registrant's most recently completed second fiscal quarter, the registrant's equity was not listed on any domestic exchange or over-the-counter market. The registrant's common units began trading on the New York Stock Exchange on September 30, 2010. As of March 14, 2011, the registrant had 12,406,760 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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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 appearance, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations. 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 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 in a historical context refer to Rhino Energy LLC and its subsidiaries, which were contributed to Rhino Resource Partners LP in connection with its initial public offering, which was completed on October 5, 2010 (the "IPO"). When used in the present tense or prospectively, those 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 related 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.

        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, 2010, we controlled an estimated 309.0 million tons of proven and probable coal reserves, consisting of an estimated 297.0 million tons of steam coal and an estimated 12.0 million tons of metallurgical coal. In addition, as of December 31, 2010, we controlled an estimated 271.8 million tons of non-reserve coal deposits. As of December 31, 2010, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and for which we serve as manager, controlled an estimated 22.2 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 34.3 million tons of non-reserve coal deposits. As of December 31, 2010, we operated ten mines, including five underground and five surface mines, located in Kentucky, Ohio and West Virginia. 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 due to the expiration of our sole customer contract at this location. We are currently planning to restart production at this location in late 2011. Additionally, we began production and customer shipments in January 2011 at one underground mine located in Emery and Carbon Counties in Utah that we had acquired out of bankruptcy in August of 2010. 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, 2010, we produced approximately 4.0 million tons of coal, purchased approximately 0.3 million tons of coal and sold approximately 4.3 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, 2010.

        Our principal business strategy is to safely, efficiently and profitably produce and sell 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 non-coal 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 by, for example, serving as a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel, steel products and other commodities consumed in the mining process.

History

        Our predecessor was formed in April 2003 by Wexford Capital LP ("Wexford Capital", and together with 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 $6.0 billion of assets under management. Since the formation of our predecessor, we have significantly grown our

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coal reserves. Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $223.3 million, including our acquisition in August 2010 of certain mining assets of C.W. Mining Company out of bankruptcy. The assets acquired in August 2010 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. 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.

        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 an affiliate of Wexford Capital and issued incentive distribution rights to our general partner. Principals of Wexford, including certain directors of our general partner, own the majority of the membership interests in our general partner.

        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 Operations

        As of December 31, 2010, 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")) and two mining complexes located in Northern Appalachia (Hopedale and Sands Hill). During 2010, we operated one mine located in the Western Bituminous region in Colorado (McClane Canyon). The McClane Canyon mine was temporarily idled at year end due to the expiration of our sole customer contract at this location. With production temporarily idled, we are in the process of building and permitting a rail loadout at this location and we are currently planning to restart production at the McClane Canyon mine in late 2011. 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. We began production from these assets at one underground mine in January 2011.

        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 underground mines. All of the preparation plants are modern plants that have both coarse and fine coal cleaning circuits.

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        The following map shows the location of our mining operations as of December 31, 2010:

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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, 2010:

        Central Appalachia.    As of December 31, 2010, 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, 2010, the mines at our Tug River, Rob Fork and Deane mining complexes produced an aggregate of approximately 1.2 million tons of steam coal and an estimated 0.7 million tons of metallurgical coal, and the underground mine at the Rhino Eastern mining 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.

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        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 0.2 million tons of steam coal for the year ended December 31, 2010.

        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 two company-operated underground mines. 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 0.6 million tons of steam coal and 0.7 million tons of metallurgical coal for the year ended December 31, 2010.

        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 0.4 million tons of steam coal for the year ended December 31, 2010.

        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 produces premium metallurgical coal from one company-operated underground mine. The joint venture acquired the Rhino Eastern complex in May 2008 and commenced production in August 2008. 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, 2010.

        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, 2010, these mines produced an aggregate of approximately 2.0 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 the customer. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 1.4 million tons of steam coal for the year ended December 31, 2010.

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        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 0.6 million tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2010.

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

        McClane Canyon Mine.    The McClane Canyon mine is located near Loma, Colorado and is on property leased from the Bureau of Land Management ("BLM"). The mine produced approximately 0.2 million tons of steam coal for the year ended December 31, 2010, all of which was sold to Xcel's Cameo power plant, located east of Grand Junction, Colorado pursuant to a contract with Xcel which expired on December 31, 2010. We have temporarily idled production at the McClane Canyon mine as we build and permit a rail loadout. We believe access to a rail loadout will enable us to expand our customer base. We are currently planning to restart production at the McClane Canyon mine in late 2011.

        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.

        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 from these assets at one underground mine. The coal we produce and sell from these mining assets is sold as steam coal in the Western Bituminous region.

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. We have been able to efficiently supply internally the majority of these services, which were previously outsourced. Through Rhino Services, we plan and monitor each phase of our mining projects as well 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

        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

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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, 2010, approximately 84% of our coal sales tons consisted of steam coal and approximately 16% consisted of metallurgical coal. For the year ended December 31, 2010, 100% of the joint venture's coal sales tons consisted of metallurgical coal. For the year ended December 31, 2010, excluding results from the joint venture, approximately 74% of our coal sales tons that we produced were sold to electric utilities. In addition, for the year ended December 31, 2010, excluding results from the joint venture, approximately 3% of our total coal sales tons were sold through the OTC market, a portion of which were ultimately supplied 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, 2010, we derived approximately 82.5% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 43.0% of our coal revenues for that period: Indiana Harbor Coke Company, L.P., a subsidiary of Sunoco, Inc. (17.7%); GenOn Energy, Inc. (fka Mirant Corporation) (12.9%); and American Electric Power Company, Inc. (12.4%). 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.

Coal Supply Contracts

        For the years ended December 31, 2010 and 2009, approximately 96% and 99%, 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.

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Transportation

        We ship coal to our customers by rail, truck or barge. For the year ended December 31, 2010, 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 customer in Colorado. With the expiration at December 31, 2010 of our sole customer contract in Colorado, we temporarily idled the McClane Canyon mine, and are in the process of permitting a rail loadout at this location. 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 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., International Coal Group, Inc., James River Coal Company, Massey Energy 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.

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Regulation and Laws

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

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employee health and safety;



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mine permits and other licensing requirements;



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air quality standards;



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water quality standards;



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



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plant and wildlife protection;



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reclamation and restoration of mining properties after mining is completed;



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



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storage and handling of explosives;



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wetlands protection;



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surface subsidence from underground mining;



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



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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. 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 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

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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 cannot assure you that we will not 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 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 withdrawal orders. 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. Violations of mandatory health and safety standards that are labeled as "serious" 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.

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        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 incidence rate was 39.3% below the industry average for the year ended December 31, 2010. 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. Our non-fatal days lost time incidence rate for all operations for the year ended December 31, 2010 was 1.53 as compared to the national average of 2.52 through the nine months ended September 30, 2010, as reported by MSHA.

        In addition, for the year ended December 31, 2010 our average MSHA violations per inspection day was 0.70 as compared to the full year 2009 national average of 0.82 violations per inspection day, 14.6% below the 2009 national average.

        In 2006, 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 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 currently in the public hearing and comment phase, 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 introduced an Emergency Temporary Standard in 2010 that required the application and continued maintenance of a significantly increased amount of rock dust throughout underground coal mines.

        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

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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, are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

        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.

        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, 2010 (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 operations on a mine-wide level or otherwise entail material financial or operational consequences for us. We cannot assure you that any suspension of operations at any one of our locations that may occur in the future will not 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 pending. 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 cannot predict the outcome of our challenges or assure you that we will not be assessed significant fines, penalties, or sanctions in the future with respect to alleged instances of non-compliance.

        On November 19, 2010, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and serves as manager, 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, we submitted a Corrective Action Plan to MSHA and this plan became effective on December 31, 2010.

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        On February 4, 2011, CAM Mining LLC ("CAM Mining"), a subsidiary of us, received an imminent danger order under Section 107(a) of the Mine Act which stated that two carpenters in the employ of an independent, third-party contractor were working 10 feet above ground on the roof of a structure at CAM Mining's Mine 28 without tie off lines. The carpenters were immediately instructed to safely climb down to the ground level where they received further safety training. These actions terminated the order.

        We exercise substantial efforts toward achieving compliance at our mines. In light of the recent citations issued with respect to Mine 28 and Eagle #1 Mine, 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 Mine 28 and Eagle #1 Mine.

        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. For instance, we incurred approximately $3.1 million for the eighteen months ended June 30, 2010 in capital expenditures to comply with the requirements of the MINER Act. We project capital expenditures of approximately $2.8 million on compliance with mine safety laws over the next five years. These figures are subject to change, however, as new requirements come into effect.

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 2010, we recorded approximately $3.5 million of expense related to this excise tax.

        On March 23, 2010, President Obama signed into law health care reform legislation, known as the Affordable Health Choices 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 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.

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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 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, 2010, we had accrued approximately $35.7 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 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

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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 advanced 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 intends to propose a series of Stream Protection Rules in 2011 and will finalize those rules in 2012. 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 SBZ 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

        A mine operator must 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, 2010, we had approximately $76.1 million in surety bonds outstanding to secure the performance of our reclamation obligations.

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,

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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 21 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. On July 11, 2008, the United States Court of Appeals for the D.C. Circuit vacated CAIR. The EPA subsequently filed a petition for rehearing or, in the alternative, for a remand of the case without vacatur. On December 23, 2008, the Court issued an opinion to remand without vacating CAIR. Therefore, CAIR will remain in effect while the EPA conducts rulemaking to modify CAIR to comply with the Court's July 2008 opinion. The Court declined to impose a schedule by which the EPA must complete the rulemaking, but reminded the EPA that the Court does "...not intend to grant an indefinite stay of the effectiveness of this Court's decision." The EPA is considering its options on how to proceed.

        In March 2005, EPA finalized the Clean Air Mercury Rule, or CAMR, which established a two-part nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. The CAMR has been the subject of ongoing litigation, and on February 8, 2008, the United States Court of Appeals for the D.C. Circuit vacated the rule for further consideration by the EPA. As a result of the decision to vacate the CAMR, in February 2009 the EPA announced that it would regulate mercury emissions by issuing Maximum Achievable Control Technology standards, or MACT, which are likely to impose stricter limitations on mercury emissions from power plants than the vacated CAMR. The EPA is under a court deadline to issue a final rule requiring MACT for power plants by November 2011. In conjunction with these efforts, on December 24, 2009, EPA approved an Information Collection Request (ICR) requiring all US power plants with coal-or oil-fired electric generating units to submit emissions information for use in developing air toxics emissions standards. The EPA has stated that it intends to propose air toxics standards for coal- and oil-fired electric generating units by March 10, 2011. In addition, on April 30, 2010, EPA proposed new MACT for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and

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mercury. While the future of mercury emission regulation is uncertain, certain states have adopted or proposed mercury control regulations that are more stringent than the federal requirements, which could reduce the demand for coal in those states.

        The EPA has adopted new, more stringent national air quality standards, or NAAQS, for ozone and fine particulate matter. 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. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our mining operations and customers could be affected when the standards are implemented by the applicable states.

        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.

        On June 3, 2010, 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. EPA also plans to address the secondary sulfur dioxide standard, which is currently under review. As a result, coal-fired power plants, which are the largest end users of our coal, may be required to install additional emissions control equipment or take other steps to lower sulfur emissions.

        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. 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.

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Carbon Dioxide Emissions

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

        Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax 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 greenhouse gas 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 greenhouse gas 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;

        (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 greenhouse gases 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 greenhouse gas 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 Act's emissions thresholds; and

        (7)   the December 2010 "SIP Call" rule, finding 13 State Implementation Plans ("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. Finally, in December 2010, the EPA issued its plan to update pollution standards for fossil fuel power plants and petroleum refineries. The EPA has stated that it intends to propose standards for power plants in July 2011 and for refineries in December 2011 and will issue final standards in May 2012 and November 2012, respectively. This new standard 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,

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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. Similarly in 2007, six Midwestern states and one Canadian province signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. The Final Model Rule, released in April 2010, 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 trade program.

        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 of 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 greenhouse gas emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fueled power plants without limits on greenhouse gas 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.

        Increased efforts to control greenhouse gas emissions could result in reduced demand for coal. Current or future climate change rules have required, and rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired power plants and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon fuel. There can be no assurance at this time that a carbon dioxide cap and trade program, a carbon tax or other regulatory regime, if implemented by the states in which our customers operate or at the federal level, or future court orders or other legally enforceable mechanisms, will not affect the future market for coal in those regions. If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. For example, the U.S. Department of Energy announced in May 2009 that it would provide $2.4 billion of federal stimulus funds under the ARRA to expand and accelerate the commercial deployment of large-scaled carbon capture and

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storage technology. However, there can be no assurances that cost-effective carbon capture and storage technology will become commercially feasible in the near future.

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 United States. The CWA establishes in-stream water quality and treatment standards for wastewater discharges 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 United States. Our surface coal mining and preparation plant operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA issues 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. Although the CWA has long authorized EPA to review 404 permits issued by the Corps, EPA has only recently begun reviewing 404 permits issued by the Corps for 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 EPA regarding these permits.

        For instance, even though the State of West Virginia has been delegated the authority to issue permits for coal mines in that state, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. EPA has stated that it plans to review all applications for NPDES permits. Indeed, interim final guidance issued by the EPA on April 1, 2010, 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.

        In addition, the April 1, 2010, interim final guidance also addresses the Regions' involvement in Section 404 permitting decisions. This guidance follows up on the June 11, 2009 Enhanced Coordination Process Memoranda for the issuance of 404 permits whereby EPA undertook a new level of review of 404 permits than it had previously undertaken. Ultimately, EPA identified 79 coal-related applications for 404 permits that would need to go through that process. EPA's actions in issuing the Enhanced Coordination Process Memoranda and the guidance are being challenged in a lawsuit pending before the United States District Court for the District of Columbia in a case captioned National Mining Assoc. v. U.S. Environmental Protection Agency. In a ruling issued on January 18, 2011, the District Court held that these measures "are legislative rules that were adopted in violation of the APA's notice and comment requirements." The court would not grant the motion for a preliminary injunction to enjoin further use of these measures but also refused to dismiss the Complaint as the EPA had sought.

        Not only is EPA reviewing new permits before they are issued, EPA has recently exercised its "veto" power on January 14, 2011 to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action is the first time that such power was exercised with regard to a previously permitted coal mining project. 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 uncertainly 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.

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        These initiatives have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with obtaining and complying with those permits will increase substantially. 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 actual 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 we cannot assure you that our applications will be granted or, alternatively, require material changes to their terms before being granted by the Corps. 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.

        In December 2008, the Department of Interior published the Excess Spoil, Coal Mine Waste and Buffers for Perennial and Intermittent Streams rule under SMCRA in part to clarify when valley fills are permitted. The rule would require a 100-foot buffer around all waters, including streams, lakes, ponds and wetlands. However, the rule would exempt certain activities, such as permanent spoil fills and coal waste disposal facilities, and allow mining that changes a waterway's flow, providing the mining company repairs damage later. Companies could also receive a permit to dispose of waste within the buffer zone if they explain why an alternative is not reasonably possible or is not necessary to meet environmental requirements. Environmental groups brought lawsuits challenging the rule and in a March 2010 settlement with litigation parties, the OSM agreed to use best efforts to sign a proposed rule by February 28, 2011 and a final rule by June 29, 2012. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams.

        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 TMDL-related allocations for our coal mines could require more costly water treatment and could 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

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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 have 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 recognizes that those discharges are subject to comparable regulation under SMCRA and Section 404 of the CWA. The EPA has launched a rulemaking to revise its water quality standards regulations. The elimination of the alternative implementation methodology for coal mining discharges or other provisions of Kentucky's antidegradation rules could mean that our operations in Kentucky would be 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 "Superfund", 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 substances. 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, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option utilizes Subtitle D, which gives EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits. The proposal leaves intact the Bevill exemption for beneficial uses of CCB. If CCB is not classified as hazardous waste, it is not anticipated that regulation of CCB will have any material effect on the amount of coal used by electricity generators. However, 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.

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        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 Policy Act ("NEPA"). NEPA requires federal agencies, including the Department of 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, or EA, 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, we cannot assure you that the NEPA review will not 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.

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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.

Employees

        To carry out our operations, our general partner and our subsidiaries employed 897 full-time employees as of December 31, 2010. 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 $11.3 million per quarter, or $45.0 million per year, based on the number of common and subordinated units outstanding as of December 31, 2010 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the

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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;



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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;



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the proximity to and capacity of transportation facilities;



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the price and availability of alternative fuels;



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



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the level of worldwide energy and steel consumption;



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prevailing economic and market conditions;



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



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the effects of new or expanded health and safety regulations;



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



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changes in tax laws;



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weather conditions; and



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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:

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the supply of domestic and foreign coal;



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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;



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the proximity to, and capacity of, transportation facilities;



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



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the level of domestic and foreign taxes;



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the price and availability of alternative fuels for electricity generation;



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weather conditions;



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

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•

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 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

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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 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 clean up of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire.

The government extensively regulates our 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 national levels that have resulted in increased 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, 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, and subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act imposing 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:

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sealing off abandoned areas of underground coal mines;



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mine safety equipment, training and emergency reporting requirements;



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substantially increased civil penalties for regulatory violations;



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training and availability of mine rescue teams;



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



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

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•

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. Also, additional federal and state legislation that further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has been considered in light of recent fatal mine accidents. Further workplace accidents are likely to also result in more stringent enforcement and possibly the passage of new laws and regulations.

        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."

Penalties, fines or sanctions levied by MSHA could have a material adverse effect on our business, results of operations and cash available for distribution. Our Mine 28 recently received a number of notices of violation from MSHA.

        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.

        Recently, our Mine 28 was included on a list of 48 mines that would have faced "pattern of violation" sanctions had the owners/operators of such mines not contested the notices of violation. This list was publicly released by U.S. Representative George Miller on April 14, 2010. MSHA inspected Mine 28 again promptly thereafter, and issued additional notices of violation.

        On November 19, 2010, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and serves as manager, 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 February 4, 2011, CAM Mining, a subsidiary of us, received an imminent danger order under Section 107(a) of the Mine Act which stated that two carpenters in the employ of an independent, third-party contractor were working 10 feet above ground on the roof of a structure at CAM Mining's Mine 28 without tie off lines. The carpenters were immediately instructed to safely climb down to the ground level where they received further safety training. These actions terminated the order.

        As a result of these and future inspections and alleged violations and potential violations, we could be subject to material fines, penalties or sanctions. Mine 28, as well as any of our other 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.

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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.

        Individual or general permits under Section 404 of the CWA are required to 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. The Corps is authorized to issue "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 NWP 21 because on June 17, 2010, the Corps suspended the use of NWP 21, but NWP 21 authorizations already granted remain in effect.

        Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of Section 402 and Section 404 permits by state and federal agencies. This guidance follows up on the June 11, 2009 Enhanced Coordination Process Memorandum for the issuance of 404 permits whereby EPA undertook a new level of review of 404 permits than it had previously undertaken. Not only is EPA reviewing new permits before they are issued, EPA has recently exercised its "veto" power on January 14, 2011 to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action is the first time that such power was exercised with regard to a previously permitted coal mining project. EPA's use of its guidance and Enhanced Coordination Process Memorandum have created significant uncertainty about the time required to obtain new permits, the terms of those permits, and the possible rejection of permit applications. More frequent use of the EPA's Section 404 "veto" power including any application of this power to previously permitted projects could create uncertainly 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.

        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 conduct our mining operations pursuant to 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;

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•

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



•

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.

        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.

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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 $18 to $22 million for 2011. 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 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. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases. Many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the development of regional greenhouse gas cap-and-trade programs.

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        In the wake of the Supreme Court's April 2, 2007 decision in Massachusetts, et al. v. EPA, which held that greenhouse gases 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 greenhouse gases, 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 greenhouse gas emissions under existing provisions of the federal CAA. There are many regulatory approaches currently in effect or being considered to address greenhouse gases, 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 greenhouse gas emissions from the new plants. In addition, several permits issued to new coal-fired power plants without limits on greenhouse gas emissions have been appealed to EPA's Environmental Appeals Board.

        As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less greenhouse gas 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 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, 2010, we had $76.1 million in reclamation surety bonds, secured by $29.7 million in letters of credit outstanding under our credit agreement. Our credit agreement provides for a $200 million working capital revolving credit facility, of which up to $50.0 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

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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, 2010 we had sales commitments for approximately 73% 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, 2011. 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 51% in 2011, 30% in 2012, and 19% in 2013. We derived approximately 82.5% of our total revenues from coal sales (excluding results from the joint venture) to our ten largest customers for the year ended December 31, 2010, with affiliates of our top three customers accounting for approximately 43.0% 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 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 84% of our coal sales volume for the year ended December 31, 2010. 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

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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.

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, 2010, approximately 8% 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

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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, we cannot assure you that all of our work force will 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.

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.

We may invest in non-coal natural resource assets, which could have 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 may include investing in non-coal natural resources assets. Our management team has no experience investing in or operating non-coal natural resources assets and we may be unable to hire additional management with relevant expertise in acquiring and operating such assets. Furthermore, the acquisition of non-coal natural resource assets could expose us to new and additional operating and regulatory risks. Investments in non-coal natural resource assets could have a material adverse effect on our results of operations and cash available for distribution to our unitholders.

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;

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•

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, 2010 our current portion of long-term debt that will be funded from cash flows from operating activities during 2011 was approximately $2.9 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 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;

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•

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, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Wexford, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

        Wexford owns and controls our general partner and has appointed all of the directors of 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 Wexford. Therefore, conflicts of interest may arise between Wexford and its affiliates, including 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 affiliates over the interests of our common unitholders.

•

our general partner is allowed to take into account the interests of parties other than us, such as Wexford, 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;

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•

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 90% of the common units (if our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding common units, the ownership threshold to exercise the call right will be reduced to 80%);



•

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 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,

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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 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:

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how to allocate business opportunities among us and its affiliates;



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whether to exercise its limited call right;

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•

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



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whether to exercise its registration rights;



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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



•

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

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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.

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

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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. Currently, Wexford owns an aggregate of approximately 84% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no 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.

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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 90% 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. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding common units, the ownership threshold to exercise the limited call rights will be reduced to 80%. 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. Currently, Wexford owns an aggregate of approximately 84% of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units and no transfer by Weford of its units), Wexford will own approximately 84% of our common 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;



•

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, 2010, we had 12,406,760 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. All of the common units issued to Wexford in connection with our IPO are subject to a 180-day lock-up agreement with the underwriters, the period of which may be extended under certain circumstances. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by Wexford or other large holders of a

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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. Currently, Wexford owns approximately 69% of the outstanding common units and 99% of our outstanding subordinated units.

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

        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

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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 cannot provide absolute assurance as to our ability 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.

        Subsequent to the audit of our consolidated financial statements for the year ended December 31, 2009, our independent registered public accounting firm identified a deficiency in our internal control over financial reporting as a result of a restatement of our consolidated financial statements as of December 31, 2008 which constituted a material weakness. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. As a result of the identified material weakness, we restated our consolidated historical financial statements for the year ended December 31, 2008. Although we have taken measures to improve our internal control over financial reporting, we cannot assure you that additional material weaknesses that may result in a material misstatement of our financial statements will not occur in the future.

We will incur increased costs as a result of being a publicly traded partnership.

        As a publicly traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to our IPO. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that increase our costs. Before we are able to make distributions to our members, we must first pay or reserve cash for our expenses, including the costs of being a publicly traded

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partnership. As a result, the amount of cash we have available for distribution to our members will be affected by the costs associated with being a publicly traded partnership.

        We have only recently become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, incur additional costs associated with our SEC reporting requirements.

        We also incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

        We estimate that we will incur approximately $3.0 million of incremental costs per year associated with being a publicly-traded partnership; however, it is possible that our actual incremental costs of being a publicly-traded partnership will be higher than we currently estimate.

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. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business or a change in current law could cause us to be treated as a corporation for U.S. 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. Specifically, the present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation recently has been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to

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us as proposed, 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 these changes, or other proposals, will ultimately be enacted. Any such changes 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, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

        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 that results 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 realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the 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

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recapture. In addition, because the amount realized includes a unitholder's 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.

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, however, 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, we may be required to change our allocation of items of income, gain, loss and deduction among our unitholders.

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

        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, he 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 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 84% 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

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than twelve months of our taxable income or loss being includable in his 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.

        Among the changes contained in President Obama's Budget Proposal, or the Budget Proposal, for Fiscal Year 2011 is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. 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 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

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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 March 31, 2010, and covered all 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 in October 2010. While 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, our estimates as of December 31, 2010 were prepared by our staff of geologists and engineers.

        As of December 31, 2010, we controlled an estimated 309.0 million tons of proven and probable reserves and an estimated 271.8 million tons of non-reserve coal deposits. As of December 31, 2010, the joint venture controlled an estimated 22.2 million tons of proven and probable coal reserves and an estimated 34.3 million tons of non-reserve coal deposits.

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Coal Reserves

        The following table provides information as of December 31, 2010 on the type, amount and ownership of the coal 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.

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        The following table provides information on particular characteristics of our and the joint venture's coal reserves as of December 31, 2010:

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Non-Reserve Coal Deposits

        The following table provides information on our and the joint venture's non-reserve coal deposits as of December 31, 2010:

        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.    (Removed and Reserved).

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PART II

Item 5.    Market for Registrant's Common Equity, Related Shareholder 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 14, 2011, the closing market price for our common units was $24.75 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:

        As of March 14, 2011, we had outstanding 12,406,760 common units, 12,397,000 subordinated units, a 2% general partner interest and incentive distribution rights, or IDRs. As of March 14, 2011, Rhino Energy Holdings LLC owned approximately 68.9% of our outstanding common units and 98.6% 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 14, 2011, there were 10 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 69% of the outstanding common units and 99% 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:

        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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Recent Sales of Unregistered Securities; Use of Proceeds From Sale of Registered Securities

        On April 19, 2010, in connection with our formation, we issued to our general partner the 2.0% general partner interest in us for $20 and (ii) to Rhino Energy Holdings LLC the 98.0% limited partner interest in the us for $980.

        In connection with the closing of our IPO on October 5, 2010, the following occurred:

•

Wexford contributed all of their membership interests in Rhino Energy LLC to us;



•

we issued to Rhino Energy Holdings LLC an aggregate of 8,666,400 common units and 12,397,000 subordinated units;



•

our general partner made a capital contribution of approximately $10.4 million and maintained its 2.0% general partner interest in us; and



•

we issued our general partner the incentive distribution rights, which entitle the holder to increase percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.51175 per unit per quarter.

        Each of these issuances was exempt from registration under Section 4(2) of the Securities Act of 1933. Each of the subordinated units will convert into a common unit as described above. On October 5, 2010, we completed our IPO in which we sold 3,730,600 common units to the public at a price of $20.50 per common unit pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-166550), that was declared effective on September 29, 2010. Our IPO did not terminate prior to the sale of all securities registered. Raymond James & Associates, Inc. acted as the book-running manager for the offering. RBC Capital Markets and Stifel, Nicolaus & Company, Incorporated acted as co-managers for the IPO. Gross proceeds from the offering were approximately $76.5 million, and net proceeds were approximately $67.6 million after deducting underwriting discounts and offering expenses of $8.9 million, including $1.0 million of bonuses payable to certain executive officers and directors.

        We used the net proceeds from the IPO, 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 and to reimburse affiliates of our sponsor, Wexford Capital, for approximately $9.3 million of capital expenditures incurred with respect to the assets contributed to us in connection with the IPO. Affiliates of Raymond James & Associates, Inc. and RBC Capital Markets are lenders under our credit facility and received their pro rata portion of the net proceeds from the IPO and the related capital contribution by our general partner through the repayment of borrowings they had extended under the credit agreement.

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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 March 31, 2006 and December 31, 2006, 2007 and 2008 and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 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 as of December 31, 2009 and 2010 and for the years ended December 31, 2008, 2009 and 2010 are derived from the audited historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this report. Effective April 1, 2006, Rhino Energy LLC changed its fiscal year end from March 31 to December 31.

        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, EBITDA, which we use in our business as it is an important supplemental measure of our performance and liquidity. EBITDA represents net income before interest expense, income taxes and depreciation, depletion and amortization. This measure is not calculated or presented in accordance with GAAP. We explain this

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measure under "—Non-GAAP Financial Measure" and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

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Non-GAAP Financial Measure

        EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, to assess:

•

our financial performance without regard to financing methods, capital structure or income taxes;



•

our ability to generate cash sufficient to make distributions to our unitholders; and



•

our ability to incur and service debt and to fund capital expenditures.

        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. 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.

        EBITDA as presented below may not be comparable to similarly titled measures of other companies. The following table presents a reconciliation of EBITDA to the most directly comparable

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GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated:

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

        For ease and comparability purposes in comparing 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 2010 are comparable with 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 related 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.

        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, 2010, we controlled an estimated 309.0 million tons of proven and probable coal reserves, consisting of an estimated 297.0 million tons of steam coal and an estimated 12.0 million tons of metallurgical coal. In addition, as of December 31, 2010, we controlled an estimated 271.8 million tons of non-reserve coal deposits. As of December 31, 2010, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 22.2 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 34.3 million tons of non-reserve coal deposits. Our and the joint venture's proven and probable coal reserves and non-reserve coal deposits were the same in all material respects as of December 31, 2009. As of December 31, 2010, we operated ten mines, including five underground and five surface mines, located in Kentucky, Ohio and West Virginia. 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 due to the expiration of our sole customer contract at this location. We are currently planning to restart production at this location in late 2011. Additionally, we began production and customer shipments in January 2011 at one underground mine located in Emery and Carbon Counties in Utah that we acquired out of bankruptcy in August of 2010. The number of mines that we operate may vary from time to time 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 and sell 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 non-coal 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 by, for example, serving as a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel, steel products and other commodities consumed in the mining process.

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        For the year ended December 31, 2010, we generated revenues of approximately $305.6 million and net income of approximately $41.1 million. Excluding results from the joint venture, for the year ended December 31, 2010, we produced approximately 4.0 million tons of coal, purchased approximately 0.3 million tons of coal and sold approximately 4.3 million tons of coal, approximately 96% 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, 2010.

Recent Developments

Initial Public Offering

        On October 5, 2010, we completed our IPO, in which we sold an aggregate of 3,730,600 common units to the public at a price of $20.50 per common unit. Net proceeds from the offering were approximately $67.6 million, after deducting underwriting discounts and estimated offering expenses of $8.9 million. We used the net proceeds from this offering, 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 and to reimburse Wexford for capital expenditures incurred with respect to the assets contributed to us in connection with the offering.

        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 and issued incentive distribution rights to our general partner.

Credit Facility

        In connection with our IPO, we amended our credit agreement to revise certain restrictive provisions, allow for the equity transfer of Rhino Energy LLC to us in the event of a successful IPO and provide for quarterly cash distributions of available cash, as that term is defined in our partnership agreement. See also "Liquidity and Capital Resources—Credit Agreement."

Utah Acquisition

        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. We began production from these assets at one underground mine in early 2011 and expect the type of coal produced will be steam coal. As of a result of this acquisition being completed under a distressed bankruptcy sale, we recognized a $10.8 million gain during 2010 in accordance with accounting principles generally accepted in the United States of America, which positively impacted our 2010 net income.

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

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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, 2010, we had commitments under supply contracts to deliver annually scheduled base quantities of 3.7 million, 2.2 million and 1.4 million tons of coal to 16 customers in 2011, 5 customers in 2012, and 3 customers in 2013, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

        During the year ended December 31, 2008, we entered into certain long-term sales contracts at favorable prices. Sales under these contracts are included in the sales and commitments discussed in the previous paragraph and had a significant impact on revenues for year ended December 31, 2010. We have remaining commitments under these contracts of approximately 0.4 million tons of coal at an average price of approximately $92 per ton for each of the years ending December 31, 2011, 2012 and 2013.

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, 2010, together included four underground mines, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. 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 southern Ohio, included one underground mine and one preparation plant and loadout facility as of December 31, 2010. Our Sands Hill mining complex, located in northern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2010. 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, 2010, this complex was comprised of one underground mine and a preparation plant and loadout facility (owned by our joint venture partner). Our Rhino Western segment includes our coal reserves in the Illinois Basin, as well as our two underground mines in the Western Bituminous region. Of the latter two, our McClane Canyon mine in Colorado was temporarily idled at the end of 2010 upon the expiration of our sole customer contract, and our Castle Valley mining complex in Utah 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) EBITDA, (2) coal revenues per ton and (3) cost of operations per ton.

        EBITDA.    The discussion of our results of operations below includes references to, and analysis of, our segments' EBITDA results. EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used by management primarily as a measure of our segments' operating performance. 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

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companies calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income 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 depreciation, depletion and amortization) divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency of operations.

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, 2010, 2009 and 2008:

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

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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 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 December 31, 2009. EBITDA increased to $80.6 million for the year ended December 31, 2010, from $62.0 million for the year ended December 31, 2009. The increases in net income and 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 and EBITDA in 2010 also benefited by a $10.8 million gain recognized on the Castle Valley Acquisition discussed earlier.

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

        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:

        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 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.

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        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.

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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, 2010 and 2009:

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        Cost of Operations.    Total cost of operations was $220.8 million for the year ended December 31, 2010 as compared to $336.3 million for the year ended December 31, 2009, primarily as a result of a decrease in the amount of purchased coal offset by increased costs associated with heightened regulatory scrutiny. Our cost of operations per ton was $51.27 for the year ended December 31, 2010, an increase of $1.06, or 2.1%, from the year ended December 31, 2009. This overall increase in the cost of operations on a per ton basis was due to increased costs associated with heightened regulatory scrutiny.

        Our cost of operations for the Central Appalachia segment decreased by $115.6 million, or 46.4%, to $133.5 million for the year ended December 31, 2010 from $249.1 million for the year ended December 31, 2009, primarily due to purchasing fewer tons at a lower total cost offset by increases in cost of operations associated with labor, contract services, royalties and maintenance. Our cost of operations per ton increased to $61.87 per ton for the year ended December 31, 2010 from $58.32 per ton for year ended December 31, 2009. This increase in cost of operations per ton was primarily due to higher costs of operations associated with heightened regulatory scrutiny.

        In our Northern Appalachia segment, our cost of operations decreased by $6.4 million, or 9.0%, to $65.1 million for the year ended December 31, 2010 from $71.5 million for the year ended December 31, 2009, primarily due to decreased expenditures for operating supplies offset by increases in costs such as maintenance and outside services. Our cost of operations per ton increased to $33.43 for the year ended December 31, 2010 from $33.04 for the year ended December 31, 2009, an increase of $0.39 per ton, or 1.2%. This increase in cost of operations per ton was primarily due to higher roof control costs at our underground operation due to ground control issues requiring additional materials to be used.

        Cost of operations in our Rhino Western segment increased by $0.7 million, or 10.9%, to $6.9 million for the year ended December 31, 2010 from $6.2 million for the year ended December 31, 2009, primarily due to an increase in amounts spent for outside services. Our cost of operations per ton increased to $34.20 for the year ended December 31, 2010 from $23.56 for the year ended December 31, 2009, an increase of $10.63 per ton, or 45.1%. This increase in cost of operations per ton was primarily due to charges associated with the idling of the McClane Canyon mine and the rehabilitation of the Castle Valley mine.

        Cost of operations in our Other category increased by $5.8 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. This increase was primarily due to an increase in amounts spent for outside services.

        Freight and Handling.    Total freight and handling cost for the year ended December 31, 2010 decreased by $1.4 million, or 34.0%, to $2.6 million from $4.0 million for the year ended December 31, 2009. This decrease was primarily due to a 2.4 million decrease in the number of tons sold for the period ended December 31, 2010 as compared to the period ended December 31, 2009.

        Depreciation, Depletion and Amortization.    Total depreciation, depletion and amortization, or DD&A, expense for the year ended December 31, 2010 was $34.1 million as compared to $36.3 million for the year ended December 31, 2009.

        For the year ended December 31, 2010, our depreciation cost was $26.8 million as compared to $29.3 million for the year ended December 31, 2009. The decrease in depreciation cost in 2010 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, 2010, our depletion cost was $1.8 million as compared to $2.3 million for the year ended December 31, 2009. The decrease in depletion cost in 2010 was primarily due to a decrease in tons of coal produced in 2010 when compared to 2009.

        For the year ended December 31, 2010, our amortization cost was $5.5 million as compared to $4.7 million for the year ended December 31, 2009. This increase is primarily attributable to the acceleration of 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, or SG&A, expense for the year ended December 31, 2010 was $16.4 million as compared to $16.8 million for the year ended December 31, 2009. This decrease in SG&A expense was primarily due to a gain recognized on a litigation settlement, partially offset by an increase in expenditures for legal fees associated with the Castle Valley acquisition and other professional fees.

        Interest Expense.    Interest expense for the year ended December 31, 2010 was $5.3 million as compared to $6.2 million for the year ended December 31, 2009, a decrease of $0.9 million, or 14.2%. This decrease was primarily the result of a reduction in the balance due under our credit facility in the fourth quarter of 2010.

        Net Income (Loss).    The following table presents net income (loss) by reportable segment for the years ended December 31, 2010 and 2009:

        For the year ended December 31, 2010, total net income increased to $41.1 million from $19.5 million for the year ended December 31, 2009. This increase was primarily due to the sale of a higher percentage of metallurgical coal, higher contracted prices for the steam coal, a reduction in the amount of coal purchased that was sold near breakeven in 2009 and the $10.8 million gain recognized on the Castle Valley acquisition. For our Central Appalachia segment, net income increased to $20.6 million for the year ended December 31, 2010, an improvement of $20.0 million as compared to the year ended December 31, 2009, primarily due an increase in our higher margin metallurgical coal sales. Net income in our Northern Appalachia segment decreased by $7.5 million to $10.1 million for the year ended December 31, 2010, from $17.6 million for the year ended December 31, 2009. This decrease was primarily due to higher costs of operations at both the surface and underground mines in addition to a decrease in sales as dictated by market conditions. Our Eastern Met segment recorded net income of $4.7 million for the year ended December 31, 2010, an increase of $3.8 million from $0.9 million recorded for the year ended December 31, 2009. For our Rhino Western segment, we recorded net income of $11.2 million for the year ended December 31, 2010, an increase of $7.9 million from $3.3 million recorded for the year ended December 31, 2009. This increase in net income was primarily due to the $10.8 million gain recorded on the Castle Valley acquisition. For the Other category, we had a net loss of $5.5 million for the year ended December 31, 2010, a decrease of

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$2.6 million as compared to a net loss of $2.9 million recorded for the year ended December 31, 2009. This decrease was primarily due to an increase in costs of operations as well as an asset impairment charge recorded for certain assets in two of our ancillary businesses.

        EBITDA.    The following table presents EBITDA by reportable segment for the years ended December 31, 2010 and 2009:

        Total EBITDA for the year ended December 31, 2010 was $80.6 million, an increase of $18.6 million from the year ended December 31, 2009 primarily due to an increase in net income of $21.6 million offset by a decrease in depreciation expense of $2.2 million and a decrease in interest expense of $0.9 million. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, DD&A and interest expense are not presented separately for our Eastern Met segment. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

        Summary.    For the year ended December 31, 2009, our total revenues declined to $419.8 million from $438.9 million for the year ended December 31, 2008. The decrease was primarily due to the global economic recession and a concurrent decrease in the demand for both steam and metallurgical coal. As a result of this decreased demand, we sold 6.7 million tons of coal for the year ended December 31, 2009, which is 1.3 million fewer tons, or 16.0% less, than the 8.0 million tons of coal sold for the year ended December 31, 2008. Despite the decrease in the number of tons that we produced and sold, both net income and EBITDA increased for the year ended December 31, 2009 from the year ended December 31, 2008. Net income increased to $19.5 million for the year ended December 31, 2009 from $0.9 million for the year ended December 31, 2008, and EBITDA increased to $62.0 million for the year ended December 31, 2009 from $42.9 million for the year ended December 31, 2008. These increases in net income and EBITDA were the result of favorable pricing included in contracts executed in 2008 and effective for the year ended December 31, 2009 as well as our successful efforts to control the cost of operations.

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        Tons Sold.    The following table presents tons of coal sold by reportable segment for the years ended December 31, 2009 and 2008:

        Tons of coal sold for the year ended December 31, 2009 decreased by 1.3 million tons, primarily due to lower production in our Central Appalachia segment. Tons of coal sold in our Central Appalachia segment decreased by 1.3 million, or 22.0%, to 4.2 million tons for the year ended December 31, 2009 from 5.5 million tons for the year ended December 31, 2008. This decrease in production was a response to decreased demand for coal as well as the result of temporarily idling several of our less profitable surface mines. For our Northern Appalachia segment and Rhino Western segment tons of coal sold were flat at 2.2 million tons and 0.3 million tons, respectively, for the year ended December 31, 2009. These operations maintained consistent sales due to the fact they serve a small customer base under supply contracts. We produced 4.7 million tons of coal and purchased 2.0 million tons of coal in 2009 as compared to producing 7.7 million tons of coal and purchasing 0.3 million tons of coal in 2008. We purchased additional amounts of coal in 2009 in order to satisfy certain existing contracts and to take advantage of favorable coal prices in the OTC market, which in some cases were lower than the actual costs of producing the same amount of coal.

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        Revenues.    The following table presents revenue data by reportable segment for the years ended December 31, 2009 and 2008:

        Our total revenues for the year ended December 31, 2009 decreased by $19.1 million, or 4.4%, to $419.8 million from $438.9 million for the year ended December 31, 2008. The decline in total revenues was due to a decrease in coal demand as a result of the global recession. Coal revenues per ton were $59.98 for the year ended 2009, an increase of $8.73, or 17.0%, from $51.25 per ton for the year ended December 31, 2008. This increase in coal revenues per ton for the year ended December 31, 2009 was primarily the result of supply contracts executed in 2008 at favorable prices offset by the sale of a smaller percentage of metallurgical coal. The impact of the favorable prices included in these contracts

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was an increase in coal revenue per ton of approximately $11.49. This increase was offset by the impact of a less favorable sales mix as compared to the year ended December 31, 2008. This impact was a decrease of approximately $2.76 per ton.

        For our Central Appalachia segment, coal revenues decreased by $15.5 million, or 5.0%, to $295.1 million for the year ended December 31, 2009 from $310.6 million for the year ended December 31, 2008 due to fewer tons of coal sold in 2009. Coal revenues per ton for our Central Appalachia segment increased by 21.8%, or $12.36, to $69.10 per ton for the year ended December 31, 2009 as compared to $56.74 per ton for the year ended December 31, 2008 due to favorable pricing included in contracts executed in 2008 offset by a less favorable sales mix of steam and metallurgical coal.

        For our Northern Appalachia segment, coal revenues were $95.5 million for the year ended December 31, 2009, an increase of $5.6 million, or 6.1%, from $89.9 million for the year ended December 31, 2008 as a result of favorable prices included in our supply contracts. Coal revenues per ton for our Northern Appalachia segment increased by 9.1%, or $3.68, to $44.12 per ton for the year ended December 31, 2009 from $40.44 per ton for the year ended December 31, 2008. The increase in 2009 was primarily due to favorable pricing included in contracts executed in 2008 for coal produced at our Sands Hill operation.

        For our Rhino Western segment, coal revenues increased by $2.9 million, or 34.9%, to $11.2 million for the year ended December 31, 2009 from $8.3 million for the year ended December 31, 2008. Coal revenues per ton for our Rhino Western segment were $42.35 for the year ended December 31, 2009, an increase of $12.61, or 42.4%, from $29.74 for the year ended December 31, 2008 as a result of favorable prices included in supply contracts executed in 2008.

        For our Other category, other revenues increased by $0.8 million, or 21.0%, to $4.2 million for the year ended December 31, 2009 from $3.4 million for the year ended December 31, 2008. The increase was primarily due to the addition of sales in 2009 from our roof bolt manufacturing operations of $1.8 million, offset by a decrease in revenues of $1.0 million for our other ancillary services operations.

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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, 2009 and 2008:

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        Cost of Operations.    Total cost of operations was $336.3 million for the year ended December 31, 2009 as compared to $364.9 million for the year ended December 31, 2008, primarily resulting from a decrease in the amount of coal produced of 2.8 million tons for the year ended December 31, 2009 as compared to the same period in 2008; however, we sold 2.0 million tons of purchased coal for the year ended December 31, 2009, an increase of 1.5 million tons from the year ended December 31, 2008. Our cost of operations per ton was $50.21 for the year ended December 31, 2009, an increase of $4.46, or 9.8%, from the year ended December 31, 2008. This increase was primarily due to the higher costs of labor, insurance and purchased coal, partially offset by reductions in the cost of operating supplies such as diesel fuel and explosives. We took steps to reduce our workforce as production slowed but necessarily retained a higher percentage of employees in critical ancillary and support positions. These labor costs, when applied to the smaller base of tons produced, resulted in higher costs on a per ton basis.

        Our cost of operations for our Central Appalachia segment decreased by $23.7 million, or 8.7%, to $249.1 million for the year ended December 31, 2009 from $272.8 million for the year ended December 31, 2008, primarily resulting from a decrease in the amount of coal produced of 2.8 million tons. Our cost of operations per ton, however, increased to $58.32 per ton for the year ended December 31, 2009 from $49.84 per ton for the year ended December 31, 2008. This increase was primarily due to the higher costs of labor, insurance and purchased coal, offset by reductions in the cost of operating supplies such as diesel fuel and explosives. We bought 1.5 million more tons of coal for the year ended December 31, 2009 compared to the year ended December 31, 2008.

        In our Northern Appalachia segment, our cost of operations decreased by $5.1 million, or 6.7%, to $71.5 million for the year ended December 31, 2009 from $76.6 million for the year ended December 31, 2008, primarily due to reductions in the costs of fuel, explosives and roof support. Our cost of operations per ton decreased to $33.04 for the year ended December 31, 2009 from $34.45 for the year ended December 31, 2008, a decrease of $1.40 per ton, or 4.1%, also due to reductions in amounts spent for operating supplies such as diesel fuel, explosives and roof support.

        In our Rhino Western segment, our cost of operations increased by $0.1 million, or 2.6%, to $6.2 million for the year ended December 31, 2009 from $6.1 million for the year ended December 31, 2008. Our cost of operations per ton increased to $23.56 for the year ended December 31, 2009 from $21.76 for the year ended December 31, 2008, an increase of $1.80 per ton, or 8.3%.

        Cost of operations in our Other category increased by $0.1 million for the year ended December 31, 2009 as compared to the year ended December 31, 2008.

        Freight and Handling.    Total freight and handling costs for the year ended December 31, 2009 decreased by $6.2 million, or 61.0%, to $4.0 million from $10.2 million for the year ended December 31, 2008. This decrease was primarily due to a decrease of 1.3 million tons of coal sold for the year ended December 31, 2009 as well as a decrease in the cost of fuel and favorable new contract terms that required customers to assume the transportation cost of purchased coal.

        Depreciation, Depletion and Amortization.    Total DD&A expense for the year ended December 31, 2009 was $36.3 million as compared to $36.4 million for the year ended December 31, 2008.

        For the year ended December 31, 2009, our depreciation cost was $29.2 million as compared to $26.0 million for the year ended December 31, 2008. The higher depreciation cost in 2009 was primarily due to the acquisition of operating assets.

        For the year ended December 31, 2009, our depletion cost was $2.3 million as compared to $4.0 million for the year ended December 31, 2008. The decrease in depletion cost in 2009 was primarily a result of the decrease in the number of tons of coal produced for the year ended December 31, 2009.

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        For the year ended December 31, 2009, our amortization cost was $4.7 million as compared to $6.4 million for the year ended December 31, 2008. Amortization cost for the year ended December 31, 2009 decreased as a result of producing fewer tons in 2009.

        Selling, General and Administrative.    Total SG&A expense for the year ended December 31, 2009 was $16.8 million as compared to $19.1 million for the year ended December 31, 2008. The decrease in SG&A expense for the year ended December 31, 2009 was primarily due to $3.6 million in costs related to an abandoned public offering recorded in August of 2008. This benefit was partially offset by decreases in the amounts of discounts and rebates available in 2009 and an increase in amounts spent for licenses, fines and penalties.

        Interest Expense.    Interest expense for the year ended December 31, 2009 was $6.2 million as compared to $5.5 million for the year ended December 31, 2008, an increase of $0.7 million, or 13.1%. For the year ended December 31, 2008, we increased our overall debt to fund the acquisition of the Deane mining complex, additional coal reserves at our Deane mining complex and the investment in the joint venture. The increase in interest expense for 2009 reflects a full year of interest expense resulting from debt incurred on 2008 acquisitions.

        Net Income (Loss).    The following table presents net income (loss) by reportable segment for the years ended December 31, 2009 and 2008:

        For the year ended December 31, 2009, total net income increased to $19.5 million from $0.9 million for the year ended December 31, 2008. This increase was due to favorable prices included in supply contracts executed in 2008 and successful cost containment efforts. For our Central Appalachia segment, net income increased to $0.6 million for the year ended December 31, 2009, an improvement of $4.1 million primarily due to higher coal revenues per ton as a result of favorable contract pricing and successful cost containment efforts. Net income in our Northern Appalachia segment increased by $6.7 million to $17.6 million for the year ended December 31, 2009, from $10.9 million for the year ended December 31, 2008 primarily due to higher coal revenues per ton resulting from favorable pricing included in contracts executed during 2008 for coal sold during 2009. Net income from our Eastern Met segment increased by $2.5 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, as a result of the Rhino Eastern mining complex reaching full production and beginning sales of metallurgical coal. Net income from our Rhino Western segment increased by $2.6 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, as a result of higher revenues from our Colorado operations. For our Other category, we had a net loss of $2.9 million for the year ended December 31, 2009 as compared to a net loss of $5.6 million for the year ended December 31, 2008. This $2.7 million improvement was primarily due to abandoned public offering costs recorded in 2008, and lower costs of operations from

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our ancillary businesses. These ancillary businesses provide services such as reclamation, maintenance and transportation.

        EBITDA.    The following table presents EBITDA by reportable segment for the years ended December 31, 2009 and 2008:

        Total EBITDA for the year ended December 31, 2009 was $62.0 million, an increase of $19.1 million from the year ended December 31, 2008, primarily due to a $18.6 million increase in net income for the year ended December 31, 2009. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, depreciation, depletion and amortization, interest expense and income tax expense (benefit) are not presented separately for our Eastern Met segment. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

Reconciliation of EBITDA to Net Income by Segment

        EBITDA represents net income before interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used by management primarily as a measure of each of our segments' operating performance. Because not all companies calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. 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. The following tables present reconciliations of EBITDA to net income for each of the periods indicated.

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Liquidity and Capital Resources

Liquidity

        Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and service our debt. Our sources of liquidity include cash generated by our operations, borrowings under our credit agreement and further issuances of equity and debt securities.

        The principal indicators of our liquidity are our cash on hand and availability under our credit agreement. As of December 31, 2010, our available liquidity was $139.0 million, including cash on hand of $0.1 million and $138.9 million available under our credit agreement.

        Please read "—Capital Expenditures" for a further discussion of the impact on liquidity.

Cash Flows

        Net cash provided by operating activities was $55.0 million for the year ended December 31, 2010 as compared to $41.5 million for the year ended December 31, 2009. This increase in cash provided by operating activities was primarily the result of an increase in net income due to favorable sales prices, partially offset by a use of net working capital related to our asset retirement obligations.

        Net cash used in investing activities was $37.6 million for the year ended December 31, 2010 as compared to $27.3 million for the year ended December 31, 2009. The increase in cash used in investing activities was primarily due to the Castle Valley Acquisition offset by a distribution received

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from our Rhino Eastern joint venture representing a return of investment and a reduction in amounts expended for the purchase of mining equipment and other asset acquisitions.

        Net cash used in financing activities for the year ended December 31, 2010 was $18.0 million, which was primarily attributable to the use of the net proceeds from our IPO along with a contribution from our general partner to repay a portion of the outstanding indebtedness under our credit facility and to pay offering costs. Net cash used for financing activities for the year ended December 31, 2009 was $15.4 million, which primarily represented the repayment of a loan from Wexford and the payment of debt issuance costs.

Capital Expenditures

        Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves; to the extent such expenditures are made to maintain our long-term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of reserves, equipment for a new mine or the expansion of an existing mine to the extent such expenditures are expected to expand our long-term operating capacity.

        Actual maintenance capital expenditures for the year ended December 31, 2010 was approximately $12.2 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the year ended December 31, 2010 was approximately $29.0 million. These amounts were primarily spent for the Castle Valley Acquisition as well as our internal development projects. For the year ending December 31, 2011, we have budgeted $46.0 million to $55.0 million for capital expenditures.

        We believe that we have sufficient liquid assets, cash flows from operations and borrowing capacity under our credit agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity. From time to time, we may issue debt and equity securities.

Credit Agreement

        Rhino Energy LLC, our wholly owned subsidiary, as borrower, and we and our operating subsidiaries, as guarantors, are parties to our $200.0 million credit agreement, which is available for general partnership purposes, including working capital and capital expenditures, and may be increased by up to $75.0 million with the consent of the lenders, so long as there is no event of default. Of the $200.0 million, $50.0 million is available for letters of credit. As of December 31, 2010, we had borrowings outstanding under our credit agreement of approximately $28.5 million and $32.6 million of letters of credit in place, leaving approximately $138.9 million of availability under our credit agreement. During the three month period ended December 31, 2010, we had average borrowings outstanding of approximately $35.7 million in relation to this credit agreement.

        Our obligations under the credit agreement are secured by substantially all of our assets, including the equity interests in our subsidiaries. Indebtedness under the credit agreement is guaranteed by us and all of our wholly owned subsidiaries.

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        Our credit agreement bears interest at either (1) LIBOR plus 3.0% to 3.5% per annum, depending on our leverage ratio, or (2) a base rate that is the sum of (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.5% or (c) LIBOR plus 1.0% and (ii) 1.5% to 2.0% per annum, depending on our leverage ratio. We incur letter of credit fees equal to the then applicable spread above LIBOR on the undrawn face amount of standby letters of credit and a 15 basis point fronting fee payable to the administrative agent on the aggregate face amount of such letters of credit. In addition, we incur a commitment fee on the unused portion of the credit agreement at a rate of 0.5% per annum. The credit agreement will mature in February 2013. At that time, the credit agreement will terminate and all outstanding amounts thereunder will be due and payable, unless the credit agreement is amended.

        Our credit agreement requires us to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. As of December 31, 2010, we are in compliance with respect to all covenants contained in the credit agreement.

Off-Balance Sheet Arrangements

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

        Federal and state laws require us to secure certain long-term obligations related to mine closure and reclamation costs. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of our credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank letters of credit in an amount of up to 25% of the aggregate bond liability. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

        As of December 31, 2010, we had $32.6 million in letters of credit outstanding, of which $29.7 million served as collateral for surety bonds.

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Contractual Obligations

        The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2010:

Critical Accounting Policies and Estimates

        Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates and judgments on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Nevertheless, actual results may differ from the estimates used and judgments made. Note 2 to the audited consolidated financial statements included elsewhere in this report provides a summary of all significant accounting policies and refer to Note 11 for information on our postretirement plan. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.

Partnership Environment and Risk Factors

        We, in the course of our business activities, are exposed to a number of risks, including: fluctuating market conditions of coal, truck and rail transportation, fuel costs, changing government regulations, unexpected maintenance and equipment failure, employee benefits cost control, changes in estimates of proven and probable coal reserves, as well as the ability of us to maintain adequate financing, necessary mining permits and control of sufficient recoverable coal properties. In addition, adverse weather and geological conditions may increase mining costs, sometimes substantially.

Investment in Joint Venture

        Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, our ability to exercise significant influence over the operating and financial policies of the investee and whether we are determined to be the primary beneficiary of a

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variable interest in an entity. Equity investments are recorded at original cost and adjusted periodically to recognize our proportionate share of the investees' net income or losses after the date of investment. When net losses from an equity method investment exceed its carrying amount, the investment balance is reduced to zero and additional losses are not provided for. We resume accounting for the investment under the equity method when the entity subsequently reports net income and our share of that net income exceeds the share of net losses not recognized during the period the equity method was suspended. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.

        In May 2008, we entered into a joint venture, Rhino Eastern, with an affiliate of Patriot to acquire the Rhino Eastern mining complex. To initially capitalize the joint venture, we contributed approximately $16.1 million for a 51% ownership interest in the joint venture, and we account for the investment in the joint venture and its results of operations under the equity method. We consider the operations of this entity to comprise a reporting segment and have provided supplemental detail related to this operation in Note 19 to the audited consolidated financial statements that are included elsewhere in this report.

        In determining that we were not the primary beneficiary of the variable interest entity for the years ended December 31, 2010, 2009 and 2008, we performed a qualitative and quantitative analysis of the variable interests in the joint venture. This included an analysis of the expected losses and residual returns of the joint venture. We concluded that we are not the primary beneficiary of the joint venture primarily because of certain contractual arrangements by the joint venture with Patriot. Mandatory pro rata additional contributions not to exceed $10 million in the aggregate could be required of the joint venture partners which we would be obligated to fund based upon our 51% ownership interest.

        As of December 31, 2010 and 2009, we have recorded our equity method investment of $18.7 million and $17.2 million, respectively, as a long-term asset. Our maximum exposure to losses associated with our involvement in this variable interest entity would be limited to our equity investment of $18.7 million as of December 31, 2010, plus any additional capital contributions, if required. We had not provided any additional contractually required support as of December 31, 2010; however, as disclosed in Note 17 to the audited consolidated financial statements that are included elsewhere in this report, we had provided a loan as of December 31, 2009 in the amount of $0.4 million to the joint venture that was fully repaid as of December 31, 2010.

Concentrations of Credit Risk

        We do not require collateral or other security on accounts receivable. Credit risk is controlled through credit approvals and monitoring procedures. Please read Note 15 to the audited consolidated financial statements included elsewhere in this report for a discussion of major customers.

Property, Plant and Equipment

        Property, plant, and equipment, including coal properties, mine development costs and construction costs, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Mining and other equipment and related facilities are depreciated using the straight-line method based upon the shorter of estimated useful lives of the assets or the estimated life of each mine. Coal properties are depleted using the units-of-production method, based on estimated proven and probable reserves. Mine development costs are amortized using the units-of-production method, based on estimated proven and probable reserves. Gains or losses arising from sales or retirements are included in current operations.

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        On March 30, 2005, the Financial Accounting Standards Board (FASB) ratified the consensus reached by the Emerging Issues Task Force, or EITF, on accounting for stripping costs in the mining industry. This accounting guidance applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the guidance, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. We have recorded stripping costs for all of our surface mines incurred during the production phase as variable production costs that are included in the cost of inventory produced. We define a surface mine as a location where we utilize operating assets necessary to extract coal, with the geographic boundary determined by property control, permit boundaries, and/or economic threshold limits. Multiple pits that share common infrastructure and processing equipment may be located within a single surface mine boundary, which can cover separate coal seams that typically are recovered incrementally as the overburden depth increases. In accordance with the accounting guidance for extractive mining activities, we define a mine in production as one from which saleable minerals have begun to be extracted (produced) from an ore body, regardless of the level of production; however, the production phase does not commence with the removal of de minimis saleable mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to an ore body. We capitalize only the development cost of the first pit at a mine site that may include multiple pits.

Asset Impairments

        We follow the accounting guidance on the impairment or disposal of property, plant and equipment which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets when potential impairment is indicated. When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, we must determine the fair value for the assets in question in accordance with the applicable fair value accounting guidance. Once the fair value is determined, the appropriate impairment loss must be recorded as the difference between the carrying amount of the assets and their respective fair values. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine's underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the mine closing accrual is increased accordingly. To the extent it is determined that asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. We recorded an impairment loss of $0.7 million in 2010 related to certain assets that are to be disposed of by sale. Please read Note 5 to the audited consolidated financial statements included elsewhere in this report for a discussion of this asset impairment loss recorded in 2010. There were no impairment losses recorded during the years ended December 31, 2009 and 2008.

Asset Retirement Obligations

        The accounting guidance for asset retirement obligations addresses asset retirement obligations that result from the acquisition, construction, or normal operation of long-lived assets. This guidance requires companies to recognize asset retirement obligations at fair value when the liability is incurred or acquired. Upon initial recognition of a liability, an amount equal to the liability is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We have recorded the asset retirement costs in coal properties.

        We estimate our future cost requirements for reclamation of land where we have conducted surface and underground mining operations, based on our interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground

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mines. Other reclamation costs are related to refuse and slurry ponds, as well as holding and related termination or exit costs.

        We expense contemporaneous reclamation which is performed prior to final mine closure. The establishment of the end of mine reclamation and closure liability is based upon permit requirements and requires significant estimates and assumptions, principally associated with regulatory requirements, costs and recoverable coal reserves. Annually, we review our end of mine reclamation and closure liability and make necessary adjustments, including mine plan and permit changes and revisions to cost and production levels to optimize mining and reclamation efficiency. When a mine life is shortened due to a change in the mine plan, mine closing obligations are accelerated, the related accrual is increased and the related asset is reviewed for impairment, accordingly.

        The adjustments to the liability from annual recosting reflect changes in expected timing, cash flow, and the discount rate used in the present value calculation of the liability. Changes in the asset retirement obligations for the year ended December 31, 2010 were calculated with a discount rate of 7.5% which changed from previous years due to changes in applicable market indicators that are used to arrive at an appropriate discount rate. Changes in the asset retirement obligations for the years ended December 31, 2009 and 2008 were calculated with the same discount rate of 10%. Other recosting adjustments to the liability are made annually based on inflationary cost increases and changes in the expected operating periods of the mines.

Workers' Compensation Benefits

        Certain of our subsidiaries are liable under federal and state laws to pay workers' compensation and coal workers' pneumoconiosis ("black lung") benefits to eligible employees, former employees and their dependents. We currently utilize an insurance program and state workers' compensation fund participation to secure our on-going obligations depending on the location of the operation. Premium expense for workers' compensation benefits is recognized in the period in which the related insurance coverage is provided.

Revenue Recognition

        Most of our revenues are generated under supply contracts with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the supply contract. Under the typical terms of these contracts, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation source that delivers coal to its destination. Advance payments are deferred and recognized in revenue as coal is shipped and title has passed.

        Coal revenues also result from the sale of brokered coal produced by others. The revenues related to brokered coal sales are included in coal revenues on a gross basis and the corresponding cost of the coal from the supplier is recorded in cost of coal sales in accordance with the revenue recognition accounting guidance on principal agent considerations.

        Freight and handling costs paid directly to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.

        Other revenues generally consist of limestone sales, coal handling and processing, rebates and rental income. With respect to other revenues recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the seller's price to the buyer is fixed or determinable and collectibility

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is reasonably assured. Advance payments received are deferred and recognized in revenue when earned.

Derivative Financial Instruments

        During the year ended December 31, 2008, we used futures contracts to manage the risk of fluctuations in the sales price of coal. We did not use derivative financial instruments for trading or speculative purposes. We recorded the derivative financial instruments as either assets or liabilities, at fair value, in accordance with the accounting guidance on derivatives and hedging. All futures contracts were settled as of December 31, 2008. We also use diesel fuel forward contracts to manage the risk of fluctuations in the cost of diesel fuel. Our diesel fuel forward contracts qualify for the normal purchase normal sale, or NPNS, exception prescribed by the accounting guidance on derivatives and hedging, based on management's intent and ability to take physical delivery of the diesel fuel.

Income Taxes

        We are considered a partnership for income tax purposes. Accordingly, the partners report our taxable income or loss on their individual tax returns.

Recent Accounting Pronouncements

        Effective January 1, 2008, we adopted the accounting guidance that clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements (codified as ASC Topic 820, Fair Value Measurements and Disclosures). This fair value accounting guidance applies whenever other accounting guidance requires or permits assets or liabilities to be measured at fair value. The fair value accounting requirements for certain non-financial assets and liabilities were permitted to be deferred until the first quarter of 2009 in accordance with the FASB published guidance. We adopted this new guidance effective January 1, 2009, and at the time of the adoption, there were no nonfinancial assets or nonfinancial liabilities that were measured at fair value on a nonrecurring basis. The fair value accounting guidance establishes the following fair value hierarchy that prioritizes the inputs used to measure fair value:

•

Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.



•

Level 2—Inputs other than Level 1 that are based on observable market data, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets, quoted prices for identical assets or liabilities in inactive markets, inputs that are observable that are not prices and inputs that are derived from or corroborated by observable markets.



•

Level 3—Developed from unobservable data, reflecting an entity's own assumptions.

        ASC Topic 805, "Business Combinations", among other things, provides guidance for the way companies account for business combinations. This guidance requires transaction-related costs to be expensed as incurred, which were previously accounted for as a cost of acquisition. ASC Topic 805 also requires acquirers to estimate the acquisition-date fair value of any contingent consideration and recognize any subsequent changes in the fair value of contingent consideration in earnings. In addition, restructuring costs the acquirer was not obligated to incur shall be recognized separately from the business acquisition. We adopted this guidance on a prospective basis as of January 1, 2009. The adoption of this guidance did not require remeasurement of any prior balances but will impact accounting for business combinations after date of adoption. This guidance was applied to the purchase accounting of Triad Roof Support Systems LLC and C.W. Mining Company.

        ASC Topic 810, "Consolidation", requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated financial statements. A single method of accounting has been established for changes in a parent's ownership interest in a subsidiary

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that do not result in deconsolidation. Companies no longer recognize a gain or loss on partial disposals of a subsidiary where control is retained. In addition, in partial acquisitions where control is obtained, the acquiring company will recognize and measure at fair value 100% of the assets and liabilities, including goodwill, as if the entire target company had been acquired. We adopted this guidance as of January 1, 2009.

        In May 2009, the FASB issued guidance under ASC Topic 855,"Subsequent Events", which provided general accounting standards for the disclosure of events that occur after the balance sheet date but before the financial statements are issued or available for issue. This guidance does not apply to subsequent events or transactions that are within the scope of other generally accepted accounting principles that provide different guidance on the accounting treatment of subsequent events. ASC Topic 855 includes a new required disclosure of the date through which an entity, other than a public filer, has evaluated subsequent events and the basis for that date. Such disclosures are required for financial statements issued after June 15, 2009 and are included in our consolidated financial statements.

        In June 2009, the FASB issued guidance under ASC Topic 810, "Consolidation", which amended the consolidation guidance for variable interest entities, or VIEs. The new guidance requires a company to perform an analysis to determine whether its variable interest gives it a controlling financial interest in a VIE. The amendment, which requires ongoing reassessments, redefines the primary beneficiary as the party that (1) has the power to direct the activities of a VIE that most significantly impact the entity's economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The guidance includes enhanced disclosures about a company's involvement in a VIE and also eliminates the exemption for qualifying special purpose entities. We evaluated this guidance and determined that certain criteria is not met for consolidation of the VIE and will continue to report the results of the VIE using the equity method of accounting.

        ASC 260, "Earnings Per Share", affects how a master limited partnership, or MLP, allocates income between its general partner, which typically holds incentive distribution rights, along with the general partner interest, and the limited partners. It is not uncommon for MLPs to experience timing differences between the recognition of income and partnership distributions. The amount of incentive distributions is typically calculated based on the amount of distributions paid to the MLP's partners. The issue is whether current period earnings of an MLP should be allocated to the holders of incentive distribution rights as well as the holders of the general and limited partner interests when applying the two-class method. The conclusion was that when current period earnings are in excess of cash distributions, the undistributed earnings should be allocated to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders based upon the terms of the partnership agreement. Under this model, contractual limitations on distributions to holders of incentive distribution rights would be considered when determining the amount of earnings to allocate to them. That is, undistributed earnings would not be considered available cash for purposes of allocating earnings to incentive distribution rights holders. Conversely, when cash distributions are in excess of earnings, net income (or loss) should be reduced (increased) by the distributions made to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders. The resulting net loss would then be allocated to the holders of the general partner interest and the holders of the limited partner interest based on their respective sharing of the losses based upon the terms of the partnership agreement. This guidance is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The accounting treatment is effective for all financial statements presented.

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Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

        Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity risk and interest rate risk.

Commodity Price Risk

        We manage our commodity price risk for coal sales through the use of supply contracts and the use of forward contracts.

        Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward purchases to manage the exposure related to this volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income by $0.6 million for the year ended December 31, 2010. A hypothetical increase of 10% in steel prices would have reduced net income by $1.3 million for the year ended December 31, 2010. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.5 million for the year ended December 31, 2010.

Interest Rate Risk

        We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. During the past year, we have been operating in a period of declining interest rates, and we have managed to take advantage of the trend to reduce our interest expense. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $0.8 million for the year ended December 31, 2010.

Item 8.    Financial Statements and Supplementary Data.

        The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-1 through F-33 of this report and are incorporated herein by reference.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

        None.

Item 9A.    Controls and Procedures.

(a)   Disclosure Controls and Procedures.

        Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our controls and procedures were effective as of December 31, 2010. For purposes of this section, the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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(b)   Changes in Internal Control Over Financial Reporting.

        There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

        This annual report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Item 9B.    Other Information.

        On July 21, 2010, the Dodd-Frank Wall Street and Consumer Protection Act (the "Dodd-Frank Act") was enacted into federal law. Section 1503(a) of the Dodd-Frank Act requires a reporting company operating coal mines or with subsidiaries that operate coal mines to file in its periodic reports certain mine health and safety information as specified therein covering the period of such reports. Please see Exhibit 99.1 of this report for such mine health and safety disclosure relating to the quarter and year ended December 31, 2010.

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

Management of Rhino Resource Partners LP

        We are managed and operated by the board of directors and executive officers of our general partner, Rhino GP LLC. Employees of our general partner devote substantially all of their time and effort to our business. As a result of owning our general partner, Wexford has the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders are not entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse.

        Our general partner has nine directors, three of whom, Messrs. Plaumann, Lambert and Tompkins are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a publicly traded limited partnership, like us, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/corporate governance committee. We are, however, required to have an audit committee of at least three members, and all of its members are required to be independent as defined by the NYSE and the Exchange Act.

        When evaluating a candidate's suitability for a position on the board, Wexford assesses whether such candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board's ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties..

Executive Officers and Directors

        The following table shows information for the executive officers and directors of our general partner as of December 31, 2010:

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        Mark D. Zand.    Mr. Zand has served as the Chairman of our general partner's board of directors since January 2010 and serves as a member of our general partner's compensation committee. He is a partner of Wexford Capital. Mr. Zand joined Wexford Capital in 1996 and became a partner in 2001. He is involved in fixed income and distressed securities research and trading, and in public and private equity investing. Mr. Zand has been actively involved with Wexford Capital's coal investments since its inception. Mr. Zand was selected to serve as a director due to his in-depth knowledge of our business, including our strategies, operations, finances and markets, as well as his significant knowledge of the coal industry. Since our inception, Mr. Zand has been an integral part of our growth and expansion and we believe he will continue to provide valuable guidance to the board of directors of our general partner. In addition, he has served on the boards and creditors' committees of a number of private companies.

        David G. Zatezalo.    Mr. Zatezalo has served as President and Chief Executive Officer of our general partner since May 2010, as well as a director of our general partner since July 2010. He has served as President and Chief Executive Officer of Rhino Energy LLC since September 2009. From March 2007 to September 2009, Mr. Zatezalo served as Chief Operating Officer of Rhino Energy LLC. Prior to March 2007, Mr. Zatezalo served as President of our subsidiary Hopedale Mining LLC. Prior to joining Rhino Energy LLC, Mr. Zatezalo served as President of AEP's various Appalachian Mining Operations and as General Manager of Windsor Coal Company from 1998 to May 2004. He previously served as General Manager of the Cliff Collieries and Manager of Underground Development in the Bowen Basin of Queensland for BHP Australia Coal. Additionally, Mr. Zatezalo has served as Chairman of the Ohio Coal Association and is currently a member of the executive committee of the Kentucky Coal Association. In total, Mr. Zatezalo has approximately 37 years of experience in the coal industry. Mr. Zatezalo was selected to be a director of our general partner due to his extensive background and familiarity with the coal industry and his leadership position as President and Chief Executive Officer.

        Richard A. Boone.    Mr. Boone has served as Senior Vice President and Chief Financial Officer of our general partner since May 2010, and as Senior Vice President and Chief Financial Officer of Rhino Energy LLC since February 2005. Prior to joining Rhino Energy LLC, he served as Vice President and Corporate Controller of PinnOak Resources, LLC, a coal producer serving the steel making industry, since 2003. Prior to joining PinnOak Resources, LLC, he served as Vice President, Treasurer and Corporate Controller of Horizon Natural Resources Company, a producer of steam and metallurgical coal, since 1998. In total, Mr. Boone has approximately 30 years of experience in the coal industry.

        Christopher N. Moravec.    Mr. Moravec has served as Executive Vice President of our general partner since May 2010 and as Executive Vice President of Rhino Energy LLC since April 2010, prior to which he served as Senior Vice President of Business Development of Rhino Energy LLC beginning in March 2007 and President of Kentucky Operations beginning in September 2009. Mr. Moravec also oversees our sales efforts and is a board member of our Rhino Eastern joint venture. Prior to joining Rhino Energy LLC, he was employed by PNC Bank for more than 22 years, most recently serving as Senior Vice President and Managing Director, where he was responsible for providing investment and commercial banking services primarily to the domestic coal industry. In total, Mr. Moravec has approximately 35 years of experience in the coal industry.

        Andrew W. Cox.    Mr. Cox has served as our general partner's and Rhino Energy LLC's Vice President of Sales since May 2010 and January 2007, respectively. Prior to joining Rhino Energy LLC, he was Sales Director for Coal Marketing Company (USA) Inc., a wholly owned subsidiary of CMC Ltd., a Dublin, Ireland based coal sales company which sells and markets coal from Colombia, South America. Prior to joining CMC Ltd. in September 2004, he was a Vice President with AMVEST Coal Sales Company and also held various sales and marketing positions with Cumberland River

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Energies Inc., Mingo Logan Coal Company, Old Ben Coal Company and NERCO Coal Sales LLC. In total, Mr. Cox has approximately 29 years of experience in the coal industry.

        Reford C. Hunt.    Mr. Hunt has served as our general partner's Vice President of Technical Services since May 2010. Since April 2005 Mr. Hunt has served in various capacities with Rhino Energy LLC and its subsidiaries, including as Chief Engineer and Director of Operations. Mr. Hunt currently serves as Vice President of Technical Services of Rhino Energy LLC, a position he has held since August 2008, as President of Rhino Energy WV LLC and McClane Canyon Mining LLC since September 2009 and as President of Castle Valley Mining LLC since August 2010. Prior to joining Rhino Energy LLC, Mr. Hunt was employed by Sidney Coal Company, a subsidiary of Massey Energy Company, from 1997 to 2005. During his time at Sidney Coal Company as a Mining Engineer, he oversaw planning, engineering, and construction for various mining and preparation operations. In total, Mr. Hunt has approximately 14 years of experience in the coal industry.

        Joseph R. Miller.    Mr. Miller has served as our general partner's Vice President, Secretary and General Counsel since May 2010. From January 2007 until March 2009 he served as Rhino Energy LLC's Vice President and was also named Secretary and General Counsel in March 2009. Prior to joining Rhino Energy LLC, Mr. Miller practiced law with Frost Brown Todd in Lexington, Kentucky, from 2002 to 2007, with a substantial portion of his practice devoted to coal industry matters. Mr. Miller is a member of the Kentucky Bar Association.

        Joseph M. Jacobs.    Mr. Jacobs has served as a director of our general partner since July 2010. Mr. Jacobs is the President of Wexford Capital, which he co-founded in 1994. From 1982 to 1994, Mr. Jacobs was employed by Bear Stearns & Co., Inc., where he attained the position of Senior Managing Director. From 1979 to 1982, he was employed as a commercial lending officer at Citibank, N.A. Mr. Jacobs served as a director for ICx Technologies, Inc. until August 2010, Republic Airways Holding Company until June 2008 and Azul S.A. until January 2010, and has served on the boards and creditors' committees of a number of public and private companies in which Wexford Capital has held investments. Mr. Jacobs holds an M.B.A. from Harvard Business School and a B.S. in Economics from the Wharton School of the University of Pennsylvania. Mr. Jacobs was selected to serve as a director due to his significant service on the boards of other public and private companies, which provides a thorough understanding of board roles and responsibilities and widespread knowledge of various industries, businesses, operations, opportunities and risks. Mr. Jacobs' current position as President of Wexford Capital also provides a comprehensive knowledge of management strategy and policy.

        Jay L. Maymudes.    Mr. Maymudes has served as a director of our general partner since January 2010 and serves as a member of our general partner's compensation committee. He joined Wexford Capital in 1994 and became a partner in 1997 and serves as Wexford Capital's Chief Financial Officer. Mr. Maymudes is responsible for the financial, tax and reporting requirements of Wexford Capital and all of its private investment partnerships and its trading activities. Mr. Maymudes is a Certified Public Accountant. Mr. Maymudes was selected to serve as a director due to his credentials and qualifications in the area of public and financial accounting. Mr. Maymudes has particular skills in corporate finance, corporate governance, compliance, disclosure and compensation matters and has extensive experience in capital market transactions, which we believe provides valuable expertise and insight to the board of directors of our general partner. In addition, Mr. Maymudes has sat on the boards of a number of public and private companies.

        Arthur H. Amron.    Mr. Amron has served as a director of our general partner since January 2010. He joined Wexford Capital as General Counsel in 1994 and became a partner in 1999. Mr. Amron is responsible for legal and securities compliance and actively participates in various private equity transactions, particularly in the bankruptcy and restructuring areas. Mr. Amron was selected to serve as a director due to his experience with us, his background as a corporate and transactional lawyer and his familiarity with mergers and acquisitions transactions, public offerings, financings, and other capital

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markets and financial transactions, which we believe provides valuable expertise and insight to the board of directors of our general partner. In his capacity as Wexford Capital's General Counsel, Mr. Amron has been involved with us since our formation and is familiar with many of the transactions we have undertaken prior to this offering. In addition, Mr. Amron has served on the boards of other public and private companies in which Wexford Capital has invested.

        Kenneth A. Rubin.    Mr. Rubin has served as a director of our general partner since January 2010. He joined Wexford Capital in 1996 and became a partner in 2001 and serves as the portfolio manager of the Wexford Global Strategies Fund. Mr. Rubin focuses on investment grade and government fixed income investments. Mr. Rubin was selected to serve as a director due to his long-term experience in the capital and investment markets. Mr. Rubin brings to the board of directors of our general partner an understanding of our business, history and organization. Mr. Rubin has been on the boards of public and private companies.

        Mark L. Plaumann.    Mr. Plaumann has served as a director of our general partner, as the chair of our general partner's audit committee and as a member of our general partner's conflicts committee since October 2010. He is currently a Managing Member of Greyhawke Capital Advisors LLC, or Greyhawke, which he co-founded in 1998. Prior to founding Greyhawke, Mr. Plaumann was a Senior Vice President of Wexford Capital. Mr. Plaumann was formerly a Managing Director of Alvarez & Marsal, Inc. and the President of American Healthcare Management, Inc. He also earned the position of Senior Manager at Ernst & Young LLP. Mr. Plaumann holds an M.B.A. and a B.A. in Business from the University of Central Florida. Mr. Plaumann served as a director and audit committee chairman for ICx Technologies, Inc. until October 2010 and currently serves as a director and audit committee chairman of Republic Airways Holdings, Inc., and a director of one private company. Mr. Plaumann was selected to serve as a director of our general partner due to his significant financial and audit expertise. Mr. Plaumann's service on the boards of other public companies, including previous experience as chairman of audit committees, gives him a clear understanding of his role and responsibilities on our general partner's board of directors.

        Douglas Lambert.    Mr. Lambert has served as a director of our general partner and as a member of our general partner's audit committee and conflicts committee since October 2010. He is presently a Managing Director in the North American Restructuring Practice Group of Alvarez & Marsal Inc., a position he has held since November 2006, and has served as Chief Executive Officer of Legacy Asset Management Company, a wholly-owned subsidiary of Lehman Brothers Holdings, Inc. since May 2010. Mr. Lambert has been a director of Republic Airways Holdings, Inc., an airline holding company, since 2001. From 1994 to 2003, Mr. Lambert was a Senior Vice President of Wexford Capital. From 1983 to 1994, Mr. Lambert held various financial positions with Integrated Resources, Inc.'s Equipment Leasing Group, including Treasurer and Chief Financial Officer. Mr. Lambert is a member of the American Institute of Certified Public Accountants and the New York State Society of Certified Public Accountants. Mr. Lambert was chosen to serve as a director due to his strong and diverse financial and operational background in a variety of different businesses and industries.

        James F. Tompkins.    Mr. Tompkins has served as a director of our general partner and as a member of our general partner's audit committee and conflicts committee since October 2010. He is currently the President of JFT Consultants, LLC, a firm that provides consulting services to the coal and associated industries and which Mr. Tompkins founded in 1997. Prior to founding JFT Consultants, Mr. Tompkins served as a Vice President of the Southern Ohio Coal Company. Mr. Tompkins also worked in the mining industry in West Virginia, Nova Scotia, and Manitoba. Mr. Tompkins earned a Bachelor of Mining Engineering degree from Dalhousie University (DalTech) in 1971 and an M.A. in Interpersonal Communication from Ohio University in 1997. He is a member of the Ohio Chapter of the Society of Mining Engineers and a member of the Mining Society of Nova Scotia. Mr. Tompkins has served on several non-profit boards in southern Ohio. Mr. Tompkins was selected to serve as a

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director of our general partner due to his extensive operational and engineering expertise in the coal industry, as well as his financial experience.

Director Independence

        The board of directors of our general partners has determined that each of Messrs. Plaumann, Lambert and Tompkins are independent as defined under the independence standards established by the NYSE and the Exchange Act. In evaluating director independence with respect to Mr. Plaumann and Mr. Lambert, the board of directors of our general partner considered the various relationships each of them has with Wexford Capital and its affiliates. Certain affiliated investment funds of Wexford Capital were the majority owners of ICx Technologies, Inc. until October 2010. As described above, Mr. Plaumann served as an independent director and audit committee chairman of ICx Technologies, Inc. until October 2010. In addition, as described below, both Mr. Plaumann and Mr. Lambert were former employees of Wexford Capital and continue to hold small interests in Wexford Capital private equity funds in connection with investments that were made at the time each of them was employed by Wexford Capital. Certain of these funds hold an interest in Rhino Energy Holdings LLC, which beneficially owns an aggregate 83.8% of our outstanding units. Mr. Plaumann's and Mr. Lambert's indirect beneficial interest in Rhino Energy Holdings LLC through these funds is immaterial. The board of directors of our general partner considered these relationships in light of the attributes it believes need to be possessed by independent-minded directors, including personal financial substance and a lack of economic dependence on us. The board of directors of our general partner concluded that each of Mr. Plaumann's and Mr. Lambert's relationships, rather than interfering with their ability to be independent from management, are consistent with the business and financial substance that make them qualified, independent directors.

Meetings; Committees of the Board of Directors

        The board of directors of our general partner held one meeting during the portion of the quarter ended December 31, 2010 for which we were publicly-traded. All of the directors attended the meeting. The board of directors of our general partner has an audit committee, a conflicts committee and, although not required by the NYSE, a compensation committee.

Audit Committee

        The audit committee of our general partner has been established in accordance with Section 3(a)(58)(A) of the Exchange Act, and consists of Messrs. Plaumann, Lambert and Tompkins, all of whom are independent. The board of directors of our general partner has determined Mr. Plaumann is an "audit committee financial expert" within the meaning of the SEC rules. Our audit committee operates pursuant to a written charter, an electronic copy of which is available on our website at http://www.rhinolp.com. This committee oversees, reviews, acts on and reports to our board of directors of our general partner on various auditing and accounting matters, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements.

Compensation Committee

        The compensation committee of our general partner consists of Messrs. Zand and Maymudes, and operates pursuant to a written charter. This committee establishes salaries, incentives and other forms of compensation for officers and other employees. The compensation committee also administers our incentive compensation and benefit plans.

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Conflicts Committee

        Messrs. Plaumann, Lambert and Tompkins serve on the conflicts committee to review specific matters that the board believes may involve conflicts of interest and determine to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be directors, officers or employees of our general partner or any person controlling our general partner, including Wexford Capital, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Executive Sessions of Non-Management Directors; Procedure for Contacting the Board of Directors

        The board of directors of our general partner plans to hold regular executive sessions in which the three independent directors meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the independent directors. The rules of the NYSE require that one of the independent directors must preside over each executive session, and the role of presiding director is rotated among each of the independent directors.

        A means for interested parties to contact the Board of Directors (including the independent directors as a group) directly has been established in the general partner's Corporate Governance Guidelines, published on our website at www.rhinolp.com. Information may be submitted confidentially and anonymously, although we may be obligated by law to disclose the information or identity of the person providing the information in connection with government or private legal actions and in certain other circumstances.

Code of Ethics

        We have adopted a Code of Business Conduct and Ethics that applies to all of our officers, directors and employees. An electronic copy of the code is available on our website at http://www.rhinolp.com. For a discussion on what other corporate governance materials are posted on our website, see Part I, Item 1. "Business—Available Information."

Section 16(a) Beneficial Ownership Reporting Compliance

        Section 16(a) of the Exchange Act requires directors, executive officer and persons who beneficially own more than 10% of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. Based upon a review of the copies of the forms furnished to us and written representations from certain reporting persons, we believe that, during the year ended December 31, 2010, none of our executive officers, directors or beneficial owners of more than 10% of any class of registered equity security failed to file on a timely basis any such report.

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Item 11.    Executive Compensation

Compensation Discussion and Analysis

Introduction

        Our general partner has the sole responsibility for conducting our business and for managing our operations and its board of directors and officers make decisions on our behalf. For this reason, prior to our public offering, we did not form a compensation committee. However, in connection with the completion of our IPO the board of directors of our general partner formed a compensation committee, effective September 30, 2010, to determine the future compensation of the directors and officers of our general partner, including its named executive officers. The compensation payable to the officers of our general partner is paid by our general partner and such payments are reimbursed by us on a dollar-for-dollar basis.

        For the year ended December 31, 2010, the President and Chief Executive Officer of our general partner made all decisions regarding the compensation of the executive officers of our general partner pursuant to the terms of the employment agreements entered into with those executives. In 2010, the named executive officers of our general partner were:

•

David G. Zatezalo—President and Chief Executive Officer;



•

Richard A. Boone—Senior Vice President and Chief Financial Officer;



•

Christopher N. Moravec—Executive Vice President;



•

Andrew W. Cox—Vice President of Sales; and



•

Reford C. Hunt—Vice President of Technical Services and President of a number of our operating subsidiaries.

        With respect to the compensation disclosures in this Compensation Discussion and Analysis and the tables that follow, these individuals are referred to as the "named executive officers." The historical compensation discussion that follows reflects the total compensation the named executive officers received for services provided to Rhino Energy LLC, and the philosophy and policies of Rhino Energy LLC that drove the compensation decisions for these named executive officers, as implemented by the President and Chief Executive Officer of Rhino Energy LLC prior to the completion of our IPO in October 2010. The compensation philosophy, policy and practices of our general partner and the procedures adopted by our general partner are also described below, although these practices are largely a continuation of the compensation practices employed by Rhino Energy LLC. Specific changes that were made to our compensatory policies as a result of the completion of our IPO are noted below. Unless otherwise noted, within the remainder of this Compensation Discussion and Analysis, references to "we" and "our" refer to both the philosophy and policies implemented by our predecessor, Rhino Energy LLC, as well as the philosophy and policies implemented by our general partner upon completion of our IPO. The philosophy and policies may change in the future.

Compensation Philosophy and Objectives

        We employ a compensation philosophy that emphasizes pay for performance and reflects what the current market dictates. The executive compensation program applicable to the named executive officers is designed to provide a total compensation package that allows us to attract, retain and motivate the executives necessary to manage our business. Our general philosophy and program is guided by several key principles:

•

designing competitive total compensation programs to enhance our ability to attract and retain knowledgeable and experienced senior management level employees;

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•

motivating employees to deliver outstanding financial performance and meet or exceed general and specific business, operational, and individual objectives; and



•

setting compensation and incentive levels relevant to the market in which the employee provides service.

        Our executive compensation program is also designed to ensure that a portion of the total compensation made available to the named executive officers is determined by increases in equity value, thereby assuring an alignment of interests between our senior management level employees and our unitholders.

        By accomplishing these objectives, we hope to optimize long-term unitholder value.

Compensation Setting Process

        Historically and during the first three fiscal quarters of 2010, the President and Chief Executive Officer of Rhino Energy LLC determined the overall compensation philosophy and set the final compensation of the named executive officers without the assistance of a compensation consultant. Following the formation of the compensation committee by the board of our general partner as of September 30, 2010, all compensation decisions for the named executive officers are determined by the compensation committee (consistent with the employment agreements that we have entered into with the named executive officers described below in the section titled "—Elements of Compensation—Employment Agreements").

        Our compensation committee seeks to provide a total compensation package designed to drive performance and reward contributions in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us. Our compensation committee did not make any compensation-related decisions with respect to the compensation of our named executive officers for fiscal 2010 (other than determining the amount of bonuses payable to the named executive officers at year-end 2010 and the approval of certain phantom unit awards made in connection with the IPO); however, it is possible that in the future the compensation committee will examine the compensation practices of our peer companies and may also review compensation data from the coal industry generally to the extent the competition for executive talent is broader than a group of selected peer companies. To date, the compensation committee has not made any decisions regarding possible benchmarking. In addition, the compensation committee may review and, in certain cases, participate in, various relevant compensation surveys and consult with compensation consultants with respect to determining compensation for the named executive officers. For instance, we participated in a compensation survey prepared by Lockton Companies, LLC covering 26 public and private companies in the coal industry, effective as of August 1, 2010 and published January 1, 2011, and we anticipate that, in setting future compensation, our compensation committee may consider this or other relevant surveys in determining appropriate pay levels. We expect that our President and Chief Executive Officer, Mr. Zatezalo, will provide periodic recommendations to the compensation committee regarding the compensation of the other named executive officers. The compensation committee reviews the compensation structure for the named executive officers of our general partner on an annual basis; however, to date, no changes have been made to the compensation of our named executive officers, except that Andrew Cox entered into a new employment agreement with us, effective January 14, 2011. See "—Elements of Compensation—Employment Agreements" below for additional information.

Elements of Compensation

        The following discussion regarding the elements of compensation provided to the named executive officers reflects our historical philosophy concerning the division of the elements of senior management

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level employees' compensation packages, which our general partner, at this time, continues to employ with the modifications noted below.

        The principal elements of compensation for the named executive officers are:

•

base salary;



•

bonus awards;



•

long-term equity based incentive awards (only since the completion of our IPO); and



•

nondiscriminatory welfare and retirement benefits.

        We believe a material amount of executive compensation should be tied to our performance, and a significant portion of the total prospective compensation of each named executive officer should be tied to measurable financial and operational objectives. These objectives may include absolute performance or performance relative to a peer group. During periods when performance meets or exceeds established objectives, the named executive officers should be paid at or above targeted levels, respectively. When our performance does not meet key objectives, incentive award payments, if any, should be less than such targeted levels.

        Historically, our compensation program has predominately been focused on retention and the achievement of strong short-term annual results. The preponderance of these short-term incentives have been in the form of discretionary cash bonuses based on both objective performance criteria and subjective criteria. In light of the recent completion of our IPO, the compensation committee seeks to balance awards based on short-term annual results with awards intended to compensate our executives based on our long-term viability and success. Consequently, long-term equity-based awards were made to our named executive officers in connection with the completion of the IPO and we anticipate that, in the future, we will periodically provide long-term incentives to our executives in the form of additional long-term equity-based awards to further align the interests of the named executive officers with those of our unitholders. Our general partner believes that awards under its long-term incentive plan (the "LTIP") further incentivize the named executive officers to perform their duties in a way that will enhance our long-term success.

        Our compensation committee determines the mix of compensation, both among short-term and long-term compensation and cash and non-cash compensation, to establish compensation packages that it believes are appropriate for each of the named executive officers. We believe that the mix of base salary, bonus awards, awards under the LTIP and the other benefits that are available to our named executive officers effectively accomplish our overall compensation objectives. We believe the elements of compensation provided create competitive compensation opportunities to align and drive employee performance in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us.

Employment Agreements

        We have entered into employment agreements with each of the named executive officers. Our employment agreements typically provide for a three year term, which may be earlier terminated in accordance with the terms of the applicable agreement or extended by mutual agreement of the parties. The terms of these employment agreements are described in greater detail below in the section entitled "—Narrative Discussion of Summary Compensation Table and Grants of Plan-Based Awards Table—Employment Agreements."

        We entered into amended and restated employment agreements with Messrs. Zatezalo and Moravec effective January 1, 2010 and March 31, 2010, respectively. The amended and restated employment agreements are substantially similar to the prior agreements in effect with Messrs. Zatezalo and Moravec. The amended and restated employment agreement with Mr. Zatezalo

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will expire on December 31, 2012, and the amended and restated employment agreement with Mr. Moravec will expire on March 31, 2013. The amended and restated employment agreements specify the annual base salaries and annual bonus opportunities for Messrs. Zatezalo and Moravec, and Mr. Zatezalo's agreement provides for automatic salary increases in calendar years 2011 and 2012. The amended and restated employment agreements also provide Messrs. Zatezalo and Moravec with the opportunity to participate in the employee benefit arrangements offered to similarly situated employees and provide that they may periodically receive grants pursuant to the LTIP as determined in our general partner's discretion. Effective January 14, 2011, we entered into an amended and restated employment agreement with Mr. Cox which is substantially similar to his prior agreement. The new agreement with Mr. Cox extends his employment term to December 31, 2013 and increases his annual base salary rate to $220,000 per year, but otherwise does not impact the material terms of his agreement.

        The severance benefits provided by the employment agreements with the named executive officers are described below in the section titled "—Potential Payments Upon Termination or Change in Control—Employment Agreements." The employment agreements also contain certain confidentiality, noncompetition, and other restrictive covenants, which are also described in the section titled "—Potential Payments Upon Termination or Change in Control—Employment Agreements."

        Base Salary.    The base salaries set forth in the employment agreements were established based on various factors, including the amounts we considered necessary to attract and retain the highest quality executives, the responsibilities of the named executive officers and the historic compensation of our executives. Our compensation committee reviews the base salaries of our named executive officers on an annual basis and may adjust base salaries consistent with the employment agreements. As part of its review, the compensation committee may review the compensation of executives in similar positions with similar responsibility in any peer companies identified by the compensation committee or in companies in the coal industry with which we generally compete for executives. While our compensation committee will consider all of the foregoing factors in determining the appropriate amount of base salary for each named executive officer, ultimately the minimum base salary established for each individual officer was determined through negotiations with the individual and is set at the level necessary to retain the executive's services. In accordance with his employment agreement, Mr. Zatezalo's base salary increased to $500,000 effective for fiscal year 2011. To date, the compensation committee has not increased the base salary of any other named executive officer for fiscal year 2011, other than Mr. Cox, whose base salary rate increased to $220,000 in connection with his amended and restated employment agreement.

        Bonus Awards.    Historically, annual bonuses have been discretionary. We review annual cash bonus awards for the named executive officers and other executives annually to determine award payments for the last completed fiscal year, as well as to establish award opportunities for the current fiscal year. At the beginning of each year, we meet with executives to discuss company goals for the year and what each executive is expected to contribute in order to help us achieve those goals. Our bonuses for 2010 were determined by the compensation committee at year-end following a review of the individual performance of the executive officer in question, the past compensation paid to the executive officer, and our overall performance, including our performance with respect to various safety measures and our profitability for the year; however, no specific pre-established performance objectives are set and, ultimately, the amount of the annual bonuses is determined in the discretion of the compensation committee. Although there were no specified financial, operational or individual performance objectives for the 2010 annual bonuses, approximately one-half of the annual discretionary bonus amount payable to each named executive officer was determined based on the bonus amounts actually received by the employees supervised by the named executive officer and the other one-half of the annual bonus amount was purely discretionary. In addition, Mr. Moravec has been entitled to

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receive additional annual term bonuses pursuant to his prior employment agreement beginning in 2008 and ending in March 2010.

        Consistent with our historical practice, we have retained a maximum bonus threshold of 40% for most of our named executive officers. Pursuant to the employment agreements with each of the named executive officers, the annual bonus actually awarded to a named executive officer for a given fiscal year may be up to 40% of his annual salary (up to 150% of annual base salary in the case of Mr. Zatezalo). Historically, the Chief Executive Officer of our general partner has been entitled to receive significant guaranteed payments, including guaranteed bonus payments; however, in order to incentivize Mr. Zatezalo to improve our performance, we have structured a large portion of his cash compensation to be a discretionary, performance-based bonus of up to 150% of his annual base salary.

        During 2010, in connection with the consummation of our IPO, the named executive officers (other than Mr. Cox) also received certain one-time cash bonuses. The amount of these bonuses is approximately $250,000 for Mr. Zatezalo, approximately $150,000 for Messrs. Boone and Moravec, and approximately $100,000 for Mr. Hunt. These amounts were ultimately determined on a discretionary basis to be appropriate to reward the contributions of these individuals in connection with the IPO.

        In the near future we expect our compensation committee will continue to rely on discretionary annual bonus awards to the named executive officers. In addition, Mr. Moravec's employment agreement also provides that he is entitled to a guaranteed annual bonus of $200,000 for each year of the three year term of his agreement, payable in bi-weekly installments in accordance with our general payroll practices. Because we agreed to provide Mr. Moravec with a guaranteed annual bonus in his amended and restated employment agreement, we significantly reduced the size of the phantom unit award granted to him under the LTIP in connection with our IPO. See "—Compensation Discussion and Analysis—Elements of Compensation—Long-Term Incentive Compensation."

        The following table sets forth the annual rate of salary payable for fiscal 2010 and potential bonus amounts for the named executive officers pursuant to the employment agreements that were in effect following the completion of our IPO:

        Severance and Change in Control Benefits.    The employment agreements with the named executive officers (other than Mr. Hunt) provide such individuals with certain severance benefits upon an involuntary termination, including, in some cases, upon a termination due to death. We believe it is appropriate to provide these severance benefits in recognition of the fact that it may be difficult for the named executive officers to find comparable employment within a short period of time if they are involuntarily terminated. The severance and benefits provided under the employment agreements are described in greater detail below. Please read "—Potential Payments Upon Termination or Change in Control—Employment Agreements."

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Long-Term Incentive Compensation

        Prior to fiscal 2010, equity based compensation was not an element of the compensation provided to our employees. However, in connection with our IPO, the board of directors of our general partner adopted the LTIP for our employees, consultants and directors and those of our affiliates who perform services for us. Each of the named executive officers is eligible to participate in the LTIP. The LTIP provides for the grant of restricted units, unit options, unit appreciation rights, phantom units, unit payments, other equity-based awards and performance awards.

        In connection with our IPO, the named executive officers each received a grant of phantom units under the LTIP in the following amounts: Mr. Zatezalo (73,171 phantom units), Mr. Boone (24,390 phantom units), Mr. Moravec (7,317 phantom units), Mr. Cox (1,220 phantom units) and Mr. Hunt (1,220 phantom units). The approximate dollar values of these phantom unit awards were determined as follows: (1) Mr. Zatezalo's award is equal to approximately three times his base salary; (ii) awards to Messrs. Boone and Moravec were targeted at approximately two times their respective base salaries (except the value of Mr. Moravec's award was reduced by the $600,000 of guaranteed bonuses provided under his amended and restated employment agreement); and (iii) awards to Messrs. Cox and Hunt were not tied to their salary levels, but are consistent with the awards granted to other officers in connection with the offering. These multiples of base salary were established pursuant to the discretion of our President and Chief Executive Officer and Wexford Capital and negotiations with our executive officers.

        The phantom units vest in equal one-sixth increments over a 36-month period, subject to earlier vesting upon a change of control or the executive's termination due to death or disability. Please read "—Potential Payments Upon Termination or Change in Control—LTIP Phantom Unit Awards." In addition, upon a termination of the executive by us without cause or by the executive for good reason, the vesting of any phantom units granted to the executive that are scheduled to vest within the 12-month period following such termination will be accelerated to such termination date. Distributions of dividend equivalent rights, or DERs, credited with respect to unvested phantom units will be paid upon vesting of the associated phantom units (and will be forfeited at the same time the associated phantom units are forfeited).

        With respect to future equity compensation awards, we intend to primarily utilize phantom units with associated DERs to provide long-term incentives to our named executive officers. DERs enable the recipients of phantom unit awards to receive cash distributions on our phantom units to the same extent generally as unitholders receive cash distributions on our common units. These awards are intended to align the interests of key employees (including the named executive officers) with those of our unitholders.

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401(k) Plan

        Rhino Energy LLC and two of its subsidiaries, CAM Mining LLC and McClane Canyon Mining LLC, are participating employers in the CAM Mining LLC 401(k) Plan, and Rhino Energy LLC's subsidiaries Hopedale Mining LLC, Rhino Coalfield Services LLC and Sands Hill Mining LLC each sponsor their own plans (collectively, the "401(k) Plans"). The companies use the 401(k) Plans to assist their eligible employees in saving for retirement on a tax-deferred basis. The 401(k) Plans permit all eligible employees, including the named executive officers and other individuals who provide services to us, to make voluntary pre-tax contributions to the applicable plan, subject to applicable tax limitations. A discretionary employer matching contribution may also be made to the 401(k) Plans for those eligible employees who meet certain conditions and subject to certain limitations under federal law. The employer matching contribution percentage, if any, is determined each year. Employee contributions are subject to annual dollar limitations, which are periodically adjusted by the cost of living index. Each 401(k) Plan is intended to be tax-qualified under Section 401(a) of the Internal Revenue Code so that contributions to the plan, and income earned on plan contributions, are not taxable to employees until withdrawn from the plan, and so that contributions, if any, will be deductible when made.

Other Benefits

        The employment agreements for each of the named executive officers provide, in general, that the named executive officer is eligible to participate in our employee benefit plans provided to salaried employees generally. Additional benefits and perquisites for the named executive officers may include payment of premiums for supplemental life insurance, long-term disability insurance and automobile fringe benefits. In 2010, the only perquisite provided to the named executive officers was the use of a company owned automobile.

Tax Deductibility of Compensation

        With respect to the deduction limitations under Section 162(m) of the Internal Revenue Code, we are a limited partnership and do not meet the definition of a "corporation" under Section 162(m). Hence, we are not subject to the deduction limitations imposed by Section 162(m).

Compensation Committee Report

        The compensation committee of our general partner has reviewed and discussed this Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the compensation committee recommended to the board of directors of our general partner that this Compensation Discussion and Analysis be included in this Form 10-K for the fiscal year ended December 31, 2010.

        Members of the compensation committee:

Jay Maymudes
Mark Zand

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Summary Compensation Table

        The following table sets forth the cash and other compensation earned by each of our named executive officers for each of the year ended December 31, 2009 and the year ended December 31, 2010.

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Grants of Plan-Based Awards

        The following table sets forth information concerning grants of plan-based awards to each of the named executive officers under the LTIP during fiscal year 2010.

Narrative Discussion of Summary Compensation Table and Grants of Plan-Based Awards Table

Employment Agreements

        During 2010, we had employment agreements in effect with each of the named executive officers included in our Summary Compensation Table. The employment agreements with Messrs. Zatezalo, Boone, Moravec, Cox and Hunt set forth the annual base salary payable to each named executive officer, which may be reviewed each year for possible increase (except Mr. Zatezalo's employment agreement provides for an automatic base salary increase for 2011 and 2012). The foregoing named executive officers were each entitled in 2010 under their respective employment agreements to receive an annual discretionary bonus of up to 40% of annual base salary (150% of base salary in the case of Mr. Zatezalo). In addition to a discretionary annual bonus, Mr. Moravec has received additional annual term bonuses, paid in monthly installments for having remained employed by us through March 31, 2010 (at an annual rate of $350,000). The named executive officers are also entitled to participate in our employee benefit programs, to the extent eligible. Pursuant to their respective employment agreements, we provide Messrs. Zatezalo, Moravec, Boone, Cox and Hunt with automobiles suitable for their duties and responsibilities to us.

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        We entered into amended and restated employment agreements with Messrs. Zatezalo and Moravec, effective January 1, 2010 and March 31, 2010, respectively. We have also entered into an amended and restated employment agreement with Mr. Cox, effective January 14, 2011. The amended and restated employment agreements are substantially similar to the agreements previously in effect, except as previously described in the section titled "—Compensation Discussion and Analysis—Elements of Compensation—Employment Agreements." The severance and change in control benefits provided by the employment agreements with the named executive officers are described below in the section titled "—Potential Payments Upon Termination or Change in Control—Employment Agreements."

Phantom Unit Awards

        On September 30, 2010, the compensation committee approved a grant of phantom units under the LTIP to each of the named executive officers in connection with our IPO. All phantom units vest in equal one-sixth increments over a 36-month period (i.e., approximately 16.6% vest at each six month anniversary of the date of grant, so that the phantom units are 100% vested on October 5, 2013), provided the named executive officer remains an employee continuously from the date of grant through the applicable vesting date. The phantom units will become fully vested upon a change in control or if the named executive officer's employment is terminated due to disability or death. In addition, if the named executive officer's employment is terminated by us without cause or by the executive for good reason, the vesting of those phantom units scheduled to vest in the 12 month period following such termination will be accelerated to the officer's termination date. While a named executive officer holds unvested phantom units, he is entitled to receive DER distributions that will be paid upon vesting of the associated phantom units (and will be forfeited at the same time the associated phantom units are forfeited).

Outstanding Equity Awards at Fiscal Year End

        The following table sets forth information concerning outstanding equity awards held by each of our named executive officers as of December 31, 2010.

Option Exercises and Stock Vested

        No equity-based awards held by our named executive officers vested or were exercised during fiscal year 2010.

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Pension Benefits

        Currently, we do not, and we do not intend to, provide pension benefits to our employees including the named executive officers. Our general partner may change this policy in the future.

Nonqualified Deferred Compensation Table

        Currently, we do not, and we do not intend to, sponsor or adopt a nonqualified deferred compensation plan. Our general partner may change this policy in the future.

Potential Payments Upon Termination or Change in Control

        We have employment agreements with each of the named executive officers that contain provisions regarding payments to be made to such individuals upon an involuntary termination of their employment by us, other than for cause. The employment agreements are described in greater detail below and in the section above titled "—Compensation Discussion and Analysis—Elements of Compensation—Employment Agreements."

Employment Agreements

        Under the employment agreements with Messrs. Zatezalo, Boone and Moravec, if the employment of the executive is terminated by us for "cause," by the executive voluntarily without "good reason," or due to the executive's "disability," then the executive, as applicable, will be entitled to receive his earned but unpaid base salary, payment with respect to accrued but unpaid vacation days, all benefits accrued and vested under any of our benefit plans, and reimbursement for any properly incurred business expenses (collectively, the "accrued obligations"). In addition to the foregoing, in the event the employment of Mr. Zatezalo, Mr. Boone or Mr. Moravec is terminated by us without "cause" or by the executive for "good reason," the executive shall receive a lump sum cash payment equal to twelve months' worth of his base salary (six months in the case of Mr. Moravec), subject to his timely execution and delivery (and nonrevocation) of a release agreement for our benefit. In the event of the death of Mr. Zatezalo, Mr. Boone or Mr. Moravec, his estate will be entitled to receive the accrued obligations and a pro-rated annual discretionary bonus. Messrs. Zatezalo, Boone and Moravec are subject to certain confidentiality, noncompete and nonsolicitation provisions contained in their respective employment agreements. The confidentiality covenants are perpetual, while the noncompete and nonsolicitation covenants apply during the term of the employment agreement and for one year (six months in the case of Mr. Moravec) following the executive's termination for any reason (two years following the executive's termination for any reason in the case of the nonsolicitation covenant).

        For purposes of the agreements with Messrs. Zatezalo, Boone and Moravec, the terms listed below have been defined as follows:

•

"cause" means (a) failure of the executive to perform substantially his duties (other than a failure due to a "disability") within ten days after written notice from us, (b) executive's conviction of, or plea of guilty or no contest to a misdemeanor involving dishonesty or any felony, (c) executive engaging in any illegal conduct, gross misconduct, or other material breach of the employment agreement that is materially and demonstratively injurious to us or (d) executive engaging in any act of dishonesty or fraud involving us or any of our affiliates.



•

"disability" means the inability of executive to perform his normal duties as a result of a physical or mental injury or ailment for any consecutive 45 day period or for 90 days (whether or not consecutive) during any 365 day period.

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•

"good reason" means, without the executive's express written consent, (a) the assignment to the executive of duties inconsistent in any material respect with those of the executive's position (including status, office, title, and reporting requirements), or any other diminution in any material respect in such position, authority, duties or responsibilities, (b) a reduction in base salary, (c) a reduction in the executive's welfare, qualified retirement plan or paid time off benefits, other than a reduction as a result of a general change in any such plan, (d) any purported termination of the executive's employment under the employment agreement other than for "cause," death or "disability" or (e) in the case of Messrs. Zatezalo and Moravec (but not Mr. Boone), a sale of our assets or ownership interests to an entity other than any of our subsidiaries or affiliates, Wexford Capital or any investment fund managed thereby. The executive must give notice of the event alleged to constitute "good reason" within six months of its occurrence and we have 30 days upon receipt of the notice to cure the alleged "good reason" event.

        Under the employment agreement with Mr. Cox, if Mr. Cox's employment is terminated by us without "cause," he is entitled to receive a lump sum payment equal to six months' worth of his base salary and continued family health insurance, at no premium cost, until the earlier of six months or the date he becomes covered under a new employer's plan. Mr. Cox is subject to certain confidentiality, noncompete and nonsolicitation provisions contained in his employment agreement. The confidentiality covenants are perpetual, while the noncompete covenants apply during the term of the employment agreement and for one year following termination of Mr. Cox's employment (except that the noncompete covenant applies for only 90 days following Mr. Cox's termination by us without "cause"). The nonsolicitation period runs until the end of the six month period following the end of the applicable noncompete period.

        For purposes of the agreement with Mr. Cox, "cause" means (1) the commission by executive of an act of dishonesty or fraud against us, (2) a breach of the executive's obligations under the employment agreement and failure to cure such breach within five days after written notice from us, (3) executive is indicted for or convicted of a crime involving moral turpitude or (4) executive materially fails or neglects to diligently perform his duties.

        Mr. Hunt's employment agreement previously provided for the payment of a one-time cash bonus of $100,000 in connection with the occurrence of certain change in control transactions or a public offering of common units of CAM Mining LLC or Rhino Energy LLC. Although this employment agreement was in effect during fiscal 2010, on April 26, 2010 Mr. Hunt received a one-time bonus of $100,000 and his employment agreement was amended to eliminate the change in control bonus contemplated thereunder. Mr. Hunt has agreed not to compete with us during his employment term and, in the case of his voluntary resignation or termination by us for "cause," for a period of three months following such termination. Mr. Hunt has also agreed not to solicit our employees for a period of six months following his noncompete period. For purposes of Mr. Hunt's employment agreement, "cause" has the same meaning set forth above with respect to the agreement with Mr. Cox.

LTIP Phantom Unit Awards

        Messrs. Zatezalo, Boone, Moravec, Cox and Hunt hold outstanding awards of phantom units under the LTIP as previously described in the section above titled "—Compensation Discussion and Analysis—Long-Term Incentive Compensation." The vesting of the phantom units will accelerate in full upon a "change of control" or the named executive officer's termination due to death or "disability." In addition, upon a termination of the executive by us without cause or by the executive for a good reason, the vesting of those phantom units scheduled to vest in the 12-month period following such termination will be accelerated to such termination date. "Good reason" will generally have the meaning set forth above and "cause" will have the meaning set forth in the respective employment agreement of the named executive officer as described above. "Cause" with respect to Mr. Hunt will

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have the meaning set forth in the employment agreements of Messrs. Zatezalo, Boone and Moravec. A "change of control" will be deemed to have occurred if: (i) any person or group, other than Wexford Capital, our general partner or an affiliate of either, becomes the owner of more than 50% of the voting power of the voting securities of either us or our general partner; or (ii) upon the sale or other disposition by either us or our general partner of all or substantially all of its assets, whether in a single or series of related transactions, to one or more parties (other than Wexford Capital, our general partner or an affiliate of either). A "disability" is any illness or injury for which the named executive officer will be entitled to benefits under the long-term disability plan of our general partner.

Quantification of Payments

        The table below discloses the amount of compensation and/or benefits due to Messrs. Zatezalo, Boone, Moravec, Cox and Hunt in the event of their termination of employment under certain specified circumstances and/or upon the occurrence of a change in control. The amounts disclosed assume (i) such termination or change in control was effective on December 31, 2010, taking into account the arrangements described above and the salary and bonus rates in effect for the named executive officers for fiscal 2010, and (ii) that the price per common unit was $23.34, which was the closing price of our common units on December 31, 2010. The table excludes amounts accrued through fiscal 2010 year-end that would be paid in the normal course of continued employment, such as accrued but unpaid salary, and benefits generally available to all our salaried employees. The amounts below constitute estimates of the amounts that would be paid to the named executive officers upon their respective terminations and/or upon a change in control under such arrangements. The actual amounts to be paid out are dependent on various factors, which may or may not exist at the time a named

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executive officer is actually terminated or a change in control actually occurs. Therefore, such amounts should be considered "forward-looking statements."

Director Compensation

        We provide compensation to the non-employee directors (including the directors who are principals of Wexford Capital) of the board of directors of our general partner, including a $20,000 annual base director fee and a grant of that number of common units having a grant date value of $25,000 (based on the preceding 10-day average price per unit), 25% of which vest on the grant date and 75% of which are restricted units that vest one-third on the first day of each of the first three calendar quarters that begin following the grant date (with vesting to be accelerated upon the director's death or disability, if a non-Wexford director, and for all of the directors, on a change of control (as defined in the LTIP)). Distributions of DERs made by us on a restricted unit vest or are forfeited when the restricted unit vests or is forfeited, as applicable. In addition, the chairs of the audit committee and conflicts committee receive a $15,000 fee, the chair of any other committee (including the compensation committee) receives a $10,000 fee, audit committee and conflicts committee members receive a $10,000 fee and the other committee members receive a $5,000 fee, for their service in such roles each year. Our employees who also serve as directors do not receive additional compensation.

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Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees, and each director is fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. Wexford Capital does not receive compensation from us for conducting our business or managing our operations.

        The following table provides information concerning the compensation of our non-employee directors for the fiscal year ended December 31, 2010.

Compensation Practices as They Related to Risk Management

        We believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees). Short-term annual incentives are generally paid pursuant to discretionary bonuses, which enable the compensation committee of our general partner to assess the actual behavior of our employees as it relates to risk taking in awarding bonus amounts. Further, our use of equity based long-term compensation serves our compensation program's goal of aligning the interests of executives and unitholders, thereby reducing the incentives to unnecessary risk taking.

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Item 12.    Security Ownership of Certain Beneficial Owners and Management.

        The following table sets forth the beneficial ownership of common units and subordinated units as of March 14, 2011 of Rhino Resource Partners LP for:

•

beneficial owners of more than 5% of our common units;



•

each director, director nominee and executive officer; and



•

all of our directors and executive officers as a group.

        The following table does not include any phantom awards granted under the long-term incentive plan. Please see "Part III, Item 11. Executive Compensation—Compensation Discussion and Analysis—Elements of Compensation—Long-Term Incentive Compensation."

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Equity Compensation Plan Information

Item 13.    Certain Relationships and Related Transactions, and Director Independence.

        As of March 14, 2011, Wexford owns 8,554,983 common units and 12,228,896 subordinated units representing approximately 83.8% of our units owns and controls our general partner, and has appointed all of the directors of our general partner, which maintains its 2.0% general partner interest as well as the incentive distribution rights representing a limited partner interest in us.

        Principals of Wexford Capital, including Mark D. Zand, Joseph M. Jacobs, Jay L. Maymudes, Arthur H. Amron and Kenneth A. Rubin, own membership interests in our general partner.

        The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm's length negotiations. Such terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms which could have been obtained from unaffiliated third parties.

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Distributions and Payments to Our General Partner and Its Affiliates

        In connection with the closing of our IPO, the following occurred:

•

Wexford contributed all of their membership interests in Rhino Energy LLC to us;



•

we issued to Rhino Energy Holdings LLC an aggregate of 8,666,400 common units and 12,397,000 subordinated units and reimbursed Rhino Energy Holdings LLC for approximately $9.3 million of capital expenditures it incurred with respect to the assets contributed to us;



•

our general partner made a capital contribution of approximately $10.4 million and maintained its 2.0% general partner interest in us; and



•

we issued our general partner the incentive distribution rights, which entitle the holder to increase percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.51175 per unit per quarter.

        On February 14, 2011, Wexford received a distribution for the fourth quarter of 2010 of approximately $0.2 million on the 2.0% general partner interest and approximately $8.7 million on its 8,554,983 common units and 12,228,896 subordinated units.

Agreements with Affiliates

        In connection with our IPO, we have entered into certain agreements with Wexford, as described in more detail below.

Contribution Agreement

        On September 29, 2010, we entered into a contribution agreement that effected the transactions, including the transfer of the ownership interests in Rhino Energy LLC, and the use of the net proceeds, of our IPO. This agreement was not the result of arm's-length negotiations, and it, or any of the transactions that it provides for, may have not been effected on terms at least as favorable to the parties to this agreement as could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions were paid from the proceeds of our IPO.

Registration Rights Agreement

        Under our partnership agreement, as amended and restated, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

        In addition, in connection with our IPO, on October 5, 2010 we entered into a registration rights agreement with Rhino Energy Holdings LLC. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to Rhino Energy Holdings LLC and the common units issuable upon the conversion of the subordinated units upon request of Rhino Energy Holdings LLC. In addition, the registration rights agreement gives Rhino Energy Holdings LLC piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Rhino Energy Holdings LLC and, in certain circumstances, to third parties.

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Policies Relating to Conflicts of Interest

        Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Wexford Capital, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a contractual duty to manage our partnership in a manner beneficial to us and our unitholders.

        Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that replace default fiduciary duties under applicable Delaware law with contractual corporate governance standards. Our partnership agreement also delimits the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its default fiduciary duty under applicable Delaware law.

        Our general partner will not be in breach of its obligations under our partnership agreement or its duties or obligations to us or our unitholders if the resolution of the conflict is:

•

approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;



•

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



•

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



•

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

        Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.

Director Independence

        See "Part III, Item 10. Directors, Executive Officers and Corporate Governance" for information regarding the directors of our general partner and the independence requirements applicable to the board of directors of our general partner and its committees.

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Item 14.    Principal Accounting Fees and Services.

        The following table presents fees for professional services rendered by Deloitte & Touche LLP for 2010 and 2009:

        Our audit committee has adopted an audit committee charter, which is available on our website, which requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee.

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PART IV

Item 15.    Exhibits, Financial Statement Schedules.

(a)(1)  Financial Statements

        See "Index to the Consolidated Financial Statements" set forth on Page F-1.

(2)       Financial Statement Schedules

        All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

(3)       Exhibits

EXHIBIT LIST

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 18, 2011

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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INDEX TO FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
the Managing General Partner
and the Partners of Rhino
Resource Partners LP:

        We have audited the accompanying consolidated statements of financial position of Rhino Resource Partners LP and subsidiaries (the "Partnership") as of December 31, 2010 and 2009, and the related consolidated statements of operations and comprehensive income, members' equity/partners' capital, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership and subsidiaries as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Cincinnati, OH
March 18, 2011

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RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

AS OF DECEMBER 31, 2010 AND 2009

(In thousands)

See notes to consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

(In thousands, except per unit data)

See notes to consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY/PARTNERS' CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

(in thousands)

 

See notes to consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

(In thousands)

See notes to consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

1. ORGANIZATION AND BASIS OF PRESENTATION

        Organization—Rhino Resource Partners LP and subsidiaries (the "Partnership") is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the "Predecessor" or the "Operating Company"), an entity engaged primarily in the mining and sale of coal. The Partnership had no operations during the period from April 19, 2010 (date of inception) to October 5, 2010 (the consummation of the initial public offering ("IPO") date of the Partnership). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Kentucky, Ohio, West Virginia, Colorado and Utah, with the majority of the Operating Company's sales going to domestic utilities and other coal-related organizations in the United States. The Operating Company was formed in April 2003 and has been built via acquisitions.

Initial Public Offering

        On October 5, 2010, Rhino Resource Partners LP completed its IPO of 3,244,000 common units, representing limited partner interests in the Partnership, at a price of $20.50 per common unit. Net proceeds from the offering were approximately $58.3 million, after deducting underwriting discounts and offering expenses of $8.2 million. The Partnership used the net proceeds from this offering, and a related capital contribution by Rhino GP LLC, the Partnership's general partner (the "General Partner") of approximately $10.4 million, to repay approximately $69.4 million of outstanding indebtedness under the Operating Company's credit facility. These net proceeds do not include $9.3 million that was used to reimburse affiliates of the Partnership's sponsor, Wexford Capital LP ("Wexford Capital"), for capital expenditures incurred with respect to the assets contributed to the Partnership in connection with the offering. In connection with the closing of the IPO, the owners of the Operating Company contributed their membership interests in the Operating Company to the Partnership, and the Partnership issued 12,397,000 subordinated units representing limited partner interests in the Partnership and 9,153,000 common units to Rhino Energy Holdings LLC, an affiliate of Wexford Capital, and issued incentive distribution rights to the General Partner. Upon the closing of the IPO, and as required by the Operating Company's credit agreement by and among the Operating Company, as borrower, and its subsidiaries as guarantors, and PNC Bank, National Association, as agent, and the other lenders thereto (as amended from time to time, the "Credit Agreement"), the Partnership pledged 100% of the membership interests in the Operating Company to the agent on behalf of itself and the other lenders to secure the Operating Company's obligations under the Credit Agreement.

Acquisition of Coal Property

        In August 2010, the Predecessor 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. These assets are located in Emery and Carbon Counties, Utah. Prior to the purchase of the assets, the Operating Company formed a new wholly owned subsidiary, Castle Valley Mining LLC ("Castle Valley"). Castle Valley in turn acquired the following assets and liabilities (of the former C.W. Mining Company) from the Operating Company:

•

the Coal Operating Agreement whereby Castle Valley becomes a sub-lessee of certain federal coal leases owned by the Bureau of Land Management;

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

1. ORGANIZATION AND BASIS OF PRESENTATION (Continued)

•

buildings, mining equipment, conveyor belts and belt structure, a truck loading facility and other mining assets; and



•

reclamation or "end of mine" liabilities.

        The Partnership is staffing the location and rehabilitating the mine and equipment and began production from these assets at one underground mine in early 2011. The coal produced and sold from these mining assets will be sold as steam coal.

        The Partnership must allocate the purchase price of $15.0 million to the assets and liabilities acquired based upon their respective fair values in accordance with Accounting Standards Codification ("ASC") Topic 805, "Business Combinations". The fair value of the assets acquired and liabilities assumed in this transaction are as follows:

        Although the responsibility of valuation remains with the Partnership's management, the determination of the fair values of the various assets and liabilities acquired were based in part upon studies conducted by third-party professionals with experience in the appropriate subject matter. Because the fair value of the assets acquired exceeded the purchase price, the Partnership recorded a gain of $10.8 million that is reflected on the Gain/loss on sale/acquisition of assets line of the Consolidated Statements of Operations and Comprehensive Income. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy.

        The Partnership has not disclosed any revenue or earnings generated from the acquired assets since production did not begin until early 2011.

        Acquisition-related costs in the amount of approximately $0.5 million were expensed for the year ended December 31, 2010 and included legal and engineering fees incurred.

Acquisition of Manufacturing Company

        In January 2009, the Operating Company acquired the manufacturing operations of Triad Roof Support Systems, LLC located in Kentucky as part of a vertical integration effort. This operation produces roof control products used in underground coal mining. This acquisition included a manufacturing facility as well as a small product development shop. The Operating Company allocated the purchase price to assets and liabilities acquired based upon their respective fair values in accordance with ASC Topic 805, "Business Combinations". To the extent that the purchase price of the

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

1. ORGANIZATION AND BASIS OF PRESENTATION (Continued)

assets was greater than the fair value of the net assets acquired, the Operating Company recorded goodwill. The recorded values of the assets were:

        Basis of Presentation and Principles of Consolidation—The accompanying consolidated financial statements include the accounts of Rhino Resource Partners LP and its subsidiaries. Intercompany transactions and balances have been eliminated in consolidation.

        For full year 2010 income, expense and cash flow items, the Partnership has disclosed consolidated figures of the Partnership and Predecessor as if the Partnership had operated the entire year. The closing of the IPO and the contribution of the membership interests in the Operating Company to the Partnership did not result in any basis change of the assets of the Predecessor as the Partnership and Predecessor were entities under common control and the Predecessor was contributed to the Partnership and continued operations in consistently the same manner after being contributed to the Partnership. For these reasons as well as year-to-year comparability of financial results, the 2010 full year income, expense and cash flow results are presented as one total figure. Note that the earnings per unit figures on the Consolidated Statements of Operations and Comprehensive Income and in Note 14 are based on the applicable income of the Partnership after the closing of the IPO and the contribution of the membership interests in the Operating Company to the Partnership (October 6, 2010) until year end December 31, 2010 since this is the amount of income that is attributable to the limited partner units after the closing of the IPO and the contribution of the membership interests in the Operating Company to the Partnership.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

        Company Environment and Risk Factors.    The Partnership, in the course of its business activities, is exposed to a number of risks including: fluctuating market conditions of coal, truck and rail transportation, fuel costs, changing government regulations, unexpected maintenance and equipment failure, employee benefits cost control, changes in estimates of proven and probable coal reserves, as well as the ability of the Partnership to maintain adequate financing, necessary mining permits and control of sufficient recoverable coal properties. In addition, adverse weather and geological conditions may increase mining costs, sometimes substantially.

        Concentrations of Credit Risk.    See Note 15 for discussion of major customers. The Partnership does not require collateral or other security on accounts receivable. The credit risk is controlled through credit approvals and monitoring procedures.

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

        Cash and Cash Equivalents.    The Partnership considers all highly liquid investments purchased with original maturities of three months or less to be cash equivalents.

        Inventories.    Inventories are stated at the lower of cost, based on a three month rolling average, or market. Inventories primarily consist of coal contained in stockpiles.

        Advance Royalties.    The Partnership is required, under certain royalty lease agreements, to make minimum royalty payments whether or not mining activity is being performed on the leased property. These minimum payments may be recoupable once mining begins on the leased property. The Partnership capitalizes the recoupable minimum royalty payments and amortizes the deferred costs once mining activities begin on the units of production method or expenses the deferred costs when the Partnership has ceased mining or has made a decision not to mine on such property.

        Note Receivable.    Included in prepaid expenses and other current assets as of December 31, 2009 are notes receivable the Partnership advanced to Rhino Eastern LLC ("Rhino Eastern"), a joint venture with an affiliate of Patriot Coal Corporation ("Patriot"), in the amount of $0.4 million, which bear interest at a fixed rate of 10%. The notes were fully repaid as of December 31, 2010.

        Property, Plant and Equipment.    Property, plant, and equipment, including coal properties, mine development costs and construction costs, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Mining and other equipment and related facilities are depreciated using the straight-line method based upon the shorter of estimated useful lives of the assets or the estimated life of each mine. Coal properties are depleted using the units-of-production method, based on estimated proven and probable reserves. Mine development costs are amortized using the units-of-production method, based on estimated proven and probable reserves. Gains or losses arising from sales or retirements are included in current operations.

        Stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. The Partnership defines a surface mine as a location where the Partnership utilizes operating assets necessary to extract coal, with the geographic boundary determined by property control, permit boundaries, and/or economic threshold limits. Multiple pits that share common infrastructure and processing equipment may be located within a single surface mine boundary, which can cover separate coal seams that typically are recovered incrementally as the overburden depth increases. In accordance with the accounting guidance for extractive mining activities, the Partnership defines a mine in production as one from which saleable minerals have begun to be extracted (produced) from an ore body, regardless of the level of production; however, the production phase does not commence with the removal of de minimis saleable mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to an ore body. The Partnership capitalizes only the development cost of the first pit at a mine site that may include multiple pits.

        Asset Impairments.    The Partnership follows the accounting guidance on the impairment or disposal of property, plant and equipment which requires that projected future cash flows from use and

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

disposition of assets be compared with the carrying amounts of those assets when potential impairment is indicated. When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, the Partnership must determine the fair value for the assets in question in accordance with the applicable fair value accounting guidance. Once the fair value is determined, the appropriate impairment loss must be recorded as the difference between the carrying amount of the assets and their respective fair values. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine's underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the mine closing accrual is increased accordingly. To the extent it is determined that asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. The Partnership recorded an impairment loss of $0.7 million in 2010 related to certain assets that are to be disposed of by sale. Please read Note 5 for a discussion of this asset impairment loss recorded in 2010. There were no impairment losses recorded during the years ended December 31, 2009 and 2008.

        Debt Issuance Costs.    Debt issuance costs reflect fees incurred to obtain financing and are amortized (included in interest expense) using the effective interest method over the life of the related debt. Debt issuance costs are included in other non-current assets.

        Asset Retirement Obligations.    The accounting guidance for asset retirement obligations addresses asset retirement obligations that result from the acquisition, construction or normal operation of long-lived assets. This guidance requires companies to recognize asset retirement obligations at fair value when the liability is incurred or acquired. Upon initial recognition of a liability, an amount equal to the liability is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Partnership has recorded the asset retirement costs in coal properties.

        The Partnership estimates its future cost requirements for reclamation of land where it has conducted surface and underground mining operations, based on its interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground mines. Other reclamation costs are related to refuse and slurry ponds, as well as holding and related termination/exit costs.

        The Partnership expenses contemporaneous reclamation which is performed prior to final mine closure. The establishment of the end of mine reclamation and closure liability is based upon permit requirements and requires significant estimates and assumptions, principally associated with regulatory requirements, costs and recoverable coal reserves. Annually, the Partnership reviews its end of mine reclamation and closure liability and makes necessary adjustments, including mine plan and permit changes and revisions to cost and production levels to optimize mining and reclamation efficiency. When a mine life is shortened due to a change in the mine plan, mine closing obligations are accelerated, the related accrual is increased and the related asset is reviewed for impairment, accordingly.

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

        The adjustments to the liability from annual recosting reflect changes in expected timing, cash flow and the discount rate used in the present value calculation of the liability. Changes in the asset retirement obligations for the year ended December 31, 2010 were calculated with a discount rate of 7.5% which changed from previous years due to changes in applicable market indicators that are used to arrive at an appropriate discount rate. Changes in the asset retirement obligations for the years ended December 31, 2009 and 2008 were calculated with the same discount rate of 10%. Other recosting adjustments to the liability are made annually based on inflationary cost increases or decreases and changes in the expected operating periods of the mines. The related inflation rate utilized in the recosting adjustments was 3.0% for all periods presented.

        Workers' Compensation Benefits.    Certain of the Partnership's subsidiaries are liable under federal and state laws to pay workers' compensation and coal workers' pneumoconiosis ("black lung") benefits to eligible employees, former employees and their dependents. The Partnership currently utilizes an insurance program and state workers' compensation fund participation to secure its on-going obligations depending on the location of the operation. Premium expense for workers' compensation benefits is recognized in the period in which the related insurance coverage is provided. As of December 31, 2010, the workers' compensation benefits liability balance included approximately $3.7 million in the non-current liabilities section of the Partnership's Consolidated Statements of Financial Position.

        Revenue Recognition.    Most of the Partnership's revenues are generated under long-term coal sales contracts with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales agreement. Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation source that delivers coal to its destination. Advance payments received are deferred and recognized in revenue as coal is shipped and title has passed.

        Coal sales revenues also result from the sale of brokered coal produced by others. The revenues related to brokered coal sales are included in coal sales revenues on a gross basis and the corresponding cost of the coal from the supplier is recorded in cost of coal sales in accordance with the revenue recognition accounting guidance on principal agent considerations.

        Freight and handling costs paid directly to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.

        Other revenues generally consist of limestone sales, roof bolt sales, coal handling and processing, rebates and rental income. With respect to other revenues recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the seller's price to the buyer is fixed or determinable and collectibility is reasonably assured. Advance payments received are deferred and recognized in revenue when earned.

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

        Selling, General and Administrative ("SG&A") Expenses.    SG&A expense recorded for the year ended December 31, 2008 includes the recognition of $3.6 million in deferred costs related to our previous initial public offering, which was abandoned in August of that year.

        Equity-Based Compensation.    The Partnership applies the provisions of ASC 718 to account for any unit awards granted to employees or directors. This guidance requires that all share-based payments to employees, including grants of stock options, be recognized in the financial statements based on their fair value. The General Partner has currently granted restricted units and phantom units to directors and certain employees of the General Partner and Partnership that contain only a service condition. The fair value of each restricted unit and phantom unit award was calculated using the closing price of the Partnership's common units on the date of grant. The fair value of the employee unit-based awards, less estimated forfeitures, is amortized over the awards' vesting periods on a straight-line basis. Unit awards granted to directors of the General Partner are considered nonemployee equity-based awards since the directors are not elected by unitholders. Thus, these director awards are required to be marked-to-market each reporting period until they are vested.

        Derivative Financial Instruments.    During the year ended December 31, 2008, the Partnership used futures contracts to manage the risk of fluctuations in the sales price of coal. The Partnership did not use derivative financial instruments for trading or speculative purposes. The Partnership recorded the derivative financial instruments as either assets or liabilities, at fair value, in accordance with the accounting guidance on derivatives and hedging. All futures contracts were settled as of December 31, 2008. The Partnership also uses diesel fuel forward contracts to manage the risk of fluctuations in the cost of diesel fuel. The Partnership's diesel fuel forward contracts qualify for the normal purchase normal sale ("NPNS") exception prescribed by the accounting guidance on derivatives and hedging, based on management's intent and ability to take physical delivery of the diesel fuel.

        Investment in Joint Venture.    Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, the Partnership's ability to exercise significant influence over the operating and financial policies of the investee and whether the Partnership is determined to be the primary beneficiary of a variable interest entity. Equity investments are recorded at original cost and adjusted periodically to recognize the Partnership's proportionate share of the investees' net income or losses after the date of investment. When net losses from an equity method investment exceed its carrying amount, the investment balance is reduced to zero and additional losses are not provided for. The Partnership resumes accounting for the investment under the equity method when the entity subsequently reports net income and the Partnership's share of that net income exceeds the share of net losses not recognized during the period the equity method was suspended. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.

        In May 2008, the Operating Company entered into a joint venture, Rhino Eastern, with an affiliate of Patriot to acquire the Eagle mining complex. To initially capitalize the joint venture, the Operating Company contributed approximately $16.1 million for a 51% ownership interest in the joint venture and accounts for the investment in the joint venture and its results of operations under the equity method. The Partnership considers the operations of this entity to comprise a reporting segment and has provided additional detail related to this operation in Note 19, "Segment Information."

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

        In determining that the Partnership was not the primary beneficiary of the variable interest entity for the years ended December 31, 2010, 2009 and 2008, the Partnership performed a qualitative and quantitative analysis of the variable interests in the joint venture. This included an analysis of the expected losses and residual returns of the joint venture. The Partnership concluded that it is not the primary beneficiary of the joint venture primarily because of certain contractual arrangements by the joint venture with Patriot. Mandatory pro rata additional contributions not to exceed $10 million in the aggregate could be required of the joint venture partners which the Partnership would be obligated to fund based upon its 51% ownership interest.

        As of December 31, 2010 and 2009, the Partnership has recorded its equity method investment of $18.7 million and $17.2 million, respectively, as a long-term asset. The Partnership's maximum exposure to losses associated with its involvement in this variable interest entity would be limited to its equity investment of $18.7 million as of December 31, 2010 plus any additional capital contributions, if required. The Partnership has not provided any additional contractually required support as of December 31, 2010. As disclosed in Note 17 "Related Party and Affiliate Transactions", the Partnership provided a loan to the joint venture in the amount of $0.4 million as of December 31, 2009 that was fully repaid as of December 31, 2010.

        Income Taxes.    The Partnership is considered a partnership for income tax purposes. Accordingly, the partners report the Partnership's taxable income or loss on their individual tax returns.

        Loss Contingencies.    In accordance with the guidance on accounting for contingencies, the Partnership records loss contingencies at such time that an unfavorable outcome becomes probable and the amount can be reasonably estimated. When the reasonable estimate is a range, the recorded loss is the best estimate within the range. If no amount in the range is a better estimate than any other amount, the minimum amount of the range is recorded. The Partnership discloses information concerning loss contingencies for which an unfavorable outcome is probable. See Note 13, "Commitments and Contingencies," for a discussion of legal matters.

        Management's Use of Estimates.    The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

        Recently Issued Accounting Standards.    Effective January 1, 2008, the Predecessor adopted the accounting guidance (ASC Topic 820) that clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. ASC Topic 820 applies whenever other statements require or permit assets or liabilities to be measured at fair value. ASC Topic 820 requirements for certain non-financial assets and liabilities were permitted to be deferred until the first quarter of 2009. The Predecessor adopted the new guidance under ASC Topic 820 on a prospective basis as of January 1, 2009. At the time of the adoption there were no nonfinancial assets or nonfinancial liabilities that were measured at fair value on a nonrecurring basis.

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

ASC Topic 820 establishes the following fair value hierarchy that prioritizes the inputs used to measure fair value:

•

Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.



•

Level 2—Inputs other than Level 1 that are based on observable market data, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets, quoted prices for identical assets or liabilities in inactive markets, inputs that are observable that are not prices and inputs that are derived from or corroborated by observable markets.



•

Level 3—Developed from unobservable data, reflecting an entity's own assumptions.

        The Predecessor also adopted ASC Topic 825, Financial Instruments, as of January 1, 2008, which permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. In addition, it also establishes recognition, presentation, and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. Neither the Partnership nor the Predecessor has made any fair value elections with respect to any of its eligible assets or liabilities as of December 31, 2010 or 2009.

        ASC Topic 805, among other things, provides guidance for the way companies account for business combinations. This guidance requires transaction-related costs to be expensed as incurred, which were previously accounted for as a cost of acquisition. ASC Topic 805 also requires acquirers to estimate the acquisition-date fair value of any contingent consideration and recognize any subsequent changes in the fair value of contingent consideration in earnings. In addition, restructuring costs the acquirer was not obligated to incur shall be recognized separately from the business acquisition. The Predecessor adopted this guidance on a prospective basis as of January 1, 2009. The adoption of this guidance did not require remeasurement of any prior balances, but will impact the accounting for business combinations after date of adoption. The adoption of this guidance was applied to the purchase accounting of Triad Roof Support Systems LLC in 2009 and the acquisition of C.W. Mining Company assets in 2010.

        In June 2009, the FASB issued guidance under ASC Topic 810 which amended the consolidation guidance for variable interest entities ("VIEs"). The new guidance requires a company to perform an analysis to determine whether its variable interest gives it a controlling financial interest in a VIE. The amendment, which requires ongoing reassessments, redefines the primary beneficiary as the party that (1) has the power to direct the activities of a VIE that most significantly impact the entity's economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The guidance includes enhanced disclosures about a company's involvement in a VIE and also eliminates the exemption for qualifying special purpose entities. The guidance was effective for the Partnership on January 1, 2010.

3. SUBSEQUENT EVENTS

        On January 24, 2011, the Partnership announced a cash distribution of $0.4208 per common unit and subordinated unit, which corresponded to the minimum quarterly distribution of $0.445 per unit, or

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

3. SUBSEQUENT EVENTS (Continued)

$1.78 per unit on an annualized basis, prorated for the portion of the quarter after October 5, 2010, the closing date of the IPO. This distribution was paid on February 14, 2011 to all unitholders of record as of the close of business on February 1, 2011.

        In February and March of 2011, the Partnership 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 $3.0 million. The Partnership expects royalty revenues to be generated from these mineral rights in future periods. The Partnership has not completed its accounting analysis for this acquisition.

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

        Prepaid expenses and other current assets as of December 31, 2010 and 2009 consisted of the following:

5. PROPERTY, PLANT AND EQUIPMENT

        Property, plant and equipment, including coal properties and mine development and construction costs, as of December 31, 2010 and 2009 are summarized by major classification as follows:

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RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

5. PROPERTY, PLANT AND EQUIPMENT (Continued)