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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

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

As of June 29, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's equity held by non-affiliates of the registrant was approximately $98.1 million based on the closing price of the registrant's common units on the New York Stock Exchange on such date. As of February 28, 2013, the registrant had 15,358,699 common units and 12,397,000 subordinated units outstanding.

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

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.

Bbl: One standard barrel containing 42 United States gallons liquid volume.

BOE: A barrel of oil equivalent and is a standard convention used to express oil and natural gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6 thousand cubic feet of gas to 1 Bbl of oil or natural gas liquid.

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.

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

gross acreage or gross wells: The total acres or wells, as the case may be, in which a working interest is owned.

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 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.

net acres or net wells: the sum of the fractional working interests owned in gross acres or gross wells expressed as whole numbers and fractions of whole numbers.

net mineral acre: The product of (i) the percentage of oil and natural gas mineral rights owned in a given tract of land and (ii) the total surface acreage of such tract.

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 warrant 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.

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) coal reserves: Coal 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.

productive well: A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

proven (measured) coal reserves: Coal 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.

proved developed oil and natural gas reserves: Proved oil and natural gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

proved oil and natural gas reserves: The quantities of oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

proved undeveloped oil and natural gas reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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

recompletion: The process of re-entering an existing wellbore that is either producing or not producing and completing new oil and natural gas reservoirs in an attempt to establish or increase existing production.

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.

With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by our working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.

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," "plan," "intend," foresee," "should," "would," "could" or similar words, which are generally not historical in nature. 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. While we believe that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future results are based on our forecasts for our existing operations and do not include the potential impact of any unforeseen developments. 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. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Item 1A "Risk Factors." The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

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.

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

We are a diversified energy limited partnership formed in Delaware that is focused on coal, oil and natural gas and related energy infrastructure. We produce, process and sell high quality coal of various steam and metallurgical grades from multiple coal producing basins in the United States. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition to operating coal properties, we manage and lease coal properties and collect royalties from such management and leasing activities. Our diversified energy portfolio also includes investments in oil and natural gas mineral rights in the Utica Shale and Cana Woodford regions. In addition, we have expanded our business to include infrastructure support services, including the formation of a service company to provide drill pad construction for operators in the Utica Shale as well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. In December 2012, we also invested in a joint venture that will provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region and oil and natural gas investments in the Utica Shale region of eastern Ohio and the Cana Woodford region of western Oklahoma. As of December 31, 2012, we controlled an estimated 463.7 million tons of proven and probable coal reserves, consisting of an estimated 442.8 million tons of steam coal and an estimated 20.9 million tons of metallurgical coal. In addition, as of December 31, 2012, we controlled an estimated 417.4 million tons of non-reserve coal deposits. As of December 31, 2012, Rhino Eastern LLC, a joint venture with Patriot Coal Corporation ("Patriot") in which we own a 51% membership interest and for which we serve as manager, controlled an estimated 43.1 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 17.9 million tons of non-reserve coal deposits. Our oil and natural gas investments as of December 31, 2012 consisted of a 5% net interest in a portfolio of oil and natural gas leases in the Utica Shale that encompassed 137,000 total gross acres, or 6,850 net acres, as well as approximately 1,900 net mineral acres that we own in the Cana Woodford region.

As of December 31, 2012, we operated nine mines, including four underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. In addition, the Rhino Eastern joint venture operates two underground mines in West Virginia. During 2010, we operated one underground mine in Colorado, but we temporarily idled this mine at year end 2010 and this mine remained idle at the end of 2012. The number of mines that we operate will 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 Rhino Eastern joint venture, for the year ended December 31, 2012, we produced approximately 4.3 million tons of coal, purchased approximately 0.4 million tons of coal and sold approximately 4.7 million tons of coal. Additionally, the Rhino Eastern joint venture produced and sold approximately 0.3 million tons of

premium mid-vol metallurgical coal for the year ended December 31, 2012. Additionally, lessees produced approximately 2.6 million tons of coal from our Elk Horn coal leasing properties in eastern Kentucky for the year ended December 31, 2012. For our Utica Shale investment, we receive our proportionate share (5%) of revenue from any hydrocarbons produced and sold by the operator on our acreage. We received approximately $248,000 of revenue for the year ended December 31, 2012 since the drilling and testing of wells began in 2012 and sales did not take place until late in the year. We began to receive royalty revenue from hydrocarbons sold from our Cana Woodford investment and for the year ended December 31, 2012 we received approximately $77,000 in royalty revenue. Please see Note 20 of the consolidated financial statements included elsewhere in this annual report for information regarding our reportable business segments.

Our principal business strategy is to safely, efficiently and profitably produce, sell and lease both steam and metallurgical coal from our diverse asset base in order to maintain, and, over time, increase our quarterly cash distributions. In addition, we intend to continue to expand and diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets, such as our oil and gas investments in the Utica Shale and Cana Woodford regions. We believe that such assets will allow us to grow our cash available for distribution and enhance our cash flow.

Our predecessor was formed in April 2003 by Wexford Capital LP ("Wexford Capital", and together with certain of its affiliates and principals, "Wexford"). Wexford Capital is an SEC registered investment advisor which was formed in 1994 and manages a series of investment funds and has over $4.7 billion of assets under management. Since the formation of our predecessor, we have significantly grown our coal reserves. Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $356.1 million. Through these acquisitions and coal lease transactions, we have substantially increased our proven and probable coal reserves and non-reserve coal deposits. In addition, we have successfully grown our production through internal development projects.

In May 2012, we completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for a total cost of $3.1 million as of December 31, 2012. These coal leases and property are estimated to contain approximately 32 million tons of proven and probable coal reserves that are contiguous to the Green River. We are currently performing stage one earthwork development on the property, which is fully permitted, and we have signed a sales contract with an electric utility anchor customer that ensures this project has an immediate market for its coal. We plan to commence production in mid-2014. This property provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers in the future. In addition, in June 2011 we completed the acquisition of 100% of the ownership interests in The Elk Horn Coal Company ("Elk Horn") for approximately $119.7 million in cash consideration. Elk Horn is primarily a coal leasing company located in eastern Kentucky that provides us with coal royalty revenues, which we believe helps to diversify our income stream while limiting our direct operational risk.

In addition to our coal acquisitions, in 2011 we began to invest in oil and natural gas mineral rights in the Utica Shale region of eastern Ohio as well as the Cana Woodford region of western Oklahoma. As of December 31, 2012, we invested a total of approximately $24.2 million for a 5% net interest in a portfolio of oil and natural gas leases in the Utica Shale region along with approximately $5.3 million in drilling costs, which represents our proportionate ownership share in the portfolio. The operator of the portfolio began drilling and testing wells in the region in 2012 and sales of hydrocarbons commenced late in the year. Our 2013 projected expansion capital expenditures include an estimated $15 million to $20 million for our oil and natural gas investments, primarily for drilling

costs related to our Utica Shale acreage. We believe this investment will add to our revenue streams in future periods. In addition, as of December 31, 2012, we have invested approximately $8.1 million for mineral rights in the Cana Woodford region. We believe these investments will help to diversify our income stream.

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

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

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

As of December 31, 2012, we operated four mining complexes located in Central Appalachia (Tug River, Rob Fork, Deane and Rhino Eastern) along with our Elk Horn coal leasing operations in Central Appalachia. In addition, we operated two mining complexes located in Northern Appalachia (Hopedale and Sands Hill). In the Western Bituminous region, we operated one mining complex located in Emery and Carbon Counties, Utah (Castle Valley). During 2010, we operated one mine located in the Western Bituminous region in Colorado (McClane Canyon) that has been temporarily idled since the end of 2010 and remained idle at the end of 2012. We have received a conditional permit to build a rail loadout at this location, pending bonding, and we plan to restart production at the McClane Canyon mine when market conditions are favorable.

We define a mining complex as a central location for processing raw coal and loading coal into railroad cars or trucks for shipment to customers. These mining complexes include eight 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.

The following map shows the location of our coal mining and leasing operations as of December 31, 2012:

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 Rhino Eastern joint venture's mining complexes and production by region as of December 31, 2012. The tons produced by the Elk Horn lessees are not included in the table below since we did not directly mine these tons, but rather collected royalty revenues from the lessees.

Region	Preparation Plants and Loadouts	Transportation to Customers(1)		Tons Produced for the Year Ended December 31, 2012(3)

				(in million tons)
Central Appalachia
Tug River Complex (KY, WV)	Tug Fork & Jamboree(4)	Truck, Barge, Rail (NS)	2S		0.4
Rob Fork Complex (KY)	Rob Fork	Truck, Barge, Rail (CSX)	1U, 1S		0.8
Deane Complex (KY)	Rapid Loader	Rail (CSX)	1U		0.2
Northern Appalachia
Hopedale Complex (OH)	Nelms	Truck, Rail (OHC, WLE)	1U		1.2
Sands Hill Complex (OH)	Sands Hill(5)	Truck, Barge	2S		0.7
Illinois Basin
Taylorville Field (IL)	n/a	Rail (NS)	—		—
Pennyrile Energy Field (KY)	n/a	Barge	—		—
Western Bituminous
Castle Valley Complex (UT)	Truck loadout	Truck	1U		1.0
McClane Canyon Mine (CO)(6)	n/a	Truck	—		—

Total			4U,5S		4.3

Central Appalachia
Rhino Eastern Complex (WV)(7)	Rocklick	Truck, Rail (NS, CSX)	2U

Central Appalachia. As of December 31, 2012, we operated four mining complexes located in Central Appalachia consisting of four active underground mines. During 2012, we also had one contractor-operated underground mine that produced steam coal and concluded mining operations as of year-end. In addition, as of December 31, 2012, we operated three company-operated surface mines. For the year ended December 31, 2012, the mines at our Tug River, Rob Fork and Deane mining complexes produced an aggregate of approximately 0.9 million tons of steam coal and an estimated 0.5 million tons of metallurgical coal, and the underground mines at the Rhino Eastern mining complex, owned by the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager, produced approximately 0.3 million tons of metallurgical coal. In addition, for the year ended December 31, 2012, lessees of our Elk Horn properties produced approximately 2.6 million tons of coal.

We temporarily idled a majority of our Central Appalachia operations during the month of June 2012, which allowed us to reduce coal inventories that had increased due to weakness in the met and steam coal markets.

Tug River Mining Complex. Our Tug River mining complex is located in Kentucky and West Virginia that borders the Tug River. This complex produces coal from two company operated surface mines, which includes one high-wall mining unit. Coal production from these operations is delivered to the newly constructed Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail loadout for blending and shipping. The Tug Fork plant is a modern, 350 tons per hour preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit train, batch weigh loadout. This mining complex produced approximately 0.2 million tons of steam coal and approximately 0.2 million tons of metallurgical coal for the year ended December 31, 2012.

Rob Fork Mining Complex. Our Rob Fork mining complex is located in eastern Kentucky and currently produces coal from one company-operated surface mine and one company-operated underground mine. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers' needs. The Rob Fork mining complex produced approximately 0.5 million tons of steam coal and 0.3 million tons of metallurgical coal for the year ended December 31, 2012.

Deane Mining Complex. Our Deane mining complex is located in eastern Kentucky and produces steam coal from one company-operated underground mine. We also had one contractor-operated underground mine at our Deane complex that produced steam coal during 2012 and concluded mining operations as of year-end 2012. 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 0.2 million tons of steam coal for the year ended December 31, 2012.

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

The Rhino Eastern mining complex currently produces premium metallurgical coal from two company-operated underground mines. Raw coal is trucked from the mine to a facility owned by our joint venture partner to be sized, washed and shipped by truck or via one of two rail loadouts, located on the CSX Railroad and the Norfolk Southern Railroad. The Rhino Eastern mining complex produced approximately 0.3 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2012.

On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the Rhino Eastern joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

Elk Horn Coal Leasing. Elk Horn is primarily a coal leasing company located in eastern Kentucky that provides us with coal royalty revenues. For the year ended December 31, 2012, Elk Horn lessees produced approximately 2.6 million tons of coal from our Elk Horn properties.

Northern Appalachia. We operate two mining complexes located in Northern Appalachia consisting of one company-operated underground mine and two company-operated surface mines. For the year ended December 31, 2012, these mines produced an aggregate of approximately 1.9 million tons of steam coal.

Hopedale Mining Complex. The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad in Cadiz, Ohio and then shipped by train or truck to our customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 1.2 million tons of steam coal for the year ended December 31, 2012.

Sands Hill Mining Complex. We operate two surface mines at our Sands Hill mining complex, located near Hamden, Ohio. The infrastructure includes a preparation plant along with a river front barge and dock facility on the Ohio River. The Sands Hill mining complex produced approximately 0.7 million tons of steam coal and approximately 0.5 million tons of limestone aggregate for the year ended December 31, 2012.

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

Castle Valley Mining Complex. In August 2010, we completed the acquisition of certain mining assets of C.W. Mining Company out of bankruptcy. The assets acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We produced approximately 1.0 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2012.

McClane Canyon Mine. The McClane Canyon mine is located near Loma, Colorado and is on property leased from the Bureau of Land Management ("BLM"). We temporarily idled production at this mine at the end of 2010 and the mine remained idle at the end of 2012. We have received a conditional permit to build a rail loadout at this location. We believe access to a rail loadout will enable us to expand our customer base. We plan to restart production at the McClane Canyon mine when market conditions are favorable.

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

In addition to our mining operations, we operate several subsidiaries which provide auxiliary services for our coal mining operations. Rhino Trucking provides our Kentucky coal operations with dependable, safe coal hauling to our preparation plants and loadout facilities and our southeastern Ohio coal operations with reliable transportation to our customers where rail is not available. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining reclamation. Through Rhino Services, we plan and monitor each phase of our mining projects as well 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. Prior to being sold in August 2012, our Triad Roof Support Systems subsidiary manufactured roof control products used in underground coal mining.

In addition to our coal operations, we have invested in oil and natural gas mineral rights and operations that we believe will help to diversify our income stream.

We and an affiliate of Wexford have participated with Gulfport Energy ("Gulfport"), a publicly traded company, to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. During the years ended December 31, 2012 and 2011, we completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $24.2 million. Gulfport is actively drilling in the Utica acreage and during the second of half of 2012, Gulfport released results from seven test wells that had been drilled on our acreage, which we believe are very positive due to the amount of hydrocarbon liquids contained in these wells.

Our initial position in the Utica Shale consisted of a 10.8% net interest in approximately 80,000 gross acres. During the third quarter of 2012, we completed an exchange of our initial 10.8% position for a pro rata interest in 125,000 gross acres under lease by Gulfport and an affiliate of Wexford Capital. Also during the third quarter of 2012, our position was adjusted to a 5% net interest in the 125,000 gross acres, or approximately 6,250 net acres. As of December 31, 2012, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 137,000 gross acres, or approximately 6,850 net acres. In addition, per the joint operating agreement among us, Gulfport and an affiliate of Wexford Capital, we have funded our proportionate share of drilling costs for 2012 to Gulfport for wells being drilled on our acreage. For the year ended December 31, 2012, we funded approximately $5.3 million of drilling costs. We received approximately $248,000 of revenue from this investment for the year ended December 31, 2012 since the drilling and testing of wells began in 2012 and sales did not take place until late in the year. We believe this investment could add to our revenue streams in future periods.

During 2011, we completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. We began to receive royalty revenues from these mineral rights in early 2012 and received approximately $77,000 in royalty revenue during 2012.

In December 2012, we made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppants LLC ("Muskie"), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S. We recorded our proportionate portion of the operating loss for 2012, approximately $257,000, for Muskie, which is still undergoing operational development.

In March 2012, we made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf Terminals LLC ("Timber Wolf"), with affiliates of Wexford Capital. Timber Wolf was

formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio. The initial investment was our proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during 2012.

In addition, during the second quarter of 2012 we formed a services company ("Razorback") to provide drill pad construction services in the Utica Shale for drilling operators. Razorback completed the construction of three drill pads during 2012.

In March 2012, we completed a lease agreement with a third party for approximately 1,232 acres that we previously owned in the Utica Shale region in Harrison County, Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the third party to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay us the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232 acres. We are working to resolve title issues on approximately 250 remaining acres to be included in the lease. In addition, the lease agreement stipulates that the third party shall pay us a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

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

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 Rhino Eastern joint venture, for the year ended December 31, 2012, approximately 90% of our coal sales tons consisted of steam coal and approximately 10% consisted of metallurgical coal. For the year ended December 31, 2012, 100% of the Rhino Eastern joint venture's coal sales tons consisted of metallurgical coal. For the year ended December 31, 2012, excluding results from the Rhino Eastern joint venture, approximately 73% of our coal sales tons that we produced were sold to electric utilities. The majority of our electric utility customers purchase coal for terms of one to three years, but we also supply coal on a spot basis for some of our customers. Excluding the results from the Rhino Eastern joint venture, for the year ended December 31, 2012, we derived approximately 92.0% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 43.1% of our coal revenues for that period: NRG Energy, Inc. (fka GenOn Energy, Inc.) (17.6%); Indiana Harbor (13.2%); and PPL Corporation (12.3%). Additionally, pursuant to the terms of a coal purchase agreement entered into under the Rhino Eastern joint venture agreement, we sell 100% of Rhino Eastern's production to an affiliate of our joint venture partner, Patriot, which controls the amount and terms of sales of the coal produced from Rhino Eastern. 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.

For the years ended December 31, 2012 and 2011, approximately 89% and 77%, 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. As of December 31, 2012, we had commitments under supply contracts to deliver annually scheduled base quantities of 3.9 million, 2.5 million, 1.4 million, 1.1 million and 1.1 million tons of coal to 16 customers in 2013, 7 customers in 2014, 4 customers in 2015, 2 customers in 2016 and 2 customers in 2017, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

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.

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

We ship coal to our customers by rail, truck or barge. For the year ended December 31, 2012, 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 use third-party trucking to transport coal to our customers in Utah. 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.

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.

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

Our operations are subject to regulation by federal, state and local authorities on matters such as:

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, oil and natural gas investments, or our customers' ability to use coal.

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

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

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

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

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

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 an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act contains criminal liability provisions. For example, criminal liability may be imposed for corporate operators who knowingly or willfully authorize, order or carry out violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations.

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

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

Our non-fatal days lost time incidence rate for all operations for the year ended December 31, 2012 was 1.27 as compared to the most recent national average of 2.40, as reported by MSHA, or 47.08% below this national average. Non-fatal days lost incidence rate is an industry standard used to describe occupational injuries that result in loss of one or more days from an employee's scheduled work. In addition, for the year ended December 31, 2012 our average MSHA violations per inspection day was 0.51 as compared to the most recent national average of 0.87 violations per inspection day as reported by MSHA, or 41.38% below this national average.

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

Indeed, effective March 25, 2013, MSHA will begin implementing its recently released Pattern of Violation ("POV") regulations under the Mine Act. Under this new POV regulation, MSHA will eliminate the ninety (90) day window to take corrective action and engage in mitigation efforts for mine operators who met certain initial POV screening criteria. Additionally, MSHA will make POV determinations based upon enforcement actions as issued, rather than enforcement actions that have been rendered final following the opportunity for administrative or judicial review. After a mine operator has been placed on POV status, MSHA will thereafter issue an order withdrawing miners from the area affected by any enforcement action designated by MSHA as posing a significant and substantial, or S&S, hazard to the health and/or safety of miners. Further, once designated as a POV mine, a mine operator can be removed from POV status only upon: (1) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA; or (2) no POV-related withdrawal orders being issued by MSHA within ninety (90) days of the mine operator being placed on POV status. Although it remains to be seen how these new regulations will ultimately affect production at our mines, they are consistent with the trend of more stringent enforcement.

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, 2012 (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. Any suspension of operations at any one of our locations that may occur in the future may have material financial or operational consequences for us.

It is our practice to contest notices of violations in cases in which we believe we have a good faith defense to the alleged violation or the proposed penalty and/or other legitimate grounds to challenge the alleged violation or the proposed penalty. In December 2008 and March 2009, MSHA assessed proposed penalties in excess of $100,000 with regard to three separate notices of violation, all of which relate to our operations at Mine 28. Each of these notices of violation alleged an "unwarrantable

failure" under the Mine Act with specific regard to the accumulation of combustible materials. The combustible materials typically underlying such citations are coal, loose coal, and float coal dust. We have contested these violations on grounds that the underlying circumstances did not support the issuance of a notice of violation and/or the gravity of the proposed penalty. These contests are still pending and we cannot predict the outcome of these proceedings or assure you that the fines and penalties will not be assessed in full against us. These alleged violations were abated at the time or immediately after the notices of violation were issued, and we have not been issued any notices of violation from MSHA proposing a penalty in excess of $100,000 since March 2009.

We exercise substantial efforts toward achieving compliance at our mines. In light of the recent citations issued with respect to our mines, we have further increased our focus with regard to health and safety at all of our mines and at Mine 28 and Eagle #1 Mine in particular. These efforts include hiring additional skilled personnel, providing training programs, hosting quarterly safety meetings with MSHA personnel and making capital expenditures in consultation with MSHA aimed at increasing mine safety. We believe that these efforts have contributed, and continue to contribute, positively to safety and compliance at our mines. In Item 4. Mine Safety Disclosure and in Exhibit 95 to this Annual Report on Form 10-K, we provide additional details on how we monitor safety performance and MSHA compliance, as well as provide the mine safety disclosures required pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Under the Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, coal mine operators must make payments of black lung benefits to current and former coal miners with black lung disease, some survivors of a miner who dies from this disease, and to fund a trust fund for the payment of benefits and medical expenses to claimants who last worked in the industry prior to July 1, 1973. 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. This excise tax does not apply to coal that is exported outside of the United States. In 2012, we recorded approximately $3.8 million of expense related to this excise tax.

The Patient Protection and Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. We may also be liable under state laws for black lung claims that are covered through either insurance policies or state programs.

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.

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 for the period from October 1, 2012 through September 30, 2021, has been decreased to 28 cents per ton on surface mined coal and 12 cents per ton on underground mined coal. As of December 31, 2012, we had accrued approximately $33.0 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 a mine 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 or modifications of existing mining permits, although we know of no basis by which we would be (and we are not now) permit-blocked.

In addition, on November 30, 2009, the Office of Surface Mining Reclamation and Enforcement ("OSM") published an advance notice of proposed rulemaking to revise the "stream buffer zone rule," or SBZ Rule, that prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality. OSM had previously issued a Stream Buffer Zone rule in December 2008 that would have provided certain exemptions to the requirement for a 100-foot buffer around all waters, including streams, lakes, ponds, and wetlands. The new rule has not yet been proposed or finalized. OSM is currently developing an environmental impact statement for use in drafting the anticipated stream protection rule. 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 new stream protection rule or future legislation, when adopted, will likely be stricter than the prior SBZ Rule to further protect streams from the impact of surface mining, and may adversely affect our business and operations.

Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

As of December 31, 2012, we had approximately $71.0 million in surety bonds outstanding to secure the performance of our reclamation obligations. We may be required to increase these amounts as a result of recent developments in West Virginia and Kentucky. In 2011, West Virginia passed legislation that provides for a minimum incremental bonding rate in lieu of a minimum bond amount that applies regardless of acreage. In addition, the Kentucky Department for Natural Resources and the Office of Surface Mining Reclamation and Enforcement Lexington Field Office executed an Action Plan for Improving the Adequacy of Kentucky Performance Bond Amounts, which provides for, among other things, revised bond computation protocols.

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.

In addition to the carbon dioxide regulations discussed below, air emission control programs that affect our operations, directly or indirectly, include, but are not limited to, the following:

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

On June 16, 2010, several environmental groups petitioned the EPA to list coal mines as a source of air pollution and establish emissions standards under the CAA for several pollutants, including particulate matter, nitrogen oxide gases, volatile organic compounds, and methane. Petitioners further requested that the EPA regulate other emissions from mining operations, including dust and clouds of nitrogen oxides associated with blasting operations. These same groups filed suit against the EPA in November of 2011 in the federal court for the District of Columbia seeking the EPA's listing of coal mines as a New Source Performance Standard category. If the petitioners are successful, emissions of these or other materials associated with our mining operations could become subject to further regulation pursuant to existing laws such as the CAA. In that event, we may be required to install additional emissions control equipment or take other steps to lower emissions associated with our operations, thereby reducing our revenues and adversely affecting our operations.

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

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

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

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

All of these regulations are subject to legal challenges, but the D.C. Circuit has refused to stay their implementation while the challenges are pending. On June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit rejected challenges to the Tailoring Rule and other EPA rules relating to the regulation of GHGs under the CAA. On March 27, 2012, the EPA proposed New Source Performance Standards ("NSPS") for carbon dioxide emissions from new and modified EGUs. The final NSPS, if promulgated along the lines proposed, would pose significant challenges for the construction of new coal-fired power plants and could result in a decrease in U.S. demand for steam 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 2005, ten northeastern states entered into 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. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.

Following the RGGI model, five Western states 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. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 12, 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.

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

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

The Federal Clean Water Act, or the CWA, and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the U.S. The CWA establishes in-stream water quality and treatment standards for wastewater discharges that are applied to wastewater dischargers through Section 402 National Pollutant Discharge Elimination System, or NPDES, permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into waters of the U.S. including wetlands, streams, and other areas meeting the regulatory definition. Our surface coal mining and preparation plant operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA, or a state that has been delegated such authority by the EPA, issues NPDES permits for the discharge of pollutants into navigable waters, while the U.S. Army Corps of Engineers, or the Corps, issues dredge and fill permits under Section 404 of the CWA. Where Section 402 NPDES permitting authority has been delegated to a state, the EPA retains a limited oversight role. The CWA also gives the EPA an oversight role in the Section 404 permitting program, including drafting substantive rules governing permit issuance by the Corps, providing comments on proposed permits, and, in some cases, exercising the authority to delay or pre-empt Corps issuance of a Section 404 permit. The EPA has recently asserted these authorities more forcefully to question, delay, and prevent issuance of some Section 402 and 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

For instance, even though the Commonwealth of Kentucky and the State of West Virginia have been delegated the authority to issue NPDES permits for coal mines in those states, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. The EPA issued final guidance on July 21, 2011 that encouraged EPA Regions 3, 4 and 5 to 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 with regard to state issued general Section 404 permits, support the previously drafted Enhanced Coordination Process ("ECP") among the EPA, the Corps, and the U.S. Department of the Interior for issuing Section 404 permits, whereby the EPA undertook a greater level of review of certain Section 404 permits than it had previously undertaken. On October 6, 2011, the District Court for the District of Columbia rejected the ECP on several different legal grounds and later this same court enjoined EPA from any further usage of its final guidance. Any future application of procedures similar to ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

The EPA also has statutory "veto" power under Section 404(c) to effectively revoke a previously issued Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an "unacceptable adverse effect." On January 14, 2011, the EPA exercised its Section 404(c) authority to withdraw or restrict the use of a previously issued permit for the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA's exercise of this authority was made in the federal District Court in the District of Columbia and on March 23, 2012, the Court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. This decision is currently on appeal. Any future use of the EPA's Section 404 "veto" power could create uncertainty with regard to our or 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.

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 in February 2012, the Corps reinstated the use of NWP 21, but limited application of NWP 21 authorizations to discharges with impacts not greater than a half-acre of water, including no more than 300 linear feet of streambed, and disallowed the use of NWP 21 for valley fills. If the newly issued NWP 21 cannot be used for any of our proposed surface coal mining projects, we will have to obtain individual permits from the Corps subject to the additional EPA measures discussed below with the uncertainties and delays attendant to that process.

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

Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired 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. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDLs and load allocations or any changes to antidegradation policies for streams near our coal mines could limit our ability to obtain NPDES permits, require more costly water treatment, and adversely affect our coal production.

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

The federal Resource Conservation and Recovery Act, or RCRA, and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by

SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous wastes. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

On June 21, 2010, EPA released a proposed rule to regulate the disposal of certain coal combustion by-products, or CCB. The proposed rule sets forth two proposed avenues for the regulation of CCB under RCRA. The first option calls for regulation of CCB under Subtitle C as a hazardous waste, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option calls for regulation of CCB under Subtitle D as a solid waste, which gives EPA authority to set performance standards for solid waste management facilities and would be enforced primarily through state agencies and citizen suits. Under both options, the EPA would establish dam safety requirements to address structural integrity of surface impoundments to prevent catastrophic releases. The proposal leaves intact the Bevill exemption for beneficial uses of CCB, except for land application. In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule. If CCB were re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCB, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

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

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

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.

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.

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 is not expected to have a material adverse effect on our business, financial condition or results of operations.

Hydraulic fracturing is an important and common oil and natural gas industry practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Gulfport, as the operator on our Utica Shale acreage, and operators on our Cana Woodford acreage routinely use hydraulic fracturing techniques in many of their drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including New York, have adopted and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic

fracturing activities in particular. We believe that Gulfport and operators on our Cana Woodford acreage follow applicable standard industry practices and legal requirements for groundwater protection in their hydraulic fracturing activities. Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where operators conduct fracturing activities on our oil and natural gas acreage, these operators could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from hydraulic fracturing operations in any of our oil and natural gas investments. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our pollution liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

To carry out our operations, our general partner and our subsidiaries, excluding our Rhino Eastern joint venture, employed 750 full-time employees as of December 31, 2012. 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.

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.

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. If any of these risks or uncertainties, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, were to occur, our business, financial condition or results of operation could be materially adversely affected and you may lose all or a significant part of your investment.

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

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.445 per unit, or $1.78 per unit per year, which will require us to have available cash of approximately $12.6 million per quarter, or $50.4 million per year, based on the number of common and subordinated units outstanding as of December 31, 2012 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

In addition, we have not paid any distributions on our subordinated units with respect to the quarters ended June 30, 2012, September 30, 2012 or December 31, 2012. We may not have sufficient cash available for distributions on our subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay the minimum quarterly distribution on our common units in full. Moreover, we may not be able to increase distributions on our common units if we are unable to pay the full minimum quarterly distribution on our subordinated units.

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:

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 and steel 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.

In addition, the prices of oil and natural gas may fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. A sustained decline in these commodity prices could materially adversely affect the level of return on our oil and natural gas investments in the Utica Shale and Cana Woodford regions. Significant or extended price declines could also adversely affect the amount of oil and natural gas that Gulfport or our oil and natural gas lessees in the Cana Woodford

region can economically produce, which could result in a shortfall in expected cash flows from each investment.

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 and wind 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. The competitive environment for coal is impacted by a number of the largest markets in the world, including the United States, China, Japan and India, where demand for both electricity and steel has 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.

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 Rhino Eastern joint venture, steam coal accounted for approximately 90% of our coal sales volume for the year ended December 31, 2012. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which

could materially adversely affect our results of operations and cash available for distribution to our unitholders.

Our Rhino Eastern joint venture partner filed for a Chapter 11 bankruptcy, which may affect the joint venture's future results of operations.

We entered into the Rhino Eastern joint venture with an affiliate of Patriot to acquire the Eagle mining complex in May 2008. On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. The Patriot bankruptcy proceedings have not had a material effect on the operations of Rhino Eastern. However, we cannot assure investors that the bankruptcy process will not affect the future operations of Rhino Eastern. For example, the coal produced at Rhino Eastern is processed at a nearby preparation plant that is owned and operated by Patriot. If Patriot were to discontinue operations at the preparation plant, we would be required to transport the coal via truck to another preparation plant, which would increase both the logistical complexity and the costs associated with Rhino Eastern's operations. A material decrease in production and sales from our Rhino Eastern joint venture, or increase in the costs of such sales, could have a material adverse impact on our results of operations and cash available for distribution to unitholders.

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

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

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

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

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

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

Subsequent to passage of the MINER Act, various coal producing states, including West Virginia, Ohio and Kentucky, have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Additional federal and state legislation that would further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has also been considered.

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

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

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

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

On June 24, 2011, our subsidiary, CAM Mining LLC received notice that on June 23, 2011, MSHA commenced an action in the U.S. District Court of the Eastern District of Kentucky seeking injunctive relief as a result of alleged violations of Sections 103, 104, and 108 of the Mine Act occurring at Mine 28 in connection with an inspection on June 17, 2011 by MSHA inspectors. The complaint alleges that when MSHA inspectors arrived at Mine 28 to inspect the mine with respect to the allegations that employees had been smoking underground, CAM Mining LLC employees gave advance notice of the inspection to miners working underground and that this advance notice hindered, interfered with and delayed the inspection by MSHA. The complaint asserts that the MSHA inspectors did not find any evidence of smoking paraphernalia during the inspection, which was allegedly the result of this advance notice. On June 30, 2011, MSHA obtained a temporary restraining order prohibiting such further violations. We continue to investigate the allegations in the complaint and intend to continue to fully cooperate with MSHA to ensure that all mine safety and health regulations are being complied with at our mines.

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

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

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

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

Please read "Part I, Item 1. Business—Regulation and Laws—Clean Water Act" for a discussion of recent litigation and regulatory developments related to the CWA. An inability to obtain the necessary

permits to conduct our mining operations or an inability to comply with the requirements of applicable permits would reduce our production and cash flows, which could limit our ability to make distributions to our unitholders.

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

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

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

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

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

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer's purchasing decision. Increases

in transportation costs could make coal a less competitive energy source or could make our coal production less competitive than coal produced from other sources.

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

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

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 Rhino Eastern's mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our and Rhino Eastern's actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our and Rhino Eastern's coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.

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

Part of our business strategy is to expand our operations through strategic acquisitions, which includes investing in non-coal natural resources assets. Our executive officers do not have experience investing in or operating non-coal natural resources assets and we may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural resource assets could expose us to new and additional operating and regulatory risks, including commodity price risk, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

As of December 31, 2012, we have invested approximately $8.1 million and $24.2 million for mineral rights in the Cana Woodford region of Oklahoma and oil and natural gas leases in the Utica Shale region of eastern Ohio, respectively. In addition, our 2013 projected expansion capital expenditures include an estimated $15 million to $20 million for our oil and gas investments, primarily for drilling costs related to our Utica Shale acreage. The oil and natural gas markets are highly volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Such fluctuations could cause us not to realize the full benefits from such investments.

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

We are not the operator of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

We are not the operator of the oil and natural gas properties in which we hold interests and may have limited ability to exercise influence over the operations of these and our other non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploration activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.

Numerous uncertainties exist in estimating quantities of oil and natural gas proved reserves and future net cash flows therefrom. The estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate.

Petroleum engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

Because all proved oil and natural gas reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

Furthermore, different reserve engineers may make different estimates of proved oil and natural gas reserves and cash flows based on the same available data. Actual production, revenues and expenditures will likely be different from estimates, and the differences may be material.

As required by the SEC, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on average prices preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

PV-10 is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. In general, it requires the use of commodity prices that are based upon a 12-month unweighted average, as well as operating and development costs

being incurred at the end of the reporting period. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and other risks associated with the properties or the oil and natural gas industry in general. Therefore, the estimates of discounted future net cash flows should not be construed as accurate estimates of the current market value of our Utica Shale proved oil and natural gas reserves.

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 are $10 to $15 million for 2013. 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 and impacting climate. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of GHG. Many states have already taken legal measures to reduce emissions of GHG, primarily through the development of regional GHG cap-and-trade programs.

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

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

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

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

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

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 adverse 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, 2012, we had $71.0 million in reclamation surety bonds, secured by $18.2 million in letters of credit outstanding under our credit agreement. Our credit agreement provides for a $300 million working capital revolving credit facility, of which up to $75.0 million may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations. For more information, please read "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement." If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

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

We sell a material portion of our coal under supply contracts. As of December 31, 2012 we had sales commitments for approximately 100% of our estimated coal production (including purchased coal to supplement our production and excluding results from the Rhino Eastern joint venture) for the year ending December 31, 2013. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of our total future committed tons, under the terms of the supply contracts, we will ship 39% in 2013, 25% in 2014, 14% in 2015, 11% in 2016 and 11% in 2017. We derived approximately 92.0% of our total revenues from coal sales (excluding results from the joint venture) to our ten largest customers for the year ended December 31, 2012, with affiliates of our top three customers accounting for approximately 43.1% 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."

Certain provisions in our long-term coal 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 coal supply contracts permit the customer to terminate the agreement in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit.

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

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

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

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

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

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

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

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

We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with the coal lessees, or internal control deficiencies.

Defects in title in the coal 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 coal 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 coal reserves would be adversely affected by defects in title or boundaries or if a lease expires. Any challenge to our title or leasehold interest could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on a lease that we are unable to renew on terms at least as favorable, if at all. In such event, we may have to close down or significantly alter the sequence of mining operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur liability for such mining. Our sponsor, Wexford Capital, will not indemnify us for losses attributable to title defects in the properties that we own or lease.

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

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

We depend on the services of our senior management team and other key personnel, including senior management of our general partner. 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.

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:

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, 2012 our current portion of long-term debt that will be funded from cash flows from operating activities during 2013 was

approximately $2.4 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:

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:

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."

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

Wexford owns and controls our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Therefore, conflicts of interest may arise between its owners and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our common unitholders. These conflicts include the following situations:

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

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

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

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

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

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

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

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

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:

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

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

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

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive

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

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

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and will retain its then-current general partner interest. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.

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

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

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

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of February 28, 2013, Wexford owned an aggregate of approximately 64% 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.

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

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. As of February 28, 2013, Wexford owned an aggregate of approximately 48% of our common units and approximately 84% of our subordinated units.

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

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

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, 2012, we had 15,358,699 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. Pursuant to a registration rights agreement entered into in connection with the closing of our IPO, we filed a resale shelf registration statement pursuant to which we registered the common units held by Wexford, and may be required to register any common units they hold that converted at the end of the subordination period. We may be required to undertake an underwritten offering to facilitate the sale of units held by Wexford or its permitted assignees under the registration rights agreement. In addition, under our partnership agreement, our general partner and its affiliates (including Wexford) have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations. Sales by Wexford or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.

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. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Wexford) after the subordination period has ended. As of February 28, 2013, Wexford owned approximately 48% of the outstanding common units and 84% of our outstanding subordinated units.

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

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

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

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

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

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a "qualifying income" requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for 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.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or judicial changes or differing interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such change could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax law may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity- level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for federal or

state tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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. 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. 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, unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive 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 their share of our taxable 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 result in a decrease in 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 of depreciation and deductions and certain other items. In addition, because the amount realized includes your share of our 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.

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes, 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 your tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, 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 generally prorate our items of income, gain, loss and deduction, for U.S. federal income tax purposes, between transferors and transferees of our common 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 common 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 and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change our allocation of items of income, gain, loss and deduction among our unitholders.

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

Because there is no tax concept of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner in us with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, 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 should 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 constructively 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 the 50% threshold has been met, multiple sales of the same unit will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has 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.

The Fiscal Year 2013 Budget proposed by the President recommends elimination of certain key U.S. federal income tax preferences relating to coal exploration and development (the "Budget Proposal"). The Budget Proposal would (1) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal and lignite royalties, and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or 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 conduct 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.

See "Part I, Item 1. Business" for information about our coal operations and other natural resource assets.

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

Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our and Rhino Eastern's coal reserve and non-reserve coal deposit estimates was completed by Cardno MM&A, as of December 31, 2012, and covered a majority of the coal reserves and non-reserve coal deposits that we and Rhino Eastern controlled as of such date. The coal reserve and non-reserve coal deposit estimates for the Castle Valley mining complex in Utah were audited by Norwest Corporation as of December 31, 2012 due to this firm's familiarity with the coal reserves at this location, as Norwest Corporation performed the initial coal reserve audit when we purchased Castle Valley in August 2010. Additionally, the coal reserve and non-reserve coal deposit information for our Elk Horn operation was audited by John T. Boyd Company as of December 31, 2012 due to this firm's familiarity with the coal reserves at this location, as John T. Boyd performed the coal reserve audit in connection with our acquisition of Elk Horn in June 2011. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

As of December 31, 2012, we controlled an estimated 463.7 million tons of proven and probable coal reserves and an estimated 417.4 million tons of non-reserve coal deposits. As of December 31, 2012, Rhino Eastern controlled an estimated 43.1 million tons of proven and probable coal reserves and an estimated 17.9 million tons of non-reserve coal deposits.

The following table provides information as of December 31, 2012 on the type, amount and ownership of the coal reserves:

	Proven and Probable Coal Reserves(1)

Region	Total(3)		Proven			Probable			Assigned			Unassigned			Owned			Leased			Steam(2)			Metallurgical(2)
	(in million tons)
Central Appalachia
Tug River Complex (KY, WV)		22.6		17.4			5.2			18.6			4.0			5.0			17.6			17.0			5.6
Rob Fork Complex (KY)		23.7		20.3			3.4			23.7			—			7.5			16.2			17.0			6.7
Deane Complex (KY)		39.3		23.6			15.7			6.8			32.5			39.2			0.1			39.3			—
Rich Mountain Field (WV)		8.6		1.5			7.1			—			8.6			8.6			—			—			8.6
Elk Horn (KY)		116.2		80.5			35.7			56.8			59.4			113.8			2.4			116.2			—

Total Central Appalachia(3)		210.4		143.3			67.1			105.9			104.5			174.1			36.3			189.5			20.9

Northern Appalachia
Hopedale Complex (OH)		26.5		19.8			6.7			9.3			17.2			10.3			16.2			26.5			—
Sands Hill Complex (OH)		10.0		8.4			1.6			10.0			—			1.1			8.9			10.0			—
Leesville Field (OH)		27.0		7.8			19.2			—			27.0			27.0			—			27.0			—
Springdale Field (PA)		13.8		8.8			5.0			—			13.8			13.8			—			13.8			—

Total Northern Appalachia(3)		77.3		44.8			32.5			19.3			58.0			52.2			25.1			77.3			—

Illinois Basin
Taylorville Field (IL)		111.0		38.7			72.3			—			111.0			—			111.0			111.0			—
Pennyrile Field (KY)		32.5		17.5			15.0			—			32.5			—			32.5			32.5			—

Total Illinois Basin(3)		143.5		56.2			87.3			—			143.5			—			143.5			143.5			—

Western Bituminous
Castle Valley Complex (UT)		26.1		14.9			11.2			26.1			—			—			26.1			26.1			—
McClane Canyon Mine (CO)		6.4		4.4			2.0			6.4			—			0.2			6.2			6.4			—

Total Western Bituminous(3)		32.5		19.3			13.2			32.5			—			0.2			32.3			32.5			—

Total(3)		463.7		263.6			200.1			157.7			306.0			226.5			237.2			442.8			20.9

Percentage of total(3)				56.8	%		43.2	%		34.0	%		66.0	%		48.8	%		51.2	%		95.5	%		4.5	%
Central Appalachia
Rhino Eastern Complex (WV)(4)		43.1		23.4			19.7			38.4			4.7			—			43.1			—			43.1
Percentage of total(3)				54.3	%		45.7	%		89.1	%		10.9	%		0.0	%		100.0	%		0.0	%		100.0	%

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 Rhino Eastern's coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our and the joint venture's leased priorities are not completely verified until we prepare to mine those reserves.

The following table provides information on particular characteristics of our and Rhino Eastern's coal reserves as of December 31, 2012:

	As Received Basis(1)										Proven and Probable Coal Reserves(2)

													Sulfur Content
									S02/mm Btu				Sulfur Content
Region	% Ash			% Sulfur			Btu/lb.		S02/mm Btu		Total		<1%			1 - 1.5%			>1.5%			Unknown
											(in million tons)
Central Appalachia
Tug River Complex (KY, WV)		10.61	%		1.23	%		12,899		1.91		22.6		13.5			5.3			2.5			1.3
Rob Fork Complex (KY)		6.04	%		1.17	%		13,395		1.74		23.7		14.2			5.7			2.2			1.6
Deane Complex (KY)		5.39	%		0.91	%		13,442		1.35		39.3		21.0			11.2			1.0			6.1
Rich Mountain (WV)		6.56	%		0.64	%		13,509		0.94		8.6		8.6			—			—			—
Elk Horn (KY)		11.50	%		1.51	%		13,100		2.31		116.2		17.9			48.8			49.6			—

Total Central Appalachia		9.45	%		1.29	%		13,192		1.96		210.4		75.2			71.0			55.3			9.0

Northern Appalachia
Hopedale Complex (OH)		6.59	%		2.25	%		12,999		3.46		26.5		—			—			26.5			—
Sands Hill Complex (OH)		9.29	%		3.13	%		11,779		5.31		10.0		—			—			9.5			0.5
Leesville Field (OH)		6.21	%		2.21	%		13,152		3.36		27.0		—			—			27.0			—
Springdale Field (PA)		6.63	%		1.72	%		13,443		2.55		13.8		—			—			13.8			—

Total Northern Appalachia		6.81	%		2.26	%		12,974		3.48		77.3		—			—			76.8			0.5

Illinois Basin
Taylorville Field (IL)		7.75	%		3.53	%		11,057		6.38		111.0		—			—			111.0			—
Pennyrile Field (KY)		7.50	%		2.44	%		11,460		4.26		32.5		—			—			32.5			—

Total Illinois Basin		7.69	%		3.28	%		11,148		5.89		143.5		—			—			143.5			—

Western Bituminous
Castle Valley Complex (UT)		10.99	%		0.72	%		12,127		1.16		26.1		25.9			0.2			—			—
McClane Canyon Mine (CO)		11.19	%		0.57	%		11,241		1.01		6.4		6.4			—			—			—

Total Western Bituminous		11.03	%		0.69	%		11,951		1.16		32.5		32.3			0.2			—			—

Total		8.05	%		1.86	%		11,634		3.19		463.7		107.5			71.2			275.6			9.5

Percentage of total														23.2	%		15.3	%		59.4	%		2.0	%
Central Appalachia
Rhino Eastern Complex (WV)(3)		4.42	%		0.68	%		14,019		0.97		43.1		37.7			4.9			—			0.5

The following table provides information on our and Rhino Eastern's non-reserve coal deposits as of December 31, 2012:

The Rhino Eastern 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.

We and an affiliate of Wexford Capital have participated with Gulfport, a publicly traded company, to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale region of eastern Ohio. As of December 31, 2012, our assets in this region consisted of a 5% non-operated working interest in a total of 137,000 acres, or 6,850 net acres. Per a joint operating agreement completed between us, Gulfport (the operator) and an affiliate of Wexford Capital, we began to fund our proportionate share of drilling costs to Gulfport for wells that began to be drilled in 2012 on our acreage.

Our oil and natural gas reserve estimates at December 31, 2012 were prepared by Ryder Scott Company L.P. ("Ryder Scott") with respect to our assets in the Utica Shale region, based on technical information supplied by Gulfport. Ryder Scott is an independent petroleum engineering firm and a copy of their summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. Ryder Scott has been providing petroleum consulting services throughout the world for over 75 years. The primary technical person responsible for overseeing the estimate of the reserves presented herein has been employed with Ryder Scott since 1981 and is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of Ryder Scott in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, he served in a number of engineering positions. He graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has fulfilled the work experience and continuing education requirements of the Texas Board of Professional Engineers, and based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, he has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III

of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers.

Gulfport, the operator of our Utica Shale properties, supplied substantially all of the underlying data to Ryder Scott in its preparation of our reserve estimates. Gulfport maintains an internal staff of petroleum engineers and geoscience professionals. Given the relative size and nature of our oil and gas investments in the Utica Shale, management has concluded that at this time it is reasonable and appropriate not to employ our own internal staff of petroleum engineers and geoscience professionals for purposes of our oil and gas investments. While we have no formal committee specifically designated to review the Ryder Scott reserve report and the reserves estimation process, members of senior management reviewed the Ryder Scott reserve report with representatives of Ryder Scott.

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with SEC definitions. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely than not to be achieved." Production information for the Utica Shale is limited. For those of our wells on production, performance methods were used. All of the proved undeveloped reserves included herein were estimated by the analogy method.

We have not provided oil and natural gas reserve estimates pertaining to our Cana Woodford assets in western Oklahoma since we only have a royalty interest in these assets and the information is unavailable. Our share of the oil and natural gas produced from our Cana Woodford assets was immaterial for the year ended December 31, 2012.

The following table sets forth our proportionate interest in our Utica Shale estimated proved oil and natural gas reserves at December 31, 2012. Prior years are not presented as exploration and production did not begin until early 2012.

(1): Proved undeveloped oil and natural gas reserves will be converted from undeveloped to developed as the applicable wells begin production.
(2): Estimates of reserves as of December 31, 2012 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on the first day of each month within the 12-month period ended December 31, 2012, in accordance with guidelines of the SEC applicable to reserves estimates as of year-end. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
(3): Represents present value, discounted at 10% per annum, of estimated future net revenue of our estimated proven oil and natural gas reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved oil and natural reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our oil and natural reserve reports for the year ended December 31, 2012 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December for 2012, using $94.71 per barrel for oil/condensate, $43.24 per barrel for natural gas liquids and $2.76 per Mcf for natural gas, and in each case adjusted by lease for transportation fees and regional price differentials.

PV-10 is considered a non-GAAP measure. The standardized measure of discounted future net cash flows is the most directly comparable GAAP financial measure. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. However, our PV-10 is equal to our standardized measure of discounted future net cash flows because our standardized measure does not include the impact of future federal income taxes because we are not subject to federal income taxes. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our oil and natural gas properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the

	For the year ended December 31, 2012

Production Volumes:
Oil (MBbls)		2.0
Gas (MMcf)		21.8
Natural gas liquids (MGal)		5.2
Oil equivalents (MBOE)		5.8
Average Prices:
Oil (per Bbl)	$	78.08
Gas (per Mcf)	$	3.82
Natural gas liquids (per Gal)	$	1.63
Oil equivalents (per BOE)	$	43.03
Average Production Costs:
Average production costs (per BOE)	$	7.10
Average production taxes (per BOE)	$	0.22

Total production costs and production taxes (per BOE)	$	7.32

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

Our common units began trading on the NYSE under the symbol "RNO" on September 30, 2010. On February 28, 2013, the closing market price for our common units was $14.05 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 February 28, 2013, we had outstanding 15,358,699 common units, 12,397,000 subordinated units, a 2% general partner interest and incentive distribution rights, or IDRs. As of February 28, 2013, Rhino Energy Holdings LLC owned approximately 39.1% of our outstanding common units and 69.4% of our subordinated units. Our general partner currently owns a 2.0% general partner interest in us and all of our IDRs.

As of February 28, 2013, there were 96 holders of record of our common units. The number of record holders does not include holders of units in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

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

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

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 includes 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 have not paid distributions on our subordinated units with respect to the quarters ended June 30, 2012, September 30, 2012 and December 31, 2012.

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.

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 and for the years ended December 31, 2009 and 2008 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, 2010 are derived from our audited historical consolidated financial statements that are not included in this report. The selected historical consolidated financial data presented as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010 are derived from our audited historical consolidated financial statements that are included elsewhere in this report.

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

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

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

	For the Year Ended December 31,

(in thousands, except per unit and per ton data)	2012			2011			2010			2009			2008
Statement of Operations Data:
Total revenues	$	351,991		$	367,221		$	305,647		$	419,790		$	438,924
Costs and Expenses:
Cost of operations (exclusive of depreciation, depletion and amortization)		247,105			267,180			220,756			336,335			364,912
Freight and handling costs		5,833			4,329			2,634			3,991			10,223
Depreciation, depletion and amortization		41,370			36,325			34,108			36,279			36,428
Selling, general and administrative (exclusive of depreciation, depletion and amortization)		20,442			21,815			16,449			16,754			19,042
Asset impairment loss		—			—			652			—			—
(Gain) loss on sale/acquisition of assets—net		(4,890	)		(3,172	)		(10,716	)		1,710			451

Total costs and expenses		309,860			326,477			263,883			395,069			431,056

Income from operations		42,131			40,744			41,764			24,721			7,868
Interest and other income (expense):
Interest expense and other		(7,767	)		(6,062	)		(5,338	)		(6,222	)		(5,500	)
Interest income and other		92			51			24			70			148
Equity in net income (loss) of unconsolidated affiliate		5,766			3,338			4,699			893			(1,587	)

Total interest and other income (expense)		(1,909	)		(2,673	)		(615	)		(5,259	)		(6,939	)

Income before income tax		40,222			38,071			41,149			19,462			929
Income tax		—			—			—			—			—

Net income	$	40,222		$	38,071		$	41,149		$	19,462		$	929

Basic and diluted net income per limited partner common unit(1)	$	1.42		$	1.43		$	0.22			n/a			n/a
Distributions paid per limited partner unit	$	1.85			1.8108			n/a			n/a			n/a
Weighted average number of limited partner common units outstanding:
Basic		15,331			13,725			12,400			n/a			n/a
Diluted		15,335			13,744			12,413			n/a			n/a
Balance Sheet Data:
Cash and cash equivalents	$	461		$	449		$	76		$	687		$	1,937
Property and equipment, net		463,960			450,116			282,577			270,680			282,863
Total assets		559,458			538,794			358,645			339,984			352,536
Total liabilities		253,816			231,696			111,028			201,583			234,225
Total debt—short term and long term		163,549			143,098			36,528			122,138			138,027
Partners' capital/Members' equity	$	305,642		$	307,098		$	247,617		$	138,401		$	118,311
Operating Data(2):
Tons of coal sold		4,670			4,876			4,306			6,699			7,977
Tons of coal produced/purchased		4,699			4,873			4,312			6,732			8,017
Coal revenues per ton(3)	$	65.22		$	68.47		$	67.32		$	59.98		$	51.25
Cost of operations per ton(4)	$	52.91		$	54.79		$	51.27		$	50.21		$	45.75
Other Financial Data:
Net cash provided by operating activities	$	79,744		$	66,916		$	55,001		$	41,495		$	57,211
Net cash used in investing activities		(58,404	)		(188,024	)		(37,644	)		(27,344	)		(106,638	)
Net cash (used in) provided by financing activities		(21,328	)		121,481			(17,968	)		(15,401	)		47,781
Adjusted EBITDA		90,508			81,994			71,473			63,643			43,134
Capital expenditures(5)	$	61,772		$	211,473		$	41,250		$	29,657		$	92,741

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

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

	For the Year Ended December 31,

	2012		2011		2010			2009		2008
	(in thousands)
Reconciliation of Adjusted EBITDA to net income:
Net income	$	40,222	$	38,071	$	41,149		$	19,462	$	929
Plus:
Depreciation, depletion and amortization		41,370		36,325		34,108			36,279		36,428
Interest expense		7,767		6,062		5,338			6,222		5,501
Less:
Income tax benefit		—		—		—			—		—

EBITDA(a)	$	89,359	$	80,458	$	80,595		$	61,964	$	42,858

Plus: Rhino Eastern DD&A-51%		1,070		1,509		1,630			1,460		260
Plus: Rhino Eastern interest expense-51%		79		27		37			219		16
Less: Gain from Castle Valley acquisition(b)		—		—		(10,789	)		—		—

Adjusted EBITDA(a)	$	90,508	$	81,994	$	71,473		$	63,643	$	43,134

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	79,744	$	66,916	$	55,001		$	41,495	$	57,211
Plus:
Increase in net operating assets		—		8,889		10,260			17,190		—
Decrease in provision for doubtful accounts		—		19		—			—		—
Gain on sale of assets		4,878		3,172		—			—		—
Gain on acquisition		—		—		10,789			—		—
Gain on retirement of advance royalties		—		—		—			—		—
Amortization of deferred revenue		929		532		—			—		—
Amortization of actuarial gain		295		—		—			—		—
Interest expense		7,767		6,062		5,338			6,222		5,501
Settlement of litigation		—		—		—			1,773		—
Equity in net income of unconsolidated affiliates		5,766		3,338		4,699			893		—
Less:
Decrease in net operating assets		2,652		—		—			—		10,440
Accretion on interest-free debt		222		210		206			200		569
Amortization of advance royalties		244		1,104		865			215		471
Amortization of debt issuance costs		1,075		1,043		844			—		—
Increase in provision for doubtful accounts		—		—		—			19		—
Equity-based compensation		873		727		291			—		—
Loss on sale of assets		—		—		73			1,710		451
Loss on asset impairments		—		—		652			—		—
Loss on retirement of advance royalties		100		79		396			712		45
Income tax benefit		—		—		—			—		—
Accretion on asset retirement obligations		1,896		1,956		2,165			2,753		2,709
Equity in net loss of unconsolidated affiliate		—		—		—			—		1,587
Distributions from unconsolidated affiliate		2,958		3,351		—			—		—
Payment of abandoned public offering expenses(c)		—		—		—			—		3,582

EBITDA(a)	$	89,359	$	80,458	$	80,595		$	61,964	$	42,858

Plus: Rhino Eastern DD&A-51%		1,070		1,509		1,630			1,460		260
Plus: Rhino Eastern interest expense-51%		79		27		37			219		16
Less: Gain from Castle Valley acquisition(b)		—		—		(10,789	)		—		—

Adjusted EBITDA(a)	$	90,508	$	81,994	$	71,473		$	63,643	$	43,134

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

For ease and comparability purposes in comparing 2011 to 2010 results, the results of Rhino Resource Partners LP and Rhino Energy LLC for 2010 have been combined as if Rhino Resource Partners LP was in existence for the entirety of 2010. Since Rhino Resource Partners LP maintained the historical basis of the Rhino Predecessor's net assets, management believes that the combined Rhino Resource Partners LP and Rhino Predecessor results for 2011 are comparable with 2010. 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."

We are a diversified energy limited partnership formed in Delaware that is focused on coal, oil and natural gas and related energy infrastructure. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition to operating coal properties, we manage and lease coal properties and collect royalties from those management and leasing activities. Our diversified energy portfolio also includes investments in oil and natural gas mineral rights in the Utica Shale and Cana Woodford regions. We receive our proportionate share (5%) of revenue from any hydrocarbons produced and sold by the operator on our Utica Shale acreage and we receive royalty revenue from any hydrocarbons produced and sold by operators on our Cana Woodford acreage. In addition, we have expanded our business to include infrastructure support services, including the formation of Razorback, a service company to provide drill pad construction for operators in the Utica Shale, as well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. In December 2012, we also invested in a joint venture that will provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S.

low-vol metallurgical coal, and an estimated 17.9 million tons of non-reserve coal deposits. As of December 31, 2012, we operated nine mines, including four underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. In addition, our joint venture operates two underground mines in West Virginia. During 2010, we operated one underground mine in Colorado, but we temporarily idled this mine at the end of 2010 and the mine remained idle at the end of 2012. 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 oil and natural gas investments as of December 31, 2012 consisted of a 5% net interest in a portfolio of oil and natural gas leases in the Utica Shale that encompassed 137,000 total gross acres, or 6,850 net acres, as well as approximately 1,900 net mineral acres that we own in the Cana Woodford region.

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

For the year ended December 31, 2012, we generated revenues of approximately $352.0 million and net income of approximately $40.2 million. Excluding results from the Rhino Eastern joint venture, for the year ended December 31, 2012, we produced approximately 4.3 million tons of coal, purchased approximately 0.4 million tons of coal and sold approximately 4.7 million tons of coal, approximately 89% of which were pursuant to supply contracts. Additionally, Rhino Eastern produced and sold approximately 0.3 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2012.

We have a 51% equity interest in the Rhino Eastern joint venture, with Patriot owning the remaining membership interest. On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the Rhino Eastern joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

In May 2012, we completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for approximately $1.5 million. In addition, we could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was initially recorded in in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. As of December 31, 2012, we have paid $1.6 million of the $2.0 million. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount have not yet occurred.

The coal leases and property are estimated to contain approximately 32 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is undeveloped, but fully

permitted, and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers.

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

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

In June 2011, we completed the acquisition of 100% of the ownership interests in Elk Horn for approximately $119.7 million in cash consideration. Elk Horn is primarily a coal leasing company located in eastern Kentucky that provides us with royalty revenues. The Elk Horn acquisition was funded with borrowings available under our credit facility, which were subsequently partially repaid with proceeds from an offering of our common units.

During the year ended 2011, we completed the acquisition of certain oil and natural gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. We began to receive royalty revenues from these mineral rights in early 2012.

We and an affiliate of Wexford Capital have participated with Gulfport, a publicly traded company, to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. During the year ended December 31, 2011, we completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $19.9 million. Gulfport is actively drilling in the Utica acreage and during the third and fourth quarters of 2012, Gulfport released results from seven test wells that had been drilled on our acreage, which we believe are very positive due to the amount of hydrocarbon liquids contained in these wells. Our 2013 projected expansion capital expenditures include an estimated $15 million to $20 million for our oil and natural gas investments, primarily for drilling costs related to our Utica Shale acreage.

Our initial position in the Utica Shale consisted of a 10.8% net interest in approximately 80,000 gross acres. During the third quarter of 2012, we completed an exchange of our initial 10.8% position for a pro rata interest in 125,000 gross acres under lease by Gulfport and an affiliate of Wexford Capital. Also during the third quarter of 2012, our position was adjusted to a 5% net interest in the 125,000 gross acres, or approximately 6,250 net acres. As of December 31, 2012, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 137,000 gross acres, or approximately 6,850 net acres. In addition, per the joint operating agreement completed between us, Gulfport and an affiliate of Wexford Capital, we have funded our proportionate share of drilling costs to Gulfport for wells being drilled on our acreage. During the year ended December 31, 2012, we funded approximately $5.3 million of drilling costs that are included in Coal properties and oil and natural gas properties in our consolidated statements of financial position as of December 31, 2012. Two of the wells on our acreage began production in late 2012 and we recognized our initial revenue on our Utica Shale investment during December 2012.

In March 2012, we completed an out-lease agreement with a third party for approximately 1,232 acres we own in the Utica Shale region of Harrison County Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the lessee to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay us the sum of $6,000 per acre as a lease bonus, of which

$0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232 acres. We are working to resolve title issues on approximately 250 remaining acres to be included in the lease. In addition, the lease agreement stipulates that the third party shall pay us a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

In March 2012, we made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf Terminals LLC ("Timber Wolf"), with affiliates of Wexford Capital. Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio. The initial investment was our proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during 2012.

In addition, during the second quarter of 2012 we formed Razorback, a services company to provide drill pad construction services in the Utica Shale for drilling operators. Razorback completed the construction of three drill pads during 2012.

In December 2012, we completed the sale of the surface rights to approximately 134 acres located in Harrison County, Ohio for approximately $1.5 million. We recorded a gain of approximately $1.5 million related to this sale that is included on the (Gain) loss on sale/acquisition of assets—net line of our consolidated statements of operations and comprehensive income.

In August 2012, we sold the operations and tangible assets of our roof bolt manufacturing company, Triad, to a third party for $0.5 million of cash consideration. As part of the sale, we retained the rights to certain intellectual property and entered into an exclusive license and option to purchase agreement for this intellectual property with the same third party for potential additional cash consideration. We have not recorded any portion of this additional consideration since this amount is contingent upon the third party determining the viability of the related intellectual property to their specifications which has since expired. In connection with this sale, we recorded an approximate $0.2 million gain that is recorded on the (Gain) loss on sale/acquisition of assets—net line of our consolidated statements of operations and comprehensive income.

In December 2012, we sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.2 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, we recorded a gain of approximately $0.9 million, which was higher than the sales amount due to the extinguishment of the liabilities. This gain is included on the (Gain) loss on sale/acquisition of assets—net line of the Partnership's consolidated statements of operations and comprehensive income.

In February 2012, we sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.6 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, we recorded a gain of approximately $0.9 million, which was higher than the sales amount due to the extinguishment of the liabilities.

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

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

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

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

On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation, (2) the availability and prices of competing electricity-generation fuels, (3) the world-wide demand for steel, which utilizes metallurgical coal and can affect the demand and prices of metallurgical coal that we produce, (4) our ability to secure or acquire high-quality coal reserves and (5) 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, 2012, we had commitments under supply contracts to deliver annually scheduled base quantities of 3.9 million, 2.5 million, 1.4 million, 1.1 million and 1.1 million tons of coal to 16 customers in 2013, 7 customers in 2014, 4 customers in 2015, 2 customers

in 2016 and 2 customers in 2017, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

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 and oil and natural gas investments. Our Central Appalachia segment consists of four mining complexes: Tug River, Rob Fork and Deane, which, as of December 31, 2012, together included two underground mines, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, our Central Appalachia segment includes the Elk Horn operations. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex, the Leesville field and the Springdale field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of December 31, 2012. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2012. The Eastern Met segment includes our 51% equity interest in the results of operations of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. As of December 31, 2012, this complex was comprised of two underground mines and a preparation plant and loadout facility (owned by our joint venture partner). Our Rhino Western segment includes our two underground mines in the Western Bituminous region that consist of our McClane Canyon mine in Colorado that has been temporarily idled since the end of 2010, and remained idle at the end of 2012, and our Castle Valley mining complex in Utah that began production in January 2011. Our Other category includes our ancillary businesses that consist of our 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, as well as our oil and natural gas investments.

During 2012, we changed the method that allocates certain corporate overhead and interest charges to our reportable segments from a method based on production tons to a method based upon the amount invested in fixed assets. We changed the allocation method as a result of additional investments that we made in our non-coal operations. The reportable segment figures in the following discussion and analysis have been re-cast for 2011 and 2010 for comparability purposes.

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

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

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

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

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,

	2012			2011			2010
	(in millions)
Statement of Operations Data:
Total revenues	$	352.0		$	367.2		$	305.6
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below)		247.1			267.2			220.8
Freight and handling costs		5.8			4.3			2.6
Depreciation, depletion and amortization		41.4			36.3			34.1
Selling, general and administrative (exclusive of DD&A shown separately above)		20.5			21.8			16.4
Asset impairment loss		—			—			0.7
(Gain) on sale/acquisition of assets		(4.9	)		(3.2	)		(10.7	)

Income from operations		42.1			40.8			41.7
Interest and other income (expense):
Interest expense and other		(7.8	)		(6.1	)		(5.3	)
Interest income and other		0.1			0.1			—
Equity in net income of unconsolidated affiliates		5.8			3.3			4.7

Total interest and other income (expense)		(1.9	)		(2.7	)		(0.6	)

Net income	$	40.2		$	38.1		$	41.1

Other Financial Data
Adjusted EBITDA	$	90.5		$	82.0		$	71.5

Summary. For the year ended December 31, 2012, our total revenues decreased to $352.0 million from $367.2 million for the year ended December 31, 2011. We sold 4.7 million tons of coal for the year ended December 31, 2012, which is 0.2 million tons less, or a 4.2% decrease, than the 4.9 million tons of coal sold for the year ended December 31, 2011. This decrease in tons sold was the result of weak demand in the met and steam coal markets, which resulted in lower coal revenues for 2012 compared to 2011. We believe the weak demand in the steam coal markets was primarily driven by an unseasonably mild winter along with an over-supply of low priced natural gas, both of which resulted in an increase of coal inventory supplies at electric utilities and fewer tons of steam coal being utilized in electricity generation. We believe the weak demand in the met coal markets was primarily driven by a decrease in world-wide steel production due to economic weakness in China and Europe.

For the year ended December 31, 2012, our coal inventories increased by approximately 29,000 tons from the year ended December 31, 2011 due to weak demand in the steam and met coal markets.

Net income was $40.2 million for the year ended December 31, 2012 compared to $38.1 million for the year ended December 31, 2011. Adjusted EBITDA increased to $90.5 million for the year ended December 31, 2012, from $82.0 million for the year ended December 31, 2011. Net income and Adjusted EBITDA were positively impacted by the $7.4 million lease bonus payments received in 2012 related to our Utica Shale acreage, which had relatively immaterial costs associated with the transaction. Net income and Adjusted EBITDA were also positively impacted in 2012 due to $6.0 million of income from our Rhino Eastern joint venture compared to income of $3.3 million for 2011, each of which represents our proportionate share of income from the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager.

Tons Sold. The following table presents tons of coal sold by reportable segment for the years ended December 31, 2012 and 2011:

We sold approximately 4.7 million tons of coal in the year ended December 31, 2012 as compared to approximately 4.9 million tons sold for the year ended December 31, 2011. This decrease in tons sold was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia, partially offset by increased sales at our Castle Valley operation in Utah. Tons of coal sold in our Central Appalachia segment decreased by approximately 0.5 million, or 23.9%, to approximately 1.8 million tons for the year ended December 31, 2012 from approximately 2.3 million tons for the year ended December 31, 2011. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the met and steam coal markets. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.2 million, or 9.0%, to approximately 1.9 million tons for the year ended December 31, 2012 from approximately 2.1 million tons for the year ended December 31, 2011. The decrease in total tons sold year-to-year in Northern Appalachia was primarily due to weakness in the steam coal markets. Coal sales from our Rhino Western segment increased by approximately 0.5 million, or 105.1%, to approximately 1.0 million tons for the year ended December 31, 2012 from approximately 0.5 million tons for the year ended December 31, 2011 as this operation was still being prepared for full operation in 2011 compared to operating at a greater capacity in 2012.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2012 and 2011:

Segment	Year ended December 31, 2012		Year ended December 31, 2011		Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	161.3	$	202.9	$	(41.6	)	(20.5	)%
Freight and handling revenues		—		—		—		n/a
Other revenues		22.1		16.3		5.8		35.3	%

Total revenues	$	183.4	$	219.2	$	(35.8	)	(16.4	)%

Coal revenues per ton*	$	91.83	$	87.92	$	3.91		4.4	%
Northern Appalachia
Coal revenues	$	102.9	$	109.3	$	(6.4	)	(5.8	)%
Freight and handling revenues		6.3		5.7		0.6		10.6	%
Other revenues		12.8		5.0		7.8		158.4	%

Total revenues	$	122.0	$	120.0	$	2.0		1.7	%

Coal revenues per ton*	$	54.87	$	53.00	$	1.87		3.5	%
Rhino Western
Coal revenues	$	40.4	$	21.7	$	18.7		86.4	%
Freight and handling revenues		—		—		—		n/a
Other revenues		0.3		—		0.3		n/a

Total revenues	$	40.7	$	21.7	$	19.0		87.6	%

Coal revenues per ton*	$	38.89	$	42.78	$	(3.89	)	(9.1	)%
Other
Coal revenues		n/a		n/a		n/a		n/a
Freight and handling revenues		n/a		n/a		n/a		n/a
Other revenues	$	5.9	$	6.3	$	(0.4	)	(6.3	)%

Total revenues	$	5.9	$	6.3	$	(0.4	)	(6.3	)%

Coal revenues per ton*		n/a		n/a		n/a		n/a
Total
Coal revenues	$	304.6	$	333.9	$	(29.3	)	(8.8	)%
Freight and handling revenues		6.3		5.7		0.6		10.6	%
Other revenues		41.1		27.6		13.5		48.8	%

Total revenues	$	352.0	$	367.2	$	(15.2	)	(4.1	)%

Coal revenues per ton*	$	65.22	$	68.47	$	(3.25	)	(4.8	)%

Our total revenues for the year ended December 31, 2012 decreased by $15.2 million, or 4.1%, to $352.0 million from $367.2 million for the year ended December 31, 2011. The decrease in total revenues was due to lower coal revenues resulting primarily from weakness in the met and steam coal markets, which was partially offset by an increase in other revenues that primarily resulted from the $7.4 million lease bonus received for acreage owned in the Utica Shale region. Our other revenue also increased in 2012 due to a full year of revenue from our coal leasing business compared to only a partial year of revenue from our coal leasing operations in 2011 since we purchased this business in

June 2011. Coal revenues per ton were $65.22 for the year ended December 31, 2012, a decrease of $3.25, or 4.8%, from $68.47 per ton for the year ended December 31, 2011. This decrease in coal revenues per ton was primarily the result of a higher proportion of lower priced coal from our Rhino Western operations of our total tons of coal sold.

For our Central Appalachia segment, coal revenues decreased by $41.6 million, or 20.5%, to $161.3 million for the year ended December 31, 2012 from $202.9 million for the year ended December 31, 2011 due to weakness in the met and steam coal markets, which resulted in fewer tons sold. Coal revenues per ton for our Central Appalachia segment increased by $3.91, or 4.4%, to $91.83 per ton for the year ended December 31, 2012 as compared to $87.92 for the year ended December 31, 2011, primarily due to higher contracted prices, primarily related to metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to coal royalty revenue from our coal leasing operations.

For our Northern Appalachia segment, coal revenues were $102.9 million for the year ended December 31, 2012, a decrease of $6.4 million, or 5.8%, from $109.3 million for the year ended December 31, 2011. This decrease was due to weakness in the steam coal market, which resulted in fewer tons sold. Coal revenues per ton for our Northern Appalachia segment increased by $1.87, or 3.5%, to $54.87 per ton for the year ended December 31, 2012 as compared to $53.00 per ton for the year ended December 31, 2011. This increase was primarily due to higher contracted prices for steam coal. Other revenues increased for our Northern Appalachia segment primarily due to the $7.4 million lease bonus received for acreage owned in the Utica Shale region.

For our Rhino Western segment, coal revenues increased by $18.7 million, or 86.4%, to $40.4 million for the year ended December 31, 2012 from $21.7 million for the year ended December 31, 2011 due to an increase in tons sold for coal produced at our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $38.89 for the year ended December 31, 2012, a decrease of $3.89, or 9.1%, from $42.78 for the year ended December 31, 2011. The decrease in coal revenues per ton was due to lower market prices for coal produced at our Castle Valley mine.

Other revenues for our Other category decreased by $0.4 million for the year ended December 31, 2012 from the year ended December 31, 2011, which was primarily due to a decrease in revenue from our Triad roof bolt operations that were sold in September 2012, which was partially offset by revenue from our Razorback drill pad construction company.

Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal

and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)	Year ended December 31, 2012		Year ended December 31, 2011

Met coal tons sold		467.8		654.6	(28.5	)%
Steam coal tons sold		1,288.3		1,653.4	(22.1	)%

Total tons sold†		1,756.1		2,308.0	(23.9	)%

Met coal revenue	$	59,511	$	79,227	(24.9	)%
Steam coal revenue	$	101,762	$	123,706	(17.7	)%

Total coal revenue†	$	161,273	$	202,933	(20.5	)%

Met coal revenues per ton	$	127.21	$	121.04	5.1	%
Steam coal revenues per ton	$	78.99	$	74.82	5.6	%

Total coal revenues per ton†	$	91.83	$	87.92	4.4	%

Met coal tons produced		468.3		660.5	(29.1	)%
Steam coal tons produced		1,336.2		1,573.5	(15.1	)%

Total tons produced†		1,804.5		2,234.0	(19.2	)%

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, 2012 and 2011:

Segment	Year ended December 31, 2012		Year ended December 31, 2011		Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	125.1	$	154.2	$	(29.1	)	(18.8	)%
Freight and handling costs		0.5		—		0.5		n/a
Depreciation, depletion and amortization		26.3		22.1		4.2		18.6	%
Selling, general and administrative		19.0		20.2		(1.2	)	(6.1	)%
Cost of operations per ton*	$	71.23	$	66.79	$	4.44		6.7	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	76.0	$	75.1	$	0.9		1.2	%
Freight and handling costs		5.3		4.3		1.0		23.3	%
Depreciation, depletion and amortization		8.3		8.1		0.2		2.2	%
Selling, general and administrative		0.3		0.4		(0.1	)	(13.4	)%
Cost of operations per ton*	$	40.54	$	36.45	$	4.09		11.2	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	27.5	$	17.9	$	9.6		53.0	%
Freight and handling costs		—		—		—		n/a
Depreciation, depletion and amortization		4.7		3.1		1.6		52.2	%
Selling, general and administrative		0.1		0.1		—		2.9	%
Cost of operations per ton*	$	26.42	$	35.42	$	(9.00	)	(25.4	)%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	18.5	$	20.0	$	(1.5	)	(7.1	)%
Freight and handling costs		—		—		—		n/a
Depreciation, depletion and amortization		2.1		3.0		(0.9	)	(27.9	)%
Selling, general and administrative		1.1		1.1		—		(8.2	)%
Cost of operations per ton**		n/a		n/a		n/a		n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	247.1	$	267.2	$	(20.1	)	(7.5	)%
Freight and handling costs		5.8		4.3		1.5		34.8	%
Depreciation, depletion and amortization		41.4		36.3		5.1		13.9	%
Selling, general and administrative		20.5		21.8		(1.3	)	(6.3	)%
Cost of operations per ton*	$	52.91	$	54.79	$	(1.88	)	(3.4	)%

Cost of Operations. Total cost of operations was $247.1 million for the year ended December 31, 2012 as compared to $267.2 million for the year ended December 31, 2011. The decrease in the cost of operations was primarily due to decreased production due to weakness in the met and steam coal markets, including the idling of a majority of our Central Appalachia operations in June 2012. Our cost of operations per ton was $52.91 for the year ended December 31, 2012; a decrease of $1.88, or 3.4%, from the year ended December 31, 2011. The decrease in the cost of operations on a per ton basis was primarily due to a higher mix of lower cost tons from our Castle Valley mine.

Our cost of operations for the Central Appalachia segment decreased by $29.1 million, or 18.8%, to $125.1 million for the year ended December 31, 2012 from $154.2 million for the year ended December 31, 2011. The decrease in total cost of operations was primarily due to decreased production in response to weakness in the met and steam coal markets, including the temporary idling of a majority of our Central Appalachia operations in June 2012. Our cost of operations per ton increased to $71.23 per ton for the year ended December 31, 2012 from $66.79 per ton for year ended December 31, 2011. Cost of operations per ton increased since a portion of our costs are fixed in nature and these fixed costs were spread over a smaller number of tons sold in 2012.

In our Northern Appalachia segment, our cost of operations increased by $0.9 million, or 1.2%, to $76.0 million for the year ended December 31, 2012 from $75.1 million for the year ended December 31, 2011. Our cost of operations per ton increased to $40.54 for the year ended December 31, 2012 from $36.45 for the year ended December 31, 2011, an increase of $4.09 per ton, or 11.2%. The increases in cost of operations and cost of operations per ton were primarily due to geology issues of mining thinner coal seams at our Hopedale mine and an equipment issue that resulted in the need to replace a mining shovel at one of our Sands Hill surface mines in the second quarter of 2012.

Cost of operations in our Rhino Western segment increased by $9.6 million, or 53.0%, to $27.5 million for the year ended December 31, 2012 from $17.9 million for the year ended December 31, 2011. Our cost of operations per ton decreased to $26.42 for the year ended December 31, 2012 from $35.42 for the year ended December 31, 2011, a decrease of $9.00 per ton, or 25.4%. The increase in cost of operations was primarily due to increased production at our Castle Valley mine. Cost of operations per ton decreased primarily due to our Castle Valley mine being at full production in 2012 compared to costs incurred in 2011 associated with preparing our Castle Valley mine to begin production that had a smaller amount of tons sold.

Cost of operations in our Other category decreased by $1.5 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011. This decrease was primarily as a result of the sale of our Triad roof bolt operations in September 2012, partially offset by an increase in cost from our Razorback drill pad construction company.

Freight and Handling. Total freight and handling cost for the year ended December 31, 2012 increased by $1.5 million, or 34.8%, to $5.8 million from $4.3 million for the year ended December 31, 2011. This increase was primarily due to an increase in the tons of limestone sold for 2012 as compared to 2011, along with increased coal freight and handling costs in Central Appalachia due to a new customer contract that required coal to be transported by truck to the customer's location.

Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2012 was $41.4 million as compared to $36.3 million for the year ended December 31, 2011.

For the year ended December 31, 2012, our depreciation cost was $32.7 million as compared to $26.5 million for the year ended December 31, 2011. The increase in depreciation cost in 2012 was primarily due to an increase in machinery and equipment, including a new high-wall miner purchased in Central Appalachia.

For the year ended December 31, 2012, our depletion cost was $5.9 million as compared to $5.1 million for the year ended December 31, 2011. The increase in depletion cost in 2012 is primarily attributable to depletion expense incurred at our coal leasing operations that was not present in the entire 2011 comparable period since our coal leasing business was acquired in June 2011.

For the year ended December 31, 2012, our amortization cost was $2.8 million as compared to $4.7 million for the year ended December 31, 2011. This decrease is primarily attributable to changes in the amortization for both mine development costs and asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative. Selling, general and administrative ("SG&A") expense for the year ended December 31, 2012 was $20.5 million as compared to $21.8 million for the year ended December 31, 2011. The decrease in SG&A expense is primarily attributable to a decrease in expenditures for legal fees and other professional fees.

Interest Expense. Interest expense for the year ended December 31, 2012 was $7.8 million as compared to $6.1 million for the year ended December 31, 2011, an increase of $1.7 million, or 28.1%. This increase was the result of an increase in the balance outstanding under our credit facility.

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

(In thousands, except per ton data and %)	Year ended December 31, 2012		Year ended December 31, 2011

*Eastern Met 100% Basis*
Coal revenues	$	55,187	$	49,999	10.4	%
Total revenues	$	55,221	$	50,073	10.3	%
Coal revenues per ton*	$	185.98	$	198.97	(6.5	)%
Cost of operations	$	36,710	$	37,582	(2.3	)%
Cost of operations per ton*	$	123.71	$	149.55	(17.3	)%
Depreciation, depletion and amortization	$	2,098	$	2,959	(29.1	)%
Interest expense	$	155	$	52	200.5	%
Net income (loss)	$	11,954	$	6,545	82.6	%
Partnership's portion of net income (loss)	$	6,023	$	3,338	80.4	%
Tons produced		337.1		266.2	26.6	%
Tons sold		296.7		251.3	18.1	%

Rhino Eastern's Eagle #2 mine began production in the third quarter of 2011, which was replaced by Rhino Eastern's Eagle #3 mine that began production in the third quarter of 2012 due to adverse conditions in the coal seams at the Eagle #2 mine. The year-to-date operation of the Eagle #2 mine resulted in an increase in tons produced and sold for 2012 compared to 2011. The increase in tons sold resulted in increased revenue and net income for 2012 compared to 2011.

Net Income (Loss). The following table presents net income (loss) by reportable segment for the years ended December 31, 2012 and 2011:

For the year ended December 31, 2012, total net income was $40.2 million compared to $38.1 million for the year ended December 31, 2011. Net income was positively impacted by $7.4 million received as a lease bonus payment in 2012 related to acreage we own in the Utica Shale region of eastern Ohio, which had relatively immaterial costs associated with the transaction. For our Central Appalachia segment, net income decreased to $4.3 million for the year ended December 31, 2012, a decrease of $12.6 million, as compared to the year ended December 31, 2011. This decrease was primarily due to weakness in the steam and met coal markets that resulted in fewer tons sold. Net income in our Northern Appalachia segment increased by $2.2 million to $29.6 million for the year ended December 31, 2012, from $27.4 million for the year ended December 31, 2011. This increase was primarily the result of the $7.4 million lease bonus payment partially offset by a decrease in tons of coal sold due to weakness in the steam coal markets. Net income in our Rhino Western segment increased by $8.3 million to income of $5.7 million for the year ended December 31, 2012, compared to a loss of $2.6 million for the year ended December 31, 2011. This increase was primarily the result of more tons sold from the Castle Valley mine. Our Eastern Met segment recorded net income of $6.0 million for the year ended December 31, 2012, an increase of $2.7 million from $3.3 million recorded for the year ended December 31, 2011. For the Other category, we had a net loss of $5.4 million for the year ended December 31, 2012, a benefit of $1.5 million as compared to a net loss of $6.9 million for the year ended December 31, 2011.

Adjusted EBITDA. The following table presents Adjusted EBITDA by reportable segment for the years ended December 31, 2012 and 2011:

Total Adjusted EBITDA for the year ended December 31, 2012 was $90.5 million, an increase of $8.5 million from $82.0 million for the year ended December 31, 2011, primarily due to an increase in net income, along with higher DD&A and interest expense. Please read "—Reconciliation of Adjusted EBITDA to Net Income by Segment" for reconciliations of Adjusted EBITDA to net income on a segment basis.

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

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

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

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

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

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

Segment	Year ended December 31, 2011		Year ended December 31, 2010		Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	202.9	$	194.9	$	8.0		4.1	%
Freight and handling revenues		—		—		—		n/a
Other revenues		16.3		0.7		15.6		2127.9	%

Total revenues	$	219.2	$	195.6	$	23.6		12.1	%

Coal revenues per ton*	$	87.92	$	90.30	$	(2.38	)	(2.6	)%
Northern Appalachia
Coal revenues	$	109.3	$	86.2	$	23.1		26.8	%
Freight and handling revenues		5.7		4.2		1.5		37.8	%
Other revenues		5.0		5.0		—		(2.0	)%

Total revenues	$	120.0	$	95.4	$	24.6		25.7	%

Coal revenues per ton*	$	53.00	$	44.30	$	8.70		19.6	%
Rhino Western
Coal revenues	$	21.7	$	8.8	$	12.9		145.5	%
Freight and handling revenues		—		—		—		n/a
Other revenues		—		—		—		22.2	%

Total revenues	$	21.7	$	8.8	$	12.9		145.4	%

Coal revenues per ton*	$	42.78	$	43.67	$	(0.89	)	(2.0	)%
Other
Coal revenues		n/a		n/a		n/a		n/a
Freight and handling revenues		n/a		n/a		n/a		n/a
Other revenues	$	6.3	$	5.8	$	0.5		8.6	%

Total revenues	$	6.3	$	5.8	$	0.5		8.6	%

Coal revenues per ton*		n/a		n/a		n/a		n/a
Total
Coal revenues	$	333.9	$	289.9	$	44.0		15.2	%
Freight and handling revenues		5.7		4.2		1.5		37.8	%
Other revenues		27.6		11.5		16.1		138.1	%

Total revenues	$	367.2	$	305.6	$	61.6		20.1	%

Coal revenues per ton*	$	68.47	$	67.32	$	1.15		1.7	%

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

revenues per ton was primarily the result of higher contracted and spot prices for steam coal, partially offset by a lower mix of tons sold of metallurgical coal in 2011.

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

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

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

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

Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal

and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.

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

Met coal tons sold		654.6		683.4	(4.2	)%
Steam coal tons sold		1,653.4		1,474.5	12.1	%

Total tons sold†		2,308.0		2,157.9	7.0	%

Met coal revenue	$	79,227	$	88,570	(10.5	)%
Steam coal revenue	$	123,706	$	106,281	16.4	%

Total coal revenue†	$	202,933	$	194,851	4.1	%

Met coal revenues per ton	$	121.04	$	129.59	(6.6	)%
Steam coal revenues per ton	$	74.82	$	72.08	3.8	%

Total coal revenues per ton†	$	87.92	$	90.30	(2.6	)%

Met coal tons produced		660.5		700.2	(5.7	)%
Steam coal tons produced		1,573.5		1,454.3	8.2	%

Total tons produced†		2,234.0		2,154.5	3.7	%

Segment	Year ended December 31, 2011		Year ended December 31, 2010			Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	154.2	$	133.5		$	20.7		15.5	%
Freight and handling costs		—		—			—		n/a
Depreciation, depletion and amortization		22.1		20.1			2.0		10.1	%
Selling, general and administrative		20.2		15.3			4.9		32.0	%
Cost of operations per ton*	$	66.79	$	61.87		$	4.92		7.9	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	75.1	$	65.1		$	10.0		15.5	%
Freight and handling costs		4.3		3.1			1.2		39.1	%
Depreciation, depletion and amortization		8.1		9.3			(1.2	)	(12.7	)%
Selling, general and administrative		0.4		0.3			0.1		2.5	%
Cost of operations per ton*	$	36.45	$	33.43		$	3.02		9.0	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	17.9	$	6.9		$	11.0		159.5	%
Freight and handling costs		—		—			—		n/a
Depreciation, depletion and amortization		3.1		0.6			2.5		414.6	%
Selling, general and administrative		0.1		0.1			—		17.2	%
Cost of operations per ton*	$	35.42	$	34.20		$	1.22		3.6	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	20.0	$	15.3		$	4.7		30.7	%
Freight and handling costs		—		(0.5	)		0.5		n/a
Depreciation, depletion and amortization		3.0		4.1			(1.1	)	(26.7	)%
Selling, general and administrative		1.1		0.7			0.4		64.2	%
Cost of operations per ton**		n/a		n/a			n/a		n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	267.2	$	220.8		$	46.4		21.0	%
Freight and handling costs		4.3		2.6			1.7		64.3	%
Depreciation, depletion and amortization		36.3		34.1			2.2		6.5	%
Selling, general and administrative		21.8		16.4			5.4		32.6	%
Cost of operations per ton*	$	54.79	$	51.27		$	3.52		6.9	%

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

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

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

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

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

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

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

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

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

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

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

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

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

*Eastern Met 100% Basis*
Coal revenues	$	49,999	$	40,028	24.9	%
Total revenues	$	50,073	$	40,094	24.9	%
Coal revenues per ton*	$	198.97	$	158.74	25.3	%
Cost of operations	$	37,582	$	25,153	49.4	%
Cost of operations per ton*	$	149.55	$	99.75	49.9	%
Depreciation, depletion and amortization	$	2,959	$	3,196	(7.4	)%
Interest expense	$	52	$	72	(28.1	)%
Net income (loss)	$	6,545	$	8,946	(26.8	)%
Partnership's portion of net income (loss)	$	3,338	$	4,699	(26.8	)%
Tons produced		266.2		258.6	3.0	%
Tons sold		251.3		252.2	(0.3	)%

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

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

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

For the year ended December 31, 2011, total net income was $38.1 million compared to $41.1 million (or $30.3 million excluding the $10.8 million gain from the Castle Valley acquisition) for the year ended December 31, 2010. Excluding the Castle Valley gain from 2010 net income, net income increased in 2011 due to an increase in revenue from higher tons sold, partially offset by higher cost of operations, primarily in our Central Appalachia segment. For our Central Appalachia segment, net income decreased to $16.9 million for the year ended December 31, 2011, a decrease of $2.3 million, as compared to the year ended December 31, 2010. This decrease was primarily due to lower amounts of metallurgical coal sold and an increase in costs of operations, partially offset by coal royalty income generated from our Elk Horn operation. Net income in our Northern Appalachia segment increased by $14.1 million to $27.4 million for the year ended December 31, 2011, from $13.3 million for the year ended December 31, 2010. This increase was primarily the result of an increase in sales. Net income in our Rhino Western segment decreased by $13.5 million to a loss of $2.6 million for the year ended

December 31, 2011, compared to income of $10.9 million for the year ended December 31, 2010. This decrease was primarily the result of the $10.8 million Castle Valley gain in 2010 along with an increase in costs associated with preparing our Castle Valley operation to begin production in early 2011. Our Eastern Met segment recorded net income of $3.3 million for the year ended December 31, 2011, a decrease of $1.4 million from $4.7 million recorded for the year ended December 31, 2010. For the Other category, we had a net loss of $6.9 million for the year ended December 31, 2011, a reduction of $0.1 million as compared to a net loss of $7.0 million for the year ended December 31, 2010. This decrease in the loss from year to year was primarily due to an asset impairment charge recorded for certain assets in two of our ancillary businesses in 2010, partially offset by an increase in costs of operations in 2011.

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

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

The following tables present reconciliations of Adjusted EBITDA to net income on a segment basis for each of the periods indicated. We believe the presentation of Adjusted EBITDA that includes the proportionate share of DD&A and interest expense for our Rhino Eastern joint venture is appropriate since our portion of Rhino Eastern's net income that is recognized as a single line item in our financial statements is affected by these expense items. Since we do not reflect these proportionate expense items of DD&A and interest expense in our consolidated financial statements, we believe that the adjustment for these expense items in the Adjusted EBITDA calculation is more representative of

how we review our results and also provides investors with additional information that they can use to evaluate our results. Adjusted EBITDA also excludes the effect of certain non-recurring items.

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, service our debt and make distributions to our unitholders. 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, 2012, our available liquidity was $72.6 million, including cash on hand of $0.5 million and $72.1 million of available borrowing capacity under our credit agreement. The amount available under our credit agreement is based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement).

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

Net cash provided by operating activities was $79.7 million for the year ended December 31, 2012 as compared to $66.9 million for the year ended December 31, 2011. This increase in cash provided by operating activities was the result of an increase in net income, primarily due to the $7.4 million of income from the lease bonus payments received on our Utica acreage lease, as well as favorable changes in our working capital accounts year to year.

Net cash used in investing activities was $58.4 million for the year ended December 31, 2012 as compared to $188.0 million for the year ended December 31, 2011. The decrease in cash used in investing activities was primarily due to the acquisition of Elk Horn in 2011 for approximately $119.6 million, net of cash acquired, along with decreased amounts expended for additions to property, plant and equipment in 2012 compared to 2011, primarily due to approximately $28.0 million expended for oil and natural gas mineral rights acquisitions in the Cana Woodford region and the Utica Shale region in 2011.

Net cash used in financing activities for the year ended December 31, 2012 was $21.3 million, which was primarily attributable to distributions paid to our unitholders, partially offset by net borrowings under our credit agreement that were primarily used to fund a portion of our capital expenditures. Net cash provided by financing activities for the year ended December 31, 2011 was $121.5 million, which was primarily attributable to net borrowings under our credit agreement to fund the Elk Horn acquisition that was also partially funded with the net proceeds of approximately $66.9 million from the public offering of common units in July 2011.

Net cash provided by operating activities was $66.9 million for the year ended December 31, 2011 as compared to $55.0 million for the year ended December 31, 2010. This increase in cash provided by operating activities was primarily the result of an increase in net income, excluding the non-cash gain from the Castle Valley acquisition, due to favorable sales prices of our steam coal.

Net cash used in investing activities was $188.0 million for the year ended December 31, 2011 as compared to $37.6 million for the year ended December 31, 2010. The increase in cash used in investing activities was primarily due to the acquisition of Elk Horn for approximately $119.6 million, net of cash acquired, along with increased amounts expended for the purchase of mining equipment and other asset acquisitions, including approximately $28.0 million for oil and natural gas mineral rights acquisitions in the Cana Woodford region and the Utica Shale region.

Net cash provided by financing activities for the year ended December 31, 2011 was $121.5 million, which was primarily attributable to net borrowings under our credit agreement to fund the Elk Horn acquisition that was also partially funded with the net proceeds of approximately $66.9 million from the public offering of common units in July 2011. Net cash used for 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.

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. For example, 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, acquisition of 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, 2012 were approximately $17.5 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the year ended December 31, 2012 were approximately $44.3 million, which were primarily related to the completion of our new preparation plant in our Tug River mining complex along with additional investment in our Utica Shale property and the acquisition of land in western Kentucky for the development of our Pennyrile Energy mine. The remaining amount of expansion capital expenditures was primarily spent on our internal development projects. For the year ending December 31, 2013, we have budgeted $10 million to $15 million for maintenance capital expenditures and $31 million to $39 million for expansion capital expenditures. Our 2013 projected expansion capital expenditures consist of an estimated $15 million to $20 million for our oil and natural gas investments, primarily drilling costs related to our Utica Shale acreage, and approximately $17 million for the development of our new Pennyrile Energy mine in western Kentucky.

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 for the next twelve months. 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 and our ability to pay

distributions to our unitholders. We have not paid distributions on our subordinated units with respect to the quarters ended June 30, 2012, September 30, 2012 or December 31, 2012. From time to time, we may issue debt and equity securities.

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

On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of participating lenders. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit.

Loans under the credit agreement bear interest at either (i) a base rate equaling the highest of (a) the Federal Funds Open Rate plus 0.50%; (b) the prime rate; or (c) daily LIBOR plus 1.00%, plus an applicable margin in each case or (ii) LIBOR plus an applicable margin, at our option. The applicable margin for the base rate option is 1.50% to 2.25%, and the applicable margin for the LIBOR option is 2.50% to 3.25%, each of which depends on our and our subsidiaries' consolidated leverage ratio ("Consolidated Leverage Ratio"). The credit agreement also contains letter of credit fees equal to an applicable margin of 2.50% to 3.25% depending on the Consolidated Leverage Ratio, multiplied by the aggregate amount available to be drawn on the letters of credit, and a 0.15% fronting fee payable to the administrative agent. In addition, we incur a commitment fee on the unused portion of the credit agreement at a rate of 0.375% to 0.50% per annum, depending on the Consolidated Leverage Ratio. Borrowings on the line of credit are collateralized by all of our unsecured assets.

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 units. As of and for the year ended December 31, 2012, we are in compliance with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.

At December 31, 2012, we had borrowed $156.0 million at a variable interest rate of LIBOR plus 2.75% (2.97% at December 31, 2012) and an additional $1.3 million at a variable interest rate of the prime rate plus 1.75% (5.00% at December 31, 2012). In addition, we had outstanding letters of credit of approximately $23.2 million at a fixed interest rate of 2.75% at December 31, 2012. Based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), we had not used $72.1 million of the borrowing availability at December 31, 2012. During the three month period ended December 31, 2012, we had average borrowings outstanding of approximately $160.5 million under our credit agreement.

In the normal course of business, we are a party to off-balance sheet arrangements that 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, 2012, we had $23.2 million in letters of credit outstanding, of which $18.2 million served as collateral for approximately $71.0 million in our surety bonds outstanding that secure the performance of our reclamation obligations.

The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2012:

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 12 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.

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 our ability 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.

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 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. Any losses from our equity method investment are absorbed by us based upon our proportionate ownership percentage. If losses are incurred that exceed our investment in the equity method entity, then we must continue to record our proportionate share of losses in excess of our investment. 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 Rhino Eastern 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 ("Eastern Met") and have provided supplemental detail related to this operation in Note 20 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, 2012, 2011 and 2010, we performed a qualitative and quantitative analysis based on the controlling economic interests of the Rhino Eastern joint venture. This included an analysis of the expected economic contributions 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, 2012 and 2011, we have recorded our equity method investment of $21.8 million and $18.7 million, respectively, as a long-term asset. We had not provided any additional contractually required support as of December 31, 2012; however, as disclosed in Note 18 to the audited consolidated financial statements that are included elsewhere in this report, we provided loans to the Rhino Eastern joint venture during 2012 and 2011 that totaled approximately $11.9 million and approximately $5.8 million, respectively, which were fully repaid as of December 31, 2012 and 2011, respectively.

We do not require collateral or other security on accounts receivable. Credit risk is controlled through credit approvals and monitoring procedures. Please read Note 16 to the audited consolidated financial statements included elsewhere in this report for a discussion of major customers.

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.

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.

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 were disposed of by sale. Please read Note 6 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, 2012 and 2011.

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 and oil and natural gas 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 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, 2012 were calculated with discount rates that ranged from 3.2% to 5.3% depending upon the timing of the cash flows of the specific obligations. Changes in the asset retirement obligations for the year ended December 31, 2011 were calculated with discount rates that ranged from 4.2% to 7.0% depending upon the timing of the cash flows of the specific obligations. The discount rates 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, 2010 were calculated with a discount rate of 7.5%. 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 2.3% for 2012, 2.5% for 2011 and 3.0% for 2010.

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.

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 coal royalty revenues, limestone sales, coal handling and processing, rebates and rental income. Coal royalty revenues are recognized on the basis of tons of coal sold by our lessees and the corresponding gross revenues from those sales. The leases are based on (1) minimum monthly or annual payments, (2) a minimum dollar royalty per ton and/or a percentage of the gross sales price, or (3) a combination of both. Coal royalty revenues are recorded from royalty reports submitted by the lessee, which are reconciled and subject to audit by us. Most of our lessees are required to make minimum monthly or annual royalty payments that are recoupable over certain time periods, generally two years. If tonnage royalty revenues do not meet the required minimum amount, the difference is paid as a deficiency. These deficiency payments received are recognized as an unearned revenue liability because they are generally recoupable over certain time periods. When a lessee recoups a deficiency payment through production, the recouped amount is deducted from the unearned revenue liability and added to revenue attributable to the coal royalty revenue in the current period. If a lessee does not recoup a deficiency paid during the allocated time period, the recoupment right lost becomes revenue in the current period and is deducted from the liability.

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.

We 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 the terms of the contracts and management's intent and ability to take physical delivery of the diesel fuel.

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

In June 2011, the FASB published ASU No. 2011-05, "Comprehensive Income (Topic 220): Presentation of Comprehensive Income". Under the amendments in this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income

along with a total for other comprehensive income, and a total amount for comprehensive income. For public entities, the amendments of this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

Subsequently, in December 2011, the FASB issued ASU No. 2011-12, "Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05". In order to defer only those changes in Update 2011-05 that relate to the presentation of reclassification adjustments, the paragraphs in this ASU supersede certain pending paragraphs in ASU 2011-05. The amendments are being made to allow the FASB time to re-deliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, entities should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by this ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Public entities should apply these requirements for fiscal years, and interim periods within those years, beginning after December 15, 2011. We have consistently presented comprehensive income in a single continuous statement with net income, so the provisions of ASU 2011-05 and the related deferral included in ASU 2011-12 did not have a material effect on us.

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 price risk and interest rate risk.

We manage our commodity price risk for coal sales through the use of supply contracts. As of December 31, 2012, we had commitments under supply contracts to deliver annually scheduled base quantities of 3.9 million, 2.5 million, 1.4 million, 1.1 million and 1.1 million tons of coal to 16 customers in 2013, 7 customers in 2014, 4 customers in 2015, 2 customers in 2016 and 2 customers in 2017, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

In addition, we manage the commodity price exposure associated with the diesel fuel and explosives used in our mining operations through the use of forward contracts with our suppliers. We are also subject to price volatility for steel products used for roof support in our underground mines, which is managed through negotiations with our suppliers since there is not an active forward contract market for steel products.

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, 2012. A hypothetical increase of 10% in steel prices would have reduced net income by $1.2 million for the year ended December 31, 2012. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.6 million for the year ended December 31, 2012.

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $1.5 million for the year ended December 31, 2012.

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-42 of this report and are incorporated herein by reference.

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

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, 2012 at the reasonable assurance level. 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.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed under the supervision of our CEO and CFO, and effected by our general partner's board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including the CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Deloitte & Touche LLP, the independent registered public accounting firm that audited the financial statements included in this annual report, as stated in their attestation report appearing on page 109.

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.

To the Board of Directors of
The Managing General Partner
And the Partners of
Rhino Resource Partners LP
Lexington, Kentucky

We have audited the internal control over financial reporting of Rhino Resource Partners LP and subsidiaries (the "Partnership") as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Partnership and our report dated March 8, 2013 expressed an unqualified opinion on those financial statements.

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.

The following table shows information for the executive officers and directors of our general partner as of December 31, 2012:

Name		Position With Our General Partner

Mark D. Zand*	59	Chairman of the Board of Directors
David G. Zatezalo	57	President, Chief Executive Officer and Director
Richard A. Boone	58	Senior Vice President and Chief Financial Officer
Christopher I. Walton	54	Senior Vice President and Chief Operating Officer
Andrew W. Cox	56	Vice President of Sales
Reford C. Hunt	39	Vice President of Technical Services
Whitney C. Kegley	37	Vice President, Secretary and General Counsel
Jay L. Maymudes*	51	Director
Arthur H. Amron*	56	Director
Kenneth A. Rubin*	58	Director
Joseph M. Jacobs*	59	Director
Mark L. Plaumann**	57	Director
Douglas Lambert**	55	Director
James F. Tompkins**	64	Director

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 Vice Chairman of the Kentucky Coal Association. In total, Mr. Zatezalo has approximately 39 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 32 years of experience in the coal industry.

Christopher I. Walton. Mr. Walton has served as Senior Vice President and Chief Operating Officer of our general partner since April 2012, prior to which he served as the General Manager of our Sands Hill Mining LLC and Clinton Stone LLC operations in Hamden, Ohio beginning in December 2009. From December 2007 to December 2009, Mr. Walton served as Engineer/Operations Manager of the Partnership's Sands Hill LLC operation. In total, Mr. Walton has approximately 32 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 Energies Inc., Mingo Logan Coal Company, Old Ben Coal Company and NERCO Coal Sales LLC. In total, Mr. Cox has approximately 34 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 16 years of experience in the coal industry.

Whitney C. Kegley. Ms. Kegley has served as our general partner's Vice President, Secretary and General Counsel since July 2012. Prior to joining our general partner, and beginning in April 2012, Ms. Kegley served as a partner with the law firm of Dinsmore & Shohl, LLP in their Lexington, KY office. Ms. Kegley concentrated her practice on mergers and acquisitions and general corporate law with an emphasis on mineral and energy law. From March 2009 to April 2012, Ms. Kegley was a member in the Lexington, KY office of McBrayer, McGinnis, Leslie & Kirkland, PLLC, where she concentrated on mergers and acquisitions and general corporate law with an emphasis on mineral and energy law. From August 1999 to March 2009, Ms. Kegley was employed by the law firm of Frost Brown Todd LLC where she held various positions.

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 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. 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 Diamondback Energy, Inc., as well as 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

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

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. Because we are a limited partnership, we are exempt under the rules of the NYSE from the requirement to have a majority of independent directors, as well as a compensation and nominating or corporate governance committee. 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 as of February 28, 2013, beneficially owns an aggregate 53% 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.

The board of directors of our general partner held quarterly meetings during the year ended December 31, 2012. All of the directors attended each 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.

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.

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. Because we are exempt under the rules of the NYSE from the requirement to have a compensation committee, our compensation committee is not required to consist of independent directors.

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 has held 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.

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." We intend to disclose any amendments to, or waivers from, our Code of Business Conduct and Ethics that apply to our principal executive officer, principal financial officer, and principal accounting officer or controller on our website promptly following the date of any such amendment or waiver.

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, 2012, except as described in the following, 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, except as disclosed below.

The Form 4 reports relating to a distribution on February 29, 2012 of our common and subordinated units by Rhino Energy Holdings LLC to Messrs. Amron, Zand, Maymudes and Rubin, each of whom is a Wexford-affiliated director of our general partner, as well as Charles Davidson, Joe Jacobs, Wexford GP LLC and Wexford Capital, as 10% beneficial owners of our common units (and with respect to Mr. Jacobs, a Wexford-affiliated director of our general partner), were filed after the applicable due date.

The Form 4 reports relating to the vesting of phantom unit award grants to Messrs. Zatezalo, Boone, Cox, Hunt, Walton, as well as Joseph R. Miller on April 5, 2012, were filed after the applicable due date.

The Form 4 report filed for the 2012 annual grant of restricted units to Douglas Lambert, a non-employee director of our general partner, was filed after the applicable due date. In addition, the Form 4 report filed for Mark Plaumann, a non-employee director of our general partner, for an in-kind distribution of our common and subordinated units to Mr. Plaumann from an investment fund affiliated with Wexford was filed after the applicable due date.

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. The compensation committee of the board of directors of our general partner determines the 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 reimbursed by us on a dollar-for-dollar basis.

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."

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:

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.

Our general partner's 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 that we require. In the future, the compensation committee may 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. We anticipate that our general partner's compensation committee may consider relevant surveys in determining appropriate pay levels in the future. We expect that our general partner's 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. During 2012, the compensation committee modified the compensation for certain of our named executive officers, as described under "—Elements of Compensation—Employment Agreements" below.

We believe that a material amount of executive compensation should be tied to our performance, and that 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.

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, we made long-term equity-based awards to each of our named executive officers in

connection with the completion of the IPO and intend to grant additional awards of phantom units from time to time, as determined in the discretion of the compensation committee. In the first quarter of 2012 and during the first quarter of 2013, we granted additional phantom unit awards to Messrs. Boone, Walton, Cox and Hunt to provide long-term incentives to further align the interests of these 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. The compensation committee elected not to grant any phantom unit awards to Mr. Zatezalo during the first quarter of 2012 or during the first quarter of 2013.

Our general partner's compensation committee determines the mix of compensation, comprised of both among short-term and long-term compensation and cash and non-cash compensation, included in the compensation packages 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.

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 terminated earlier 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."

Effective December 10, 2012, we entered into an amendment of the amended and restated employment agreement, effective January 1, 2010, with Mr. Zatezalo. The amendment extended the term of Mr. Zatezalo's amended and restated employment agreement to December 31, 2013 and increased his base salary from $520,000 to $540,000 for fiscal year 2013. Mr. Zatezalo also became entitled to receive a signing bonus of $45,000 upon the execution of the Amendment. The amendment did not alter any other terms of the amended and restated employment agreement. Mr. Zatezalo is entitled to participate in the employee benefit arrangements offered to similarly situated employees and is eligible to receive grants pursuant to the LTIP as determined in our general partner's discretion.

In April 2012, we entered into an amended and restated employment agreement with Mr. Walton which included his appointment to the newly recreated position of Senior Vice President and Chief Operating Officer. The new agreement with Mr. Walton extends his employment term to April 30, 2015 and increases his annual base salary rate to $300,000 per year, but otherwise does not alter 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 named executive officers' base salaries are 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 for each individual officer was established through negotiations with the individual. In accordance with their employment agreements, Mr. Zatezalo's base salary increased to $520,000 effective for fiscal year 2012 and to $540,000 for fiscal year 2013, Mr. Boone's base salary increased to $295,000 effective May 31, 2012 and Mr. Hunt's base salary increased to $235,000 effective September 8, 2012. In addition, the compensation committee increased the base salary of Mr. Walton for fiscal year 2012 as described above. Mr. Cox's base salary did not change during 2012.

Bonus Awards. We generally provide discretionary annual bonuses to each of our named executive officers. 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 our 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 2012 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 2012 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.

Consistent with our historical practice, we have retained a maximum bonus threshold of 40% for most of our named executive officers. Our employment agreements with each of the named executive officers provide that 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 and up to 75% of annual base salary in the case of Mr. Boone). 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.

The following table sets forth the annual rate of base salary payable for fiscal 2012 and potential bonus amounts for the named executive officers pursuant to their employment agreements:

Severance and Change in Control Benefits. The employment agreements with the named executive officers 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."

The board of directors of our general partner has 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. Walton (1,220 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 at the time of the award; (ii) Mr. Boone's award was targeted at approximately two times his base salary at the time of the award; and (iii) awards to Messrs. Walton, Cox and Hunt were not tied to their salary levels, but were consistent with the awards granted to other officers in connection with the offering. These multiples of base salary were established at the discretion of our President and Chief Executive Officer and Wexford Capital and through 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 scheduled to vest within the 12-month period following termination will be accelerated to the termination date. Distributions of dividend equivalent rights, or DERs, credited with respect to unvested phantom units are paid upon vesting of the associated phantom units (and are forfeited at the same time the associated phantom units are forfeited).

In the first quarters of 2012 and 2013, the compensation committee approved discretionary grants of phantom unit awards under the LTIP to certain named executive officers. These discretionary awards of phantom units were based upon a maximum value of one-half of the executive's annual pre-tax cash bonus award and the phantom units vest in equal one-third installments over a 36-month period from the respective grant date. These discretionary annual awards provide a long-term incentive to our executives to further align the interests of the named executive officers with those of our unitholders.

With respect to future equity compensation awards, we intend to continue 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.

Rhino Energy LLC and certain of its subsidiaries are participating employers in the Rhino Energy LLC 401(k) Plan (the "Rhino 401(k) Plan") and Rhino Energy LLC's subsidiary Hopedale Mining LLC sponsors its own plan (the "Hopedale 401(k) Plan" and, collectively with the Rhino 401(k) Plan, 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, to make voluntary pre-tax contributions to the applicable plan, subject to applicable tax limitations. The companies make safe harbor matching contributions to the 401(k) Plans for those eligible employees who meet certain conditions and subject to certain limitations under federal law. Under the Rhino 401(k) Plan, eligible employees receive matching contributions equal to 100% of their pre-tax contributions not exceeding 3% of their eligible compensation, plus 50% of their pre-tax contributions in excess of 3% but not in excess of 5% of their eligible compensation. Under the Hopedale 401(k) Plan, eligible employees receive matching contributions equal to 100% of their pre-tax contributions, but not as to pre-tax contributions exceeding 6% of their eligible compensation. In addition, discretionary employer non-elective contributions may be made under the 401(k) Plans. Employee and employer contributions are subject to annual dollar limitations, which are periodically adjusted for changes in the cost of living. 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 such contributions, are not taxable to employees until withdrawn from the plan, and so that contributions, if any, will be deductible when made.

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 2012, the only perquisite provided to the named executive officers was the use of a company owned automobile.

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).

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, 2012.

The following table sets forth the cash and other compensation earned by each of our named executive officers for the years ended December 31, 2012, 2011 and 2010.

Name and Principal Position		Salary ($)		Bonus ($)(1)		Unit Awards ($)(2)		All Other Compensation ($)(3)		Total ($)

David G. Zatezalo	2012	$	519,615	$	377,500	$	—	$	15,277	$	912,392
President and Chief	2011		499,616		357,200		—		21,264		878,080
Executive Officer	2010		480,000		602,100		1,500,006		22,364		2,604,470
Richard A. Boone	2012		286,308		117,100		55,998		12,356		471,762
Senior Vice President and	2011		264,231		116,300		—		12,639		393,170
Chief Financial Officer	2010		242,495		215,600		499,995		10,919		969,009
Christopher I. Walton	2012		255,578		63,500		21,994		11,942		353,014
Senior Vice President and	2011		133,750		44,000		—		9,911		187,661
Chief Operating Officer	2010		120,000		61,800		25,010		9,142		215,952
Andrew W. Cox	2012		219,999		46,600		23,999		10,919		301,517
Vice President of Sales	2011		219,614		53,100		—		9,172		281,886
	2010		209,999		55,100		25,010		11,048		301,157
Reford C. Hunt	2012		228,076		51,600		26,003		13,119		318,798
Vice President of Technical	2011		190,769		55,800		—		12,147		258,716
Services	2010		175,001		160,900		25,010		12,895		373,806

(1): For 2012 and 2011, the bonus amount reflects the annual cash bonus awarded to each named executive per the terms of their employment agreements.

For 2010, bonus amounts include the one-time cash bonuses received by certain of our named executive officers in connection with the consummation of our IPO in the following amounts: (a) Mr. Zatezalo—$250,000; (b) Mr. Boone—$150,000; (c) Mr. Walton—$25,000; and (d) Mr. Hunt—$100,000. Also includes the annual discretionary bonuses earned by the named executive officers for fiscal 2010.
(2): The amounts reported in the "Unit Awards" column reflect the aggregate grant date fair value of phantom unit awards granted under the LTIP, computed in accordance with FASB ASC Topic 718. See Note 2 to our consolidated financial statements for additional detail regarding assumptions underlying the value of these equity awards.
(3): Amounts reflect, as applicable with respect to the named executive officers and as provided in the supplemental table below, the use of a company provided automobile and employer contributions to the Rhino 401(k) Plan and the Hopedale 401(k) Plan. The value of automobile use is calculated as the monthly lease payment paid by us on behalf of the executive multiplied by the monthly percentage of personal use of the automobile by the executive.

Certain named executive officers received discretionary annual awards of phantom units that were granted on March 1, 2012. The dollar amounts of the awards granted were calculated based upon a percentage of the annual pre-tax cash bonus awards the employees received in connection with their fiscal year 2011 performance. The following table sets forth information concerning equity awards for the named executive officers that were granted during the year ended December 31, 2012.

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

During 2012, we had employment agreements in effect with each of the named executive officers. The employment agreements with Messrs. Zatezalo, Boone, Walton, Cox and Hunt set forth the annual base salary payable to each named executive officer. During 2012, Messrs. Zatezalo's, Boone's and Hunt's employment agreements provided for automatic base salary increases and the agreement with Mr. Walton provides for an automatic annual salary increase during the term of his agreement. Mr. Cox's employment agreement may be reviewed each year for a possible salary increase. The foregoing named executive officers were each entitled in 2012 under their respective employment agreements to receive an annual discretionary bonus of up to 40% of their annual base salary (150% of base salary in the case of Mr. Zatezalo and 75% of base salary in the case of Mr. Boone). 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, Boone, Walton, Cox and Hunt with automobiles suitable for their duties and responsibilities to us.

We entered into an amended and restated employment agreement with Mr. Zatezalo, effective January 1, 2010. We have also entered into amended and restated employment agreements with Mr. Cox, effective January 14, 2011, Mr. Boone, effective May 31, 2011, and Mr. Hunt, effective September 13, 2011. As described previously, we entered into an amendment of the amended and restated employment agreement with Mr. Zatezalo, effective December 10, 2012, and we also entered into an amended and restated employment agreement with Mr. Walton, effective April 2, 2012, which included his appointment to the position of Senior Vice President and Chief Operating Officer. The amended and restated employment agreements are substantially similar to the agreements previously in effect, except as previously described in the section of our Compensation Discussion and Analysis titled "—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."

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 will be 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 credits that will be paid in cash upon vesting of the associated phantom units (and will be forfeited at the same time the associated phantom units are forfeited).

Certain named executives received discretionary awards of phantom units in 2012 in respect of fiscal 2011 performance. These phantom unit awards vest in equal annual installments over a 36-month period (i.e., approximately 33.3% vest at each annual anniversary of the date of grant, so that the phantom units will be 100% vested in early 2015), provided the named executive officer remains an employee continuously from the date of grant through the applicable vesting date. The remaining characteristics of these phantom awards are similar to the phantom units awarded in connection with our IPO.

The following table sets forth information concerning outstanding equity awards held by each of our named executive officers as of December 31, 2012.

The following table sets forth information concerning equity awards for the named executive officers that vested during the year ended December 31, 2012.

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.

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.

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."

Under the employment agreements with Messrs. Zatezalo, Boone and Walton, 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. Walton 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, subject to his timely execution and delivery (and nonrevocation) of a release agreement for our benefit. Mr. Walton is also entitled to continue family health insurance, at the same premium cost as was in effect on the date of termination, until the earlier of twelve months or the date he becomes covered under a new employer's plan. In the event of the death of Mr. Zatezalo or Mr. Boone, his estate will be entitled to receive the accrued obligations and a pro-rated annual discretionary bonus. Messrs. Zatezalo, Boone and Walton are subject to certain confidentiality, non-compete and non-solicitation provisions contained in their respective employment

agreements. The confidentiality covenants are perpetual, while the non-compete and non-solicitation covenants apply during the term of the employment agreement and for one year following the executive's termination for any reason (two years following the executive's termination for any reason in the case of the non-solicitation covenant for Messrs. Zatezalo and Boone and 18 months for Mr. Walton).

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

Under the employment agreements with Mr. Cox and Mr. Hunt, if their employment is terminated by us without "cause," Mr. Cox 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 while Mr. Hunt is entitled to receive a lump sum payment equal to twelve months' worth of his base salary and continued family health insurance, at the same premium cost as was in effect on the date of termination, until the earlier of twelve months or the date he becomes covered under a new employer's plan. Mr. Cox and Mr. Hunt are subject to certain confidentiality, non-compete and non-solicitation provisions contained in their employment agreements. The confidentiality covenants are perpetual, while the non-compete covenants apply during the terms of the employment agreements and for one year following termination of employment (except that the non-compete covenant applies for only 90 days following Mr. Cox's termination by us without "cause"). The non-solicitation period runs until the end of the six month period following the end of the applicable non-compete period.

For purposes of the agreements with Messrs. Walton, Cox and Hunt, "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 (for Mr. Walton, being convicted of or pleading guilty or no contest to any felony or to any misdemeanor involving financial dishonesty or any other crime that would indicate that he is not

capable of successfully performing his obligations under his employment agreement) or (4) executive materially fails or neglects to diligently perform his duties.

Messrs. Zatezalo, Boone, Walton, 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 have the meaning set forth in the employment agreements of Messrs. Zatezalo and Boone. 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.

The table below discloses the amount of compensation and/or benefits due to Messrs. Zatezalo, Boone, Walton, 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, 2012, taking into account the arrangements described above and the salary and bonus rates in effect for the named executive officers for fiscal 2012, and (ii) that the price per common unit was $13.66, which was the closing price of our common units on December 31, 2012 (the last trading day in 2012). The table excludes amounts accrued through fiscal 2012 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 executive officer is actually terminated or a change in control actually occurs. Therefore, such amounts should be considered "forward-looking statements".

Name	Change in Control		Termination without Cause			Death		Resignation with Good Reason

David Zatezalo
Cash Payment	$	—	$	520,000		$	780,000	$	520,000
Accelerated Equity Vesting	$	333,181	$	333,181		$	333,181	$	333,181

Total	$	333,181	$	853,181		$	1,113,181	$	853,181
Richard Boone
Cash Payment	$	—	$	295,000		$	221,250	$	295,000
Accelerated Equity Vesting	$	152,651	$	124,921		$	152,651	$	124,921

Total	$	152,651	$	419,921		$	373,901	$	419,921
Christopher Walton
Cash Payment	$	—	$	300,000		$	—	$	150,000
Accelerated Equity Vesting	$	21,911	$	11,024		$	21,911	$	11,024

Total	$	21,911	$	311,024		$	21,911	$	161,024
Andrew Cox
Cash Payment	$	—	$	110,624	(2)	$	—	$	—
Accelerated Equity Vesting	$	23,400	$	11,515		$	23,400	$	11,515

Total	$	23,400	$	122,139		$	23,400	$	11,515
Reford Hunt
Cash Payment	$	—	$	235,000		$	—	$	235,000
Accelerated Equity Vesting	$	24,889	$	12,007		$	24,889	$	12,007

Total	$	24,889	$	247,007		$	24,889	$	247,007

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 approximately $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 made on a restricted unit are held by our general partner (without interest) and 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. 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, 2012.

(1): Includes annual base director fee, committee membership fees, and committee chair fees for each non-employee director as more fully explained in the preceding paragraphs.
(2): The amounts reported in the "Unit Awards" column reflect the aggregate grant date fair value of the awards granted under the LTIP in fiscal 2012, computed in accordance with FASB ASC Topic 718. See Note 2 to our consolidated financial statements for fiscal 2012 for additional detail regarding assumptions underlying the value of these equity awards. As of December 31, 2012, each non-employee director held 1,126 outstanding restricted units.
(3): Director compensation is paid or granted, as applicable, to these individuals in their capacities as agents for Wexford Capital. Restricted units granted to these individuals under the LTIP are treated for all purposes as grants to Wexford Capital or its assignee, as Wexford Capital may direct or provide, and not to the individual serving as a member of the board on behalf of Wexford Capital or its assignee.
(4): Messrs. Lambert and Plaumann have agreed or are obligated to transfer all or a portion of the compensation payable to them for their service on the board of directors of our general partner. Accordingly, as directed by Messrs. Lambert and Plaumann, the restricted units granted in respect of their service in fiscal 2012 were issued to entities in which they hold equity interests rather than to Messrs. Lambert and Plaumann individually.

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. Additionally, our annual discretionary bonuses are capped at certain percentages of our executive officers' salaries, as described earlier, which reduce the risk of actions being taken that increase short-term profit at the expense of long-term value creation. 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. Our grants of equity-based awards have historically included three-year vesting periods, which encourage our executive officers (and other employees) to focus on sustained growth over the long-term, rather than taking short-term risks.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The following table sets forth the beneficial ownership of common units and subordinated units as of February 28, 2013 of Rhino Resource Partners LP for:

The following table does not include any phantom unit 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."

Name of Beneficial Owner

Rhino Energy Holdings LLC(1)(3)(4)	6,010,265	39.1	%	8,597,487	69.4	%	52.6	%
Charles E. Davidson(1)(2)(3)(4)(5)	7,120,396	46.4	%	10,157,264	81.9	%	62.2	%
Joseph M. Jacobs(1)(2)(3)(4)	6,774,618	44.1	%	9,662,638	77.9	%	59.2	%
Wexford Capital LP(1)(2)(3)(4)	6,633,652	43.2	%	9,460,996	76.3	%	58.0	%
Wexford GP LLC(1)(2)(3)(4)	6,633,652	43.2	%	9,460,996	76.3	%	58.0	%
Mark D. Zand	14,493	*		20,729	—		*
David G. Zatezalo	35,836	*		—	—		*
Richard A. Boone	16,086	*		—	—		*
Christopher I. Walton	595	*		—	—		*
Andrew W. Cox	588	*		—	—		*
Reford C. Hunt	599	*		—	—		*
Jay L. Maymudes	14,613	*		20,903	*		*
Arthur H. Amron	12,199	*		17,447	*		*
Kenneth A. Rubin	8,914	*		12,754	*		*
Mark L. Plaumann(6)	4,425	*		682	*		*
Douglas Lambert(6)	3,948	*		—	—		*
James F. Tompkins(6)	4,948	*		—	—		*
All executive officers and directors as a group (13 persons)	6,891,862	44.9	%	9,735,153	78.5	%	59.9	%

beneficial ownership to the extent such beneficial ownership exceeds their respective pecuniary interests.

(2): 603,647 common units and 863,509 of the subordinated units shown as beneficially owned by each of Charles E. Davidson, Joseph M. Jacobs, Wexford GP LLC and Wexford Capital, reflect common units and subordinated units owned of record by Rhino Resource Holdings LLC ("RRH"). Wexford Capital serves as manager for RRH and as such may be deemed to share beneficial ownership of the units beneficially owned by RRH, but disclaims such beneficial ownership to the extent such beneficial ownership exceeds its pecuniary interest. Wexford GP, as the general partner of Wexford, may be deemed to share beneficial ownership of the units beneficially owned by RRH, but disclaims such beneficial ownership to the extent such beneficial ownership exceeds its pecuniary interest. Messrs. Davidson and Jacobs, as the controlling persons of Wexford GP, may be deemed to share beneficial ownership of any units beneficially owned by RRH for which Wexford serves as manager, but disclaim such beneficial ownership to the extent such beneficial ownership exceeds its pecuniary interest.
(3): The compensation we pay our non-executive directors includes an annual grant of common units having a grant date value of approximately $25,000, which are subject to the terms and conditions set forth in our LTIP. See "Item 11. Executive Compensation—Director Compensation." The annual grant on October 31, 2012 included a total of 7,510 common units granted to five Wexford Capital affiliated directors of our general partner on behalf of Wexford Capital. These units vest as follows: 1,880 units vested on the grant date, 1,880 units vested on January 1, 2013, 1,875 units will vest on April 1, 2013 and 1,875 units will vest on July 1, 2013. The units are reflected in the table above as beneficially owned by Wexford Capital, Wexford GP, as general partner of Wexford Capital, and Messrs. Davidson and Jacobs, as the controlling persons of Wexford GP. Wexford Capital, Wexford GP and Messrs. Davidson and Jacobs each disclaim beneficial ownership of these units to the extent such beneficial ownership exceeds their respective pecuniary interests.
(4): The address for this person or entity is 411 West Putnam Avenue, Greenwich, Connecticut 06830.
(5): Includes 486,744 common and 696,268 subordinated units held by CD Holding Company, LLC, for which Mr. Davidson is the sole managing member, and the common and subordinated units owned of record by Mr. Davidson's Roth IRA.
(6): Each of these three non-executive directors received an annual grant of 1,502 units on October 31, 2012 pursuant to the LTIP. These units vest as follows: 25% of the units vested upon the grant, 25% vested on January 1, 2013, and the remaining 50% vest ratably on April 1, 2013 and July 1, 2013.

For more information relating to our Long-Term Incentive Plan and the unit awards granted thereunder, please see Note 13 of the consolidated financial statements included elsewhere in this annual report.

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

As of February 28, 2013, Wexford owned 7,311,581 common units and 10,430,739 subordinated units representing approximately 63.9% 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.

During 2012, Wexford received distributions of approximately $1.0 million on the 2.0% general partner interest and approximately $26.7 million on its common units and subordinated units.

On February 14, 2013, Wexford received a distribution for the fourth quarter of 2012 of approximately $0.3 million on the 2.0% general partner interest and approximately $3.3 million on its common units. No distribution was paid on the subordinated units.

From time to time, employees from Wexford perform legal, consulting, and advisory services for us and we incur expenses related to these services. Please see Note 18 of our consolidated financial statements included elsewhere in this annual report for the amounts paid to Wexford for these services during the years ended December 31, 2012, 2011 and 2010.

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

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.

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.

Our initial position in the Utica Shale consisted of a 10.8% net interest in approximately 80,000 gross acres. During the third quarter of 2012, we completed an exchange of our initial 10.8% position for a pro rata interest in 125,000 gross acres under lease by Gulfport and an affiliate of Wexford Capital. Also during the third quarter of 2012, our position was adjusted to a 5% net interest in the 125,000 gross acres, or approximately 6,250 net acres. As of December 31, 2012, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 137,000 gross acres, or approximately 6,850 net acres. In addition, per the joint operating agreement completed between us, Gulfport and an affiliate of Wexford Capital, we have funded our proportionate share of drilling costs to Gulfport for wells being drilled on our acreage. During the year ended December 31, 2012, we funded approximately $5.3 million of drilling costs that are included in Coal properties and oil and natural gas properties in our consolidated statements of financial position as of December 31, 2012. Two of the wells on our acreage began production in late 2012 and we recognized our initial revenue on our Utica Shale investment during December 2012.

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:

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.

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.

The following table presents fees for professional services rendered by Deloitte & Touche LLP for 2012 and 2011:

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. All fees reported above were pre-approved by the audit committee as required.

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

		Description

2.1		Agreement of Merger among Rhino Resource Partners LP, Rhino Energy LLC, The Elk Horn Acquisition Co. LLC, and The Elk Horn Coal Company, LLC, and Peter Sisitsky, dated as of June 10, 2011, incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-34892) filed on June 16, 2011
2.2		Asset Purchase Agreement, dated August 15, 2011, by and among CAM Mining LLC, CAM-Kentucky Real Estate LLC, and Revelation Energy, LLC, incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K (File No. 001-034892) filed on August 19, 2011
2.3		Assignment and Assumption Agreement dated May 6, 2011, by and between Rhino Exploration LLC, Gulfport Energy Corporation and Windsor Ohio LLC, incorporated by reference to Exhibit 10.24 of the Registration Statement on Form S-1 (File No. 333-175138), filed on June 24, 2011
3.1		Certificate of Limited Partnership of Rhino Resource Partners LP, incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on May 5, 2010
3.2		Second Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated as of October 26, 2010, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-34892) filed on November 1, 2010
4.1		Registration Rights Agreement, dated as of October 5, 2010, by and between Rhino Resource Partners LP and Rhino Energy Holdings LLC, incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 8, 2010
10.1		Contribution, Assignment and Assumption Agreement, dated as of September 29, 2010, by and among Rhino GP LLC, Rhino Resource Partners LP, Rhino Energy LLC, Rhino Energy Holdings LLC, Artis Investors LLC, Solitair LLC, Valentis Investors LLC, Taurus Investors LLC, Callidus Investors LLC, Wexford Spectrum Fund, L.P., Wexford Spectrum Fund Liquidating LLC, Wexford Offshore CAM Preferred Corp., Wexford Offshore CAM Common Corp., Wexford Partners Investment Co. LLC, Peter Savitz and Wexford Capital LP, incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 2010
10.2		Equity Commitment Agreement, dated September 29, 2010, by and among Rhino GP LLC, CD Holding Company, LLC, Jacobs Holdings LLC, Robert H. Holtz, Mark D. Zand, Jay L. Maymudes, Arthur H. Amron, Kenneth A. Rubin, Frederick B. Simon, Kitty Capital LLC, John V. Doyle and John C. Sites, Jr., incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 2010
10.3	†	Rhino Long-Term Incentive Plan incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 2010
10.4	†	Form of Long-Term Incentive Plan Grant Agreement—Phantom Units with DERs, incorporated by reference to Exhibit 10.12 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010

		Description

10.5	†	Form of Long-Term Incentive Plan Grant Agreement—Unit Awards and Restricted Units (Directors who are not Principals of Wexford), incorporated by reference to Exhibit 10.22 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010
10.6	†	Form of Long-Term Incentive Plan Grant Agreement—Unit Awards and Restricted Units (Directors who are Principals of Wexford), incorporated by reference to Exhibit 10.23 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010
10.7	†	Employment Agreement of David G. Zatezalo dated March 31, 2010, incorporated by reference to Exhibit 10.13 of Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on June 21, 2010
10.8	†*	Amended and Restated Employment Agreement of David G. Zatezalo dated January 21, 2013.
10.9	†	Amended and Restated Employment Agreement of Andrew W. Cox dated January 14, 2011, incorporated by reference to Exhibit 10.25 to the Annual Report on Form 10-K (File No. 001-34892) filed on March 18, 2011
10.10	†	Amended and Restated Employment Agreement of Richard A. Boone dated May 31, 2011, incorporated by reference to Exhibit 10.17 of the Registration Statement on Form S-1 (File No. 333-175138), filed on June 24, 2011
10.11	†	Amended and Restated Employment Agreement of R. Chad Hunt dated September 8, 2011, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892) filed on September 13, 2011
10.12	†	Employment Agreement of Christopher N. Moravec dated March 31, 2010, incorporated by reference to Exhibit 10.15 of Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on June 21, 2010
10.13		Amended and Restated Credit Agreement, dated July 29, 2011 by and among Rhino Energy LLC, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets and Union Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners, Union Bank N.A., as Syndication agent, Raymond James Bank, FSB, Wells Fargo Bank, national Association and the Huntington National Bank, as Co-Documentation Agents and the guarantors and lenders party thereto, incorporated by reference to Exhibit 10.1 of the Current report on Form 8-K (File No. 001-34892), filed on August 4, 2011
21.1	*	List of Subsidiaries of Rhino Resource Partners LP
23.1	*	Consent of Deloitte & Touche LLP
23.2	*	Consent of Cardno MM&A
23.3	*	Consent of Norwest Corporation
23.4	*	Consent of John T. Boyd Company
23.5	*	Consent of Ryder Scott Company, LP
31.1	*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

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.

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.

To the Board of Directors of
the Managing General Partner
and the Partners of
Rhino Resource Partners LP
Lexington, Kentucky

We have audited the accompanying consolidated statements of financial position of Rhino Resource Partners LP and subsidiaries (the "Partnership") as of December 31, 2012 and 2011, 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, 2012. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 Rhino Resource Partners LP and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2013 expressed an unqualified opinion on the Partnership's internal control over financial reporting.

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(In thousands)

	As of December 31,

	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	461		$	449
Accounts receivable, net of allowance for doubtful accounts ($0 as of December 31, 2012 and 2011)		33,560			37,242
Inventories		18,743			15,629
Advance royalties, current portion		187			1,428
Prepaid expenses and other		4,323			4,327

Total current assets		57,274			59,075

PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs		683,669			637,563
Less accumulated depreciation, depletion and amortization		(219,709	)		(187,447	)

Net property, plant and equipment		463,960			450,116

Advance royalties, net of current portion		4,506			1,924
Investment in unconsolidated affiliates		23,659			18,736
Goodwill		—			202
Intangible assets, net		1,228			1,308
Other non-current assets		8,831			7,433

TOTAL	$	559,458		$	538,794

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	18,030		$	23,145
Accrued expenses and other		22,178			19,691
Current portion of long-term debt		2,350			1,334
Current portion of asset retirement obligations		2,255			3,192
Current portion of postretirement benefits		227			157

Total current liabilities		45,040			47,519

NON-CURRENT LIABILITIES:
Long-term debt, net of current portion		161,199			141,764
Asset retirement obligations, net of current portion		30,748			30,921
Other non-current liabilities		10,309			6,000
Postretirement benefits, net of current portion		6,520			5,492

Total non-current liabilities		208,776			184,177

Total liabilities		253,816			231,696

COMMITMENTS AND CONTINGENCIES (NOTE 14)
PARTNERS' CAPITAL:
Limited partners		292,791			293,100
General partner		11,420			11,650
Accumulated other comprehensive income		1,431			2,348

Total partners' capital		305,642			307,098

TOTAL	$	559,458		$	538,794

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(In thousands, except per unit data)

	Year Ended December 31,

	2012			2011			2010
REVENUES:
Coal sales	$	304,568		$	333,876		$	289,885
Freight and handling revenues		6,357			5,750			4,174
Other revenues		41,066			27,595			11,588

Total revenues		351,991			367,221			305,647
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		247,105			267,180			220,756
Freight and handling costs		5,833			4,329			2,634
Depreciation, depletion and amortization		41,370			36,325			34,108
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)		20,442			21,815			16,449
Asset impairment loss		—			—			652
(Gain) loss on sale/acquisition of assets, net		(4,890	)		(3,172	)		(10,716	)

Total costs and expenses		309,860			326,477			263,883

INCOME FROM OPERATIONS		42,131			40,744			41,764

INTEREST AND OTHER INCOME (EXPENSE):
Interest expense and other		(7,767	)		(6,062	)		(5,338	)
Interest income and other		92			51			24
Equity in net income of unconsolidated affiliates		5,766			3,338			4,699

Total interest and other (expense)		(1,909	)		(2,673	)		(615	)

INCOME BEFORE INCOME TAXES		40,222			38,071			41,149
INCOME TAXES		—			—			—

NET INCOME		40,222			38,071			41,149

Other comprehensive income—
Change in actuarial gain under ASC Topic 815		(917	)		1,723			(853	)

COMPREHENSIVE INCOME	$	39,305		$	39,794		$	40,296

Net income attributable to Predecessor—Jan 1 to Oct 5, 2010		n/a			n/a		$	35,703
Net income attributable to Partnership—Oct 6 to Dec 31, 2010		n/a			n/a		$	5,446
General partner's interest in net income	$	804		$	762		$	109
Common unitholders' interest in net income	$	21,794		$	19,603		$	2,668
Subordinated unitholders' interest in net income	$	17,624		$	17,706		$	2,669
Net income per limited partner unit, basic:
Common units	$	1.42		$	1.43		$	0.22
Subordinated units	$	1.42		$	1.43		$	0.22
Net income per limited partner unit, diluted:
Common units	$	1.42		$	1.43		$	0.22
Subordinated units	$	1.42		$	1.43		$	0.22
Distributions paid per limited partner unit(1)	$	1.85		$	1.8108			n/a
Weighted average number of limited partner units outstanding, basic:
Common units		15,331			13,725			12,400
Subordinated units		12,397			12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units		15,335			13,744			12,413
Subordinated units		12,397			12,397			12,397

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY/PARTNERS' CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010

(In thousands)

	Limited Partner

	Common					Subordinated								Accumulated Other Comprehensive Income/(Loss)
	Common					Subordinated					General Partner Capital						Total Partners' Capital
	Units		Capital			Units		Capital			General Partner Capital						Total Partners' Capital
BALANCE—October 5, 2010		—	$	—			—	$	—		$	—		$	—		$	—
Contribution from predecessor		9,153		73,320			12,397		99,306			—			1,365			173,991
Initial public offering		3,244		62,012			—		—			—			—			62,012
Initial general partner contribution		—		—			—		—			10,373			—			10,373
Offering costs		—		(1,842	)		—		(1,842	)		(76	)		—			(3,760	)
Net income after initial public offering		—		2,668			—		2,669			109			—			5,446
General partners' contributions		—		—			—		—			4			—			4
Equity-based compensation		—		241			—		—			—			—			241
Issuance of units under LTIP		3		50			—		—			—			—			50
Change in actuarial gain under ASC Topic 815		—		—			—		—			—			(740	)		(740	)

BALANCE—December 31, 2010		12,400	$	136,449			12,397	$	100,133		$	10,410		$	625		$	247,617
Net income		—		19,603			—		17,706			762			—			38,071
Distributions to unitholders and general partner		—		(25,215	)		—		(22,449	)		(972	)		—			(48,636	)
General partners' contributions		—		—			—		—			1,450			—			1,450
Offering of common units		2,875		66,916			—		—			—			—			66,916
Offering costs		—		(560	)		—		(9	)		—			—			(569	)
Equity-based compensation		—		(241	)		—		—			—			—			(241	)
Issuance of units under LTIP		36		767			—		—			—			—			767
Change in actuarial gain under ASC Topic 815		—		—			—		—			—			1,723			1,723

BALANCE—December 31, 2011		15,311	$	197,719			12,397	$	95,381		$	11,650		$	2,348		$	307,098

Net income		—		21,794			—		17,624			804			—			40,222
Distributions to unitholders and general partner		—		(28,470	)		—		(11,901	)		(1,047	)		—			(41,418	)
General partners' contributions		—		—			—		—			13			—			13
Offering costs		—		(7	)		—		—			—			—			(7	)
Issuance of units under LTIP		39		651			—		—			—			—			651
Change in actuarial gain under ASC Topic 815		—		—			—		—			—			(917	)		(917	)

BALANCE—December 31, 2012		15,350	$	191,687			12,397	$	101,104		$	11,420		$	1,431		$	305,642

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,

	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	40,222		$	38,071		$	41,149
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		41,370			36,325			34,108
Accretion on asset retirement obligations		1,896			1,956			2,165
Accretion on interest-free debt		222			210			206
Amortization of deferred revenue		(929	)		(532	)		—
Amortization of advance royalties		244			1,104			865
Amortization of debt issuance costs		1,075			1,043			844
Amortization of actuarial gain		(295	)		—			—
Provision for doubtful accounts		—			(19	)		—
Equity in net (income) of unconsolidated affiliates		(5,766	)		(3,338	)		(4,699	)
Distributions from unconsolidated affiliate		2,958			3,351			—
Loss on retirement of advance royalties		100			79			396
(Gain) loss on sale of assets—net		(4,878	)		(3,172	)		73
Loss on impairment of assets		—			—			652
(Gain) on acquisition of assets		—			—			(10,789	)
Equity-based compensation		873			727			291
Changes in assets and liabilities:
Accounts receivable		6,465			(7,253	)		(2,968	)
Inventories		(3,114	)		6			(1,463	)
Advance royalties		(1,687	)		(905	)		(1,541	)
Prepaid expenses and other assets		1,363			571			(1,624	)
Accounts payable		(5,540	)		4,435			1,416
Accrued expenses and other liabilities		5,797			(1,752	)		1,391
Asset retirement obligations		(1,108	)		(4,722	)		(6,049	)
Postretirement benefits		476			731			578

Net cash provided by operating activities		79,744			66,916			55,001

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment		(61,772	)		(91,856	)		(26,248	)
Proceeds from sales/recoveries of property, plant, and equipment		5,479			3,415			95
Proceeds from sale of coal properties and related assets and liabilities		—			20,000			—
Principal payments received on notes receivable		11,945			5,780			1,142
Cash paid from issuance of notes receivable		(11,945	)		(5,780	)		(765	)
Changes in restricted cash		3			34			(3	)
Return of capital from unconsolidated affiliate		—			—			3,137
Investment in unconsolidated affiliates		(2,114	)		—			—
Acquisitions of coal companies and other properties		—			(119,617	)		(15,002	)

Net cash used in investing activities		(58,404	)		(188,024	)		(37,644	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit		212,300			338,200			116,070
Repayments on line of credit		(192,050	)		(229,670	)		(201,600	)
Proceeds from issuance of long-term debt		2,973			1,379			2,170
Repayments on long-term debt		(2,994	)		(3,550	)		(2,455	)
Payments on debt issuance costs		—			(3,758	)		(782	)
Proceeds from issuance of common units		—			66,916			62,012
Payment of offering costs		(7	)		(569	)		(3,760	)
Net settlement of withholding taxes on employee unit awards vesting		(145	)		(281	)		—
General partner's contributions		13			1,450			10,377
Distributions to unitholders		(41,418	)		(48,636	)		—

Net cash (used in) provided by financing activities		(21,328	)		121,481			(17,968	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		12			373			(611	)
CASH AND CASH EQUIVALENTS—Beginning of period		449			76			687

CASH AND CASH EQUIVALENTS—End of period	$	461		$	449		$	76

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010

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"). 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 and Utah. The Partnership also has one underground mine located in Colorado that remained temporarily idled at December 31, 2012. The majority of the Partnership's sales are made to electric utilities and other coal-related organizations in the United States. In addition to operating coal properties, the Partnership manages and leases coal properties and collects royalties from such management and leasing activities. In addition to the Partnership's coal operations, the Partnership has invested in oil and natural gas mineral rights and operations that began to generate revenues in early 2012.

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.

On July 18, 2011, the Partnership completed a public offering of 2,875,000 common units, representing limited partner interests in the Partnership, at a price of $24.50 per common unit. Of the common units issued, 375,000 units were issued in connection with the exercise of the underwriters' option to purchase additional units. Net proceeds from the offering were approximately $66.4 million, after deducting underwriting discounts and offering expenses of approximately $4.1 million. The Partnership used the net proceeds from this offering, and a related capital contribution by the General

Partner of approximately $1.4 million, to repay approximately $67.8 million of outstanding indebtedness under the Partnership's credit facility.

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 15 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.

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 16 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.

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. At various times during 2012, the Partnership loaned to Rhino Eastern LLC ("Rhino Eastern"), a joint venture with an affiliate of Patriot Coal Corporation ("Patriot"), approximately $11.9 million that was recorded as notes receivable, which bear interest at a fixed rate of 10%. The notes were fully repaid as of December 31, 2012.

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. The Partnership assumes zero salvage values for its property, plant and equipment when depreciation and amortization are calculated. 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.

For the Partnership's oil and natural gas investments, the Partnership uses the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or cost center ceiling, on the book value of the oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price during the

applicable year, excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of natural gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization are detailed in Note 5. These costs are reviewed quarterly by the Partnership for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and natural gas properties subject to amortization. Factors considered by the Partnership in its impairment assessment include drilling results by the operators on the Partnership's oil and natural gas properties, the terms of oil and natural gas leases not held by production, and available funds for exploration and development.

Asset Impairments for Coal Properties, Mine Development Costs and Other Coal Mining Equipment and Related Facilities. The Partnership follows the accounting guidance on the impairment or disposal of property, plant and equipment for its coal mining assets, 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, the Partnership must determine the fair value for the coal mining 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 coal mining assets and their respective fair values. Also, in certain situations, expected mine lives are shortened because of changes to planned operations or changes in coal reserve estimates. 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 coal 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 6 for a discussion of this asset impairment loss recorded in 2010. There were no impairment losses recorded during the years ended December 31, 2012 and 2011.

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 for its mining

operations in coal properties and oil and natural gas properties. The Partnership has not recorded asset retirement costs for its proportionate share of its oil and natural gas investments since this amount was immaterial as of December 31, 2012.

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.

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. For the Partnership's mining operations, changes in the asset retirement obligations for the year ended December 31, 2012 were calculated with discount rates that ranged from 3.2% to 5.3% depending upon the timing of the cash flows of the specific obligations. The discount rates 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 year ended December 31, 2011 were calculated with discount rates that ranged from 4.2% to 7.0% depending upon the timing of the cash flows of the specific obligations. Changes in the asset retirement obligations for the year ended December 31, 2010 were calculated with a discount rate of 7.5%. 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 2.3% for 2012, 2.5% for 2011 and 3.0% for 2010.

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, 2012 and 2011, the workers' compensation benefits liability balance included approximately $10.3 million and $6.0 million, respectively, in the non-current liabilities section of the Partnership's consolidated statements of financial position. The balance as of December 31, 2012 consisted of $3.8 million that is the primary obligation of the Partnership, but this amount is also due from the Partnership's insurance providers, which is included in Note 8 as non-current receivables,

based on the Partnership's workers' compensation insurance coverage. The Partnership presents this amount on a gross asset and liability basis since a right of setoff does not exist per the accounting guidance in Accounting Standards Codification ("ASC") Topic 210. The workers' compensation liability was presented on a net basis as of December 31, 2011, which was not material to the consolidated statement of financial position. This presentation has no impact on the Partnership's results of operations or cash flows.

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 coal royalty revenues, limestone sales, coal handling and processing, oil and natural gas revenues, rebates and rental income. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership's lessees and the corresponding gross revenues from those sales. The leases are based on (1) minimum monthly or annual payments, (2) a minimum dollar royalty per ton and/or a percentage of the gross sales price, or (3) a combination of both. Coal royalty revenues are recorded from royalty reports submitted by the lessee, which are reconciled and subject to audit by the Partnership. Most of the Partnership's lessees are required to make minimum monthly or annual royalty payments that are recoupable over certain time periods, generally two years. If tonnage royalty revenues do not meet the required minimum amount, the difference is paid as a deficiency. These deficiency payments received are recognized as an unearned revenue liability because they are generally recoupable over certain time periods. When a lessee recoups a deficiency payment through production, the recouped amount is deducted from the unearned revenue liability and added to revenue attributable to the coal royalty revenue in the current period. If a lessee does not recoup a deficiency paid during the allocated time period, the recoupment right lost becomes revenue in the current period and is deducted from the liability.

With respect to other revenues recognized in situations unrelated to the shipment of coal or coal royalties, the Partnership carefully reviews the facts and circumstances of each transaction and does 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.

Equity-Based Compensation. The Partnership applies the provisions of ASC Topic 718 to account for any unit awards granted to employees or directors. This guidance requires that all share-based payments to employees or directors, 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.

With the vesting of the first portion of the employees' awards in early April 2011, the Compensation Committee of the board of directors of the General Partner elected to pay some of the awards in cash or a combination of cash and common units. This election was a change in policy from December 31, 2010 since management had previously planned to settle all employee awards with units upon vesting as per the grant agreements. This policy change resulted in a modification of all employee awards from equity to liability classification as of March 31, 2011 and all new awards granted thereafter. Thus, the employee awards are required to be marked-to-market each reporting period until they are vested. Restricted 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 also required to be marked-to-market each reporting period until they are vested. Expense related to unit awards is recorded in the selling, general and administrative line of the Partnership's consolidated statements of operations and comprehensive income.

Derivative Financial Instruments. The Partnership 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 Ventures. 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. Any losses from the Partnership's equity method investment are absorbed by the Partnership based upon its proportionate ownership percentage. If losses are incurred that exceed the Partnership's investment in the equity method entity, then the Partnership must continue to record its proportionate share of losses in excess of its investment. 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 Rhino Eastern 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 Rhino Eastern and its results of operations under the equity method. The Partnership considers the operations of this entity to comprise a reporting segment

("Eastern Met") and has provided additional detail related to this operation in Note 20, "Segment Information."

In determining that the Partnership was not the primary beneficiary of the variable interest entity for the years ended December 31, 2012, 2011 and 2010, the Partnership performed a qualitative and quantitative analysis based on the controlling economic interests of the Rhino Eastern joint venture. This included an analysis of the expected economic contributions of the joint venture. The Partnership concluded that it is not the primary beneficiary of Rhino Eastern 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, 2012 and 2011, the Partnership has recorded its equity method investment of $21.8 million and $18.7 million, respectively, in the Rhino Eastern joint venture as a long-term asset. The Partnership has not provided any additional contractually required support as of December 31, 2012. As disclosed in Note 18 "Related Party and Affiliate Transactions", the Partnership provided a loan to Rhino Eastern in the amount of $0.4 million as of December 31, 2009 that was fully repaid as of December 31, 2010. During 2012 and 2011, the Partnership provided loans Rhino Eastern totaling approximately $11.9 million and $5.8 million, respectively, which were fully repaid as of December 31, 2012 and 2011.

On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

In March 2012, the Partnership made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf Terminals LLC ("Timber Wolf"), with affiliates of Wexford. Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio. The initial investment was the Partnership's proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during the year ended December 31, 2012 and the Partnership will initially include any operating activities of Timber Wolf in its Other category.

In December 2012, the Partnership made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppants LLC ("Muskie"), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S. The Partnership recorded its proportionate portion of the operating loss for 2012, approximately $257,000, for Muskie, which is still undergoing operational development. The Partnership will initially include any operating activities of Muskie in its Other category.

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 14, "Commitments and Contingencies," for a discussion of such 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 and 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. In June 2011, the FASB published ASU No. 2011-05, "Comprehensive Income (Topic 220): Presentation of Comprehensive Income". Under the amendments in this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. For public entities, the amendments of this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

Subsequently, in December 2011, the FASB issued ASU No. 2011-12, "Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05". In order to defer only those changes in Update 2011-05 that relate to the presentation of reclassification adjustments, the paragraphs in this ASU supersede certain pending paragraphs in ASU 2011-05. The amendments are being made to allow the FASB time to re-deliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, entities should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Public entities should apply these requirements for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership has consistently presented comprehensive income in a single continuous statement with net income, so the provisions of ASU 2011-05 and the related deferral included in ASU 2011-12 did not have a material effect on the Partnership.

On January 22, 2013, the Partnership announced a cash distribution of $0.445 per common unit, or $1.78 per unit on an annualized basis. This distribution was paid on February 14, 2013 to all common unitholders of record as of the close of business on February 1, 2013. No distributions were paid on the subordinated units.

In June 2011, the Partnership completed the acquisition of 100% of the ownership interests in The Elk Horn Coal Company, LLC ("Elk Horn") for approximately $119.7 million in cash consideration, or approximately $119.6 million net of cash acquired (referred to as the "Elk Horn Acquisition"). Elk Horn is primarily a coal leasing company that owns or controls coal reserves and non-reserve coal deposits and surface acreage in eastern Kentucky. The Elk Horn Acquisition was initially funded with borrowings under the Partnership's credit facility. The Partnership completed a public offering of common units in July 2011 that provided proceeds the Partnership used to repay existing indebtedness on its credit facility that was incurred from the Elk Horn acquisition. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date:

	(in thousands)

Cash	$	58
Accounts receivable		2,619
Prepaid expenses and other		94
Property, plant and equipment		7,466
Mine development costs		3,000
Coal properties		111,647
Intangible assets		654
Other non-current assets		1,112
Accounts payable		(79	)
Deferred revenues		(2,499	)
Accrued expenses and other		(1,691	)
Asset retirement obligations		(2,707	)

Net assets acquired	$	119,674

Total consideration	$	119,674

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. The studies related to the value of the property, plant and equipment, coal properties, intangible assets acquired and asset retirement obligations. The table above reflects the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed in the Elk Horn Acquisition, which resulted in no recognition of goodwill or gain on the acquisition. The Partnership's consolidated statements of operations and comprehensive income do not include revenue, costs or net income from Elk Horn prior to June 10, 2011, the effective date of the acquisition. The post-acquisition revenue of

Elk Horn that is included in the Partnership's results was approximately $13.0 million for the year ended December 31, 2011. The post-acquisition net income of Elk Horn that is included in the Partnership's results was approximately $7.7 million for the year ended December 31, 2011.

The following table presents selected unaudited pro forma financial information for the years ended December 31, 2011 and 2010, as if the acquisition had occurred on January 1, 2010. The pro forma information was prepared using Elk Horn's historical financial data and also reflects adjustments based upon assumptions by the Partnership's management to give effect for certain pro forma items that are directly attributable to the acquisition. These pro forma adjustment items include increased depletion expense related to the step-up in basis for the mineral assets acquired and increased interest expense from borrowings incurred to fund the acquisition. The pro forma adjustments for interest expense and earnings per unit reflect the net amount of the additional borrowings incurred by the Partnership in June 2011 to initially fund the acquisition that were partially offset by proceeds from common units issued in a public offering completed in July 2011. Supplemental pro forma revenue, net earnings and earnings per unit disclosures are as follows.

During the year ended December 31, 2011, the Partnership completed the acquisition of certain oil and natural gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. The Partnership began to receive royalty revenues from these mineral rights in early 2012.

The Partnership and an affiliate of Wexford Capital have participated with Gulfport Energy ("Gulfport"), a publicly traded company, to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. During the year ended December 31, 2011, the Partnership completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio, which

consisted of a 10.8% net interest in approximately 80,000 gross acres. During the third quarter of 2012, the Partnership completed an exchange of its initial 10.8% position for a pro rata interest in 125,000 gross acres under lease by Gulfport and an affiliate of Wexford Capital. The non-cash transaction was an exchange of the Partnership's operating interest for the operating interest owned by another party in order to diversify the Partnership's risk in its oil and natural gas investment. Thus, the Partnership determined that the non-cash exchange of the Partnership's ownership interest in the Utica acreage did not result in any gain or loss. Also during the third quarter of 2012, the Partnership's position was adjusted to a 5% net interest in the 125,000 gross acres, or approximately 6,250 net acres. As of December 31, 2012, the Partnership had invested approximately $24.2 million for its pro rata interest in the Utica Shale portfolio of oil and natural gas leases, which consisted of a 5% interest in a total of 137,000 gross acres, or 6,850 net acres. In addition, per the joint operating agreement completed between the Partnership, Gulfport and an affiliate of Wexford Capital, the Partnership has funded its proportionate share of drilling costs to Gulfport for wells being drilled on the Partnership's acreage. For the year ended December 31, 2012, the Partnership has funded approximately $5.3 million of drilling costs that are included in Coal properties and oil and natural gas properties in the consolidated statements of financial position as of December 31, 2012. Two wells began production in late 2012 and the Partnership recognized an immaterial amount of revenue and depletion expense from its Utica Shale investment for the year ended December 31, 2012.

In March 2012, the Partnership completed a lease agreement with a third party for an estimated 1,500 acres that the Partnership previously owned in the Utica Shale region in Harrison County, Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the third party to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay the Partnership the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232 acres. The Partnership is working to resolve title issues on approximately 250 remaining acres to be included in the lease. In addition, the lease agreement stipulates that the third party shall pay the Partnership a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

The Partnership analyzed the lease agreement and determined that the lease bonus payments represented a conveyance of these oil and natural gas rights, and should be recognized as a component of the Partnership's consolidated statements of operations. This determination was based upon the fact that that the lease agreement did not require the Partnership to perform any future obligations to perform or participate in drilling activities and the lease agreement did not result in any pooling of assets that would be used to perform any future drilling activities. In addition, the entire amount of the lease bonus was recognized as Other revenues since the Partnership's business activities have historically included the leasing of mineral resources, including coal leasing, which have been recorded as Other revenues. These leasing activities are expected to continue. For the year ended December 31, 2012, the Partnership recorded $7.4 million related to the initial lease bonus payments within Other revenues in the Partnership's Northern Appalachia segment.

In May 2012, the Partnership completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for approximately $1.5 million. In addition, the Partnership could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was initially recorded in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount have not yet occurred.

During the third quarter of 2012, the Partnership paid $1.6 million of the $2.0 million that was accrued related to the acquisition since the conditions requiring payment had been met. The remaining accrued balance of $0.4 million is recorded in the Partnership's consolidated statements of financial position as of December 31, 2012 since the conditions remained probable and estimable.

The coal leases and property are estimated to contain approximately 32 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is undeveloped, but fully permitted, and provides the Partnership with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers.

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

In June 2011, the Partnership acquired approximately 32,600 acres and associated surface rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million. These development stage properties are unpermitted and contain no infrastructure. The property is estimated to contain approximately 8.6 million tons of proven and probable underground metallurgical coal reserves as of December 31, 2012. The Partnership plans to eventually commence production on this 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 Partnership staffed the location and rehabilitated the mine and equipment and began production from these assets at one underground mine in the first quarter of 2011. The coal produced and sold from these mining assets is being sold as steam coal.

The Partnership allocated the purchase price of $15.0 million to the assets and liabilities acquired based upon their respective fair values in accordance with ASC Topic 805. 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 was 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 in the third quarter of 2010. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy.

Prepaid expenses and other current assets as of December 31, 2012 and 2011 consisted of the following:

Property, plant and equipment, including coal properties and mine development and construction costs, as of December 31, 2012 and 2011 are summarized by major classification as follows:

The Partnership's proportionate share of oil and natural gas properties not subject to amortization as of December 31, 2012 and 2011 are summarized as follows:

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties, amortization expense for mine development costs, amortization expense for intangible

assets and amortization expense for asset retirement costs for the years ended December 31, 2012, 2011 and 2010 was as follows:

In December 2012, the Partnership completed the sale of the surface rights to approximately 134 acres located in Harrison County, Ohio for approximately $1.5 million. The Partnership recorded a gain of approximately $1.5 million related to this sale that is included on the (Gain) loss on sale/acquisition of assets, net line of the Partnership's consolidated statements of operations and comprehensive income.

In August 2012, the Partnership sold the operations and tangible assets of its roof bolt manufacturing company, Triad Roof Support Systems, LLC ("Triad"), to a third party for $0.5 million of cash consideration. As part of the sale, the Partnership retained the rights to certain intellectual property and entered into an exclusive license and option to purchase agreement for this intellectual property with the same third party for potential additional cash consideration. The Partnership has not recorded any portion of this additional consideration since this amount is contingent upon the third party determining the viability of the related intellectual property to their specifications. In connection with the purchase of Triad in 2009, the Partnership had recorded approximately $0.2 million of goodwill. Since the Partnership disposed of the entire operations and fixed assets of the Triad reporting unit, the goodwill was included in the carrying amount of the Triad reporting unit to determine the $0.2 million gain that was recorded on the sale of this reporting unit. This gain is included on the (Gain) loss on sale/acquisition of assets, net line of the Partnership's consolidated statements of operations and comprehensive income.

In December 2012, the Partnership sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.2 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, the Partnership recorded a gain of approximately $0.9 million, which was higher than the

sales amount due to the extinguishment of the liabilities. This gain is included on the (Gain) loss on sale/acquisition of assets, net line of the Partnership's consolidated statements of operations and comprehensive income.

In February 2012, the Partnership sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.6 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, the Partnership recorded a gain of approximately $0.9 million, which was higher than the sales amount due to the extinguishment of the liabilities. This gain is included on the (Gain) loss on sale/acquisition of assets, net line of the Partnership's consolidated statements of operations and comprehensive income.

In August 2011, the Partnership closed on an agreement to sell and assign certain non-core mining assets and related liabilities located in the Phelps, Kentucky area of the Partnership's Tug River mining complex for $20 million. The mining assets included leasehold interests and permits to surface and mineral interests that included steam coal reserves and non-reserve coal deposits. Additionally, the sales agreement includes the potential for additional payments of approximately $8.75 million dependent upon the future issuance of certain permits and the commencement of mining activities by the purchaser. These contingent payments are being accounted for as gain contingencies and will be recognized in the future when and if the contingencies are resolved. The transaction also transfers certain liabilities related to the assets sold. In relation to the sale of these assets and transfer of liabilities, the Partnership recorded a gain of approximately $2.4 million, which is included on the (Gain) loss on sale/acquisition of assets, net line of the Partnership's consolidated statements of operations and comprehensive income.

During the fourth quarter of 2010, the management of the Partnership made a strategic decision to dispose of certain assets of two of its ancillary businesses. As of December 31, 2010, the management of the Partnership tested the assets related to these ancillary businesses for recoverability by comparing expected undiscounted future cash flows to their carrying values. This analysis indicated a potential impairment existed for these specific assets. Since the potential for impairment existed for these assets, the Partnership measured an impairment loss by determining the amount by which the carrying amount of the assets exceeded their fair value. Additionally, the Partnership determined the specific assets of these ancillary businesses should be classified as held for sale since they were being actively marketed to third-party buyers as of December 31, 2010 and the remaining requirements of the accounting literature on asset impairments had been met to qualify as being held for sale. The Partnership concluded the market approach would be the best indicator of fair value as market participants would place bids for the specific assets that would reflect the assets highest and best use in the marketplace. The assets were written down to their fair value, less costs to sell, at December 31, 2010 which resulted in a $0.7 million charge that is reflected on the Asset impairment loss line of the consolidated statements of operations and comprehensive income. This charge was reflected in the Other category for 2010 segment reporting purposes. The remaining assets from these ancillary businesses were sold during 2012 for an immaterial gain. The carrying value of these assets at December 31, 2011 was $0.8 million and they were included in Property, plant and equipment on the consolidated statements of

financial position due to their immaterial amount. Based on the fair value determination that was developed from unobservable data and reflected the Partnership's assumptions, these assets were determined to be a Level 3 fair value measurement. These assets are the only Level 3 fair value measurements for the Partnership for any periods presented in this report.

ASC Topic 350 addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under the provisions of ASC Topic 350, goodwill and other intangible assets with indefinite useful lives are not amortized but instead tested for impairment at least annually.

As discussed in Note 6, the Partnership's goodwill balance was reduced to zero as a result of the disposal of the Partnership's Triad operations that were sold during the third quarter of 2012.

Intangible assets of the Partnership as of December 31, 2012 consisted of the following:

Intangible assets of the Partnership as of December 31, 2011 consisted of the following:

The Partnership considers the patent and developed technology intangible assets to have a useful life of seventeen years.

In connection with the Elk Horn Acquisition, the Partnership recognized an intangible asset for the trade name valued at $184,000 and a customer list intangible asset valued at $470,000 during 2011. The trade name and customer list intangible assets recognized in the Elk Horn Acquisition do not have any residual value and do not have any renewal or extension terms. The Partnership considers the trade name and customer list intangible assets to have a useful life of twenty years. All of the intangible assets are amortized over their useful life on a straight line basis. Amortization expense for the years ended December 31, 2012, 2011 and 2010 is included in the depreciation, depletion and amortization table included in Note 6.

The future total amortization expense for each of the five succeeding years related to intangible assets that are currently recorded in the consolidated statement of financial position is estimated to be as follows at December 31, 2012:

Other non-current assets as of December 31, 2012 and 2011 consisted of the following:

Debt issuance costs were $8.0 million as of December 31, 2012 and 2011. Accumulated amortization of debt issuance costs were $4.2 million and $3.1 million as of December 31, 2012 and 2011, respectively. The non-current receivable balance of $3.8 million as of December 31, 2012 consisted of the amount due from the Partnership's workers' compensation insurance providers for potential claims that are the primary responsibility of the Partnership, but are covered under the Partnership's insurance policies. See Note 2 for a discussion of the $3.8 million that is also recorded in the Partnership's other non-current workers' compensation liabilities.

Accrued expenses and other current liabilities as of December 31, 2012 and 2011 consisted of the following:

The $2.8 million accrued for insured litigation claims as of December 31, 2012 consists of probable and estimable litigation claims that are the primary obligation of the Partnership. This amount is also due from the Partnership's insurance providers and is included in Accounts receivable, net of allowance for doubtful accounts on the Partnership's consolidated statements of financial position. The Partnership presents this amount on a gross asset and liability basis as a right of setoff does not exist per the accounting guidance in ASC Topic 210. The amount for insured litigation claims was presented on a net basis as of December 31, 2011, which was not material to the consolidated statement of financial position. This presentation has no impact on the Partnership's results of operations or cash flows.

Senior Secured Credit Facility with PNC Bank, N.A.—The original maximum availability under the credit facility by and among the Operating Company, the guarantors (including the Partnership) and lenders which are parties thereto, and PNC Bank, N.A. as administrative agent was $200.0 million. On June 8, 2011, with the consent of the lenders, the Operating Company exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn Acquisition discussed earlier. As part of exercising this option to increase the available amount under the credit agreement, the Operating Company paid a fee of $1.0 million to the lenders, which was recorded in Debt issuance costs in Other non-current assets on the Partnership's consolidated statements of financial position and in Cash flows from financing activities in the Partnership's consolidated statements of cash flows.

On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit. Borrowings under the facility bear interest, which varies depending upon the levels of certain financial ratios. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability that also varies depending upon the levels of certain financial ratios. Borrowings on the amended and restated senior secured credit facility are collateralized by all the unsecured assets of the Partnership. The amended and restated senior secured credit facility requires the Partnership 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. The Partnership was in compliance with all covenants contained in the amended and restated senior secured credit facility as of and for the period ended December 31, 2012. The amended and restated senior secured credit facility expires in July 2016.

As part of executing the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $2.8 million to the lenders, which was recorded in Debt issuance costs in Other non-current assets on the Partnership's consolidated statements of financial position and in Cash flows from financing activities in the Partnership's consolidated statements of cash flows. The Partnership evaluated the accounting guidance in ASC Topic 470, Debt, De-recognition, Line-of-Credit or Revolving-Debt Arrangements, and determined that the balance of the previous deferred financing costs met the requirements to be included with the fees paid for the amended and restated credit facility, with the combined balance of financing costs being deferred and amortized over the five year term of the amended and restated credit facility.

At December 31, 2012, the Operating Company had borrowed $156.0 million at a variable interest rate of LIBOR plus 2.75% (2.97% at December 31, 2012) and an additional $1.3 million at a variable interest rate of PRIME plus 1.75% (5.00% at December 31, 2012). In addition, the Operating Company had outstanding letters of credit of $23.2 million at a fixed interest rate of 2.75% at December 31, 2012. Based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $72.1 million of the borrowing availability at December 31, 2012.

Note payable to H&L Construction Co., Inc.—The note payable to H&L Construction Co., Inc. was originally a non-interest bearing note and the Partnership has recorded a discount for imputed interest at a rate of 5.0% on this note that is being amortized over the life of the note using the effective interest method. The note payable matures in January 2015. The note is secured by mineral rights purchased by the Partnership from H&L Construction Co., Inc. with a carrying amount of $11.3 million and $11.6 million at December 31, 2012 and 2011, respectively.

Principal payments on long-term debt due subsequent to December 31, 2012 are as follows:

The changes in asset retirement obligations for the years ended December 31, 2012, 2011 and 2010 are as follows:

Postretirement Plan—In conjunction with the acquisition of the coal operations of American Electric Power on April 16, 2004, the Operating Company acquired a postretirement benefit plan providing healthcare to eligible employees at its Hopedale operations. The Partnership has no other postretirement plans.

Summaries of the changes in benefit obligations and funded status of the plan as of the measurement dates of December 31, 2012, 2011 and 2010 are as follows:

The classification of net amounts recognized for postretirement benefits as of December 31, 2012 and 2011 are as follows:

The amounts recognized in accumulated other comprehensive income for the years ended December 31, 2012, 2011 and 2010 are as follows:

The components of net periodic benefit cost for the years ended December 31, 2012, 2011 and 2010 are as follows:

Amounts expected to be amortized from accumulated other comprehensive income into net periodic benefit cost during the year ending December 31, 2013, are as follows:

For measurement purposes, a 7.50% annual rate of increase in the per capita cost of covered health care benefits was assumed, gradually decreasing to 4.50% in 2027 and remaining level thereafter.

Net periodic benefit cost is determined using the assumptions as of the beginning of the year, and the funded status is determined using the assumptions as of the end of the year. Effective June 1, 2007, employees hired by the Partnership are not eligible for benefits under the plan.

The expense and liability estimates can fluctuate by significant amounts based upon the assumptions used by the Partnership. As of December 31, 2012, a one-percentage-point change in assumed health care cost trend rates would have the following effects:

401(k) Plans—The Partnership and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Partnership matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant's salary with an additional matching contribution possible at the Partnership's discretion. The expense under these plans for the years ended December 31, 2012, 2011 and 2010 was as follows:

In October 2010, the General Partner established the Rhino Long-Term Incentive Plan (the "Plan" or "LTIP"). The Plan is intended to promote the interests of the Partnership by providing to employees, consultants and directors of the General Partner, the Partnership or affiliates of either incentive compensation awards to encourage superior performance. The LTIP provides for grants of restricted units, unit options, unit appreciation rights, phantom units, unit awards, and other unit-based awards. The aggregate number of units initially reserved for issuance under the LTIP is 2,479,400.

As of December 31, 2012, the General Partner granted phantom units to certain employees and restricted units and unit awards to its directors. A portion of these grants were made in connection with the IPO completed during October 2010, as well as annual restricted unit awards to directors and phantom unit awards granted in the first quarter of 2012 to certain employees in connection with fiscal year 2011 performance. The phantom units granted in the first quarter of 2012 vest in equal annual installments over a three year period from the date of grant. The remaining terms and conditions of these phantom unit awards are similar to the phantom units awarded in connection with the

Partnership's IPO. A summary of non-vested LTIP awards as of and for the years ended December 31, 2012 and 2011 is as follows:

With the vesting of the first portion of the employees' awards in early April 2011, the Compensation Committee of the board of directors of the General Partner elected to pay some of the awards in cash or a combination of cash and common units. This election was a change in policy since management had previously planned to settle all employee awards with units upon vesting as per the grant agreements. This policy change resulted in a modification of all employee awards from equity to liability classification as of March 31, 2011 and all new awards granted thereafter. The Partnership incurred incremental compensation expense for the year ended December 31, 2011 of approximately $0.1 million due to the modification of these awards. The equity balance of approximately $0.2 million accrued as of December 31, 2010 for the non-vested awards was also reclassified from the Limited partners' capital account to Accrued expenses and other in the current liability portion in the consolidated statement of financial position as of December 31, 2011. For the year ended December 31, 2012, the Partnership did not record any incremental compensation expense due to the modification of the employees' IPO awards since the market price of the Partnership's common units was below the IPO grant price.

For the years ended December 31, 2012, 2011 and 2010, the Partnership recorded expense of approximately $0.9 million, approximately $1.1 million and approximately $0.3 million, respectively, for the LTIP awards. All of the non-vested LTIP awards granted during 2012, 2011 and 2010 included, with respect to the phantom unit awards, distribution equivalent rights (or DERs) or unit distribution rights, with respect to restricted unit awards, each of which are rights to accrue quarterly cash distributions in an amount equal to the cash distribution the Partnership makes to unitholders during the vesting period. However, any accrued distributions will be forfeited if the related awards fail to vest according to the relevant vesting conditions of the award.

For the year ended December 31, 2012, the total fair value of the awards that vested was $0.8 million. As of December 31, 2012, the total unrecognized compensation expense related to the non-vested LTIP awards that are expected to vest was $1.0 million. The expense is expected to be

recognized over a weighted-average period of 1.1 years. As of December 31, 2012, the intrinsic value of the non-vested LTIP awards was $0.9 million.

During the first quarter of 2013, certain employees received grants of phantom units with tandem DERs under the LTIP program. These awards were granted in connection with fiscal year 2012 performance and vest in equal annual installments over a three-year period from the date of grant. The total value of the awards granted was approximately $0.4 million and the expense related to these awards will be recognized ratably over the three-year vesting period, plus any mark-to-market adjustments.

Coal Sales Contracts and Contingencies—As of December 31, 2012, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of 3.9 million, 2.5 million, 1.4 million, 1.1 million and 1.1 million tons of coal to 16 customers in 2013, 7 customers in 2014, 4 customer in 2015, 2 customers in 2016 and 2 customers in 2017, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Purchase Commitments—As of December 31, 2012, the Partnership had 1.0 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2013 for $3.3 million.

Purchased Coal Expenses—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts. In addition, the Partnership incurs expense from time to time related to coal purchased on the over-the-counter market ("OTC"). Purchase coal expense from coal purchase contracts and expense from OTC purchases for the years ended December 31, 2012, 2011 and 2010 was as follows:

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the years ended December 31, 2012, 2011 and 2010 was as follows:

Approximate future minimum lease and royalty payments (not including advance royalties already paid and recorded as assets in the accompanying statements of financial position) are as follows:

Environmental Matters—Based upon current knowledge, the Partnership believes that it is in compliance with environmental laws and regulations as currently promulgated. However, the exact nature of environmental control problems, if any, which the Partnership may encounter in the future cannot be predicted, primarily because of the increasing number, complexity and changing character of environmental requirements that may be enacted by federal and state authorities.

Legal Matters—The Partnership is involved in various legal proceedings arising in the ordinary course of business due to claims from various third parties, as well as potential citations and fines from the Mine Safety and Health Administration, potential claims from land or lease owners and potential property damage claims from third parties. The Partnership is not party to any other pending litigation that is probable to have a material adverse effect on the financial condition, results of operations or cash flows of the Partnership. Management of the Partnership is also not aware of any significant legal, regulatory or governmental proceedings against or contemplated to be brought against the Partnership.

Guarantees/Indemnifications and Financial Instruments with Off-Balance Sheet Risk —In the normal course of business, the Partnership is a party to certain guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. No liabilities related to these arrangements are reflected in the consolidated statements of financial position. The amount of bank letters of credit outstanding with PNC Bank, N.A., as the letter of credit issuer under the Partnership's credit facility, was $23.2 million as of December 31, 2012. The bank letters of credit outstanding reduce the borrowing capacity under the credit facility. In addition, the Partnership has outstanding surety bonds with third parties of $71.0 million as of December 31, 2012 to secure reclamation and other performance commitments.

The credit facility is fully and unconditionally, jointly and severally guaranteed by the Partnership and substantially all of its wholly owned subsidiaries. Borrowings under the credit facility are collateralized by the unsecured assets of the Partnership and substantially all of its wholly owned subsidiaries. See Note 10 for a more complete discussion of the Partnership's debt obligations.

Joint Venture—Pursuant to the joint venture agreement with Patriot, the Partnership is required to contribute additional capital to assist in funding the development and operations of the Rhino Eastern joint venture. During the year ended December 31, 2012, the Partnership did not make any capital contributions. The Partnership may be required to contribute additional capital or make loans to Rhino Eastern commensurate with its ownership percentage in subsequent periods.

The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012. The Partnership made an initial capital contribution of approximately $0.1 million during the year ended December 31, 2012 based upon its proportionate ownership interest.

The Partnership may contribute additional capital to the Muskie Proppants joint venture that was formed in the fourth quarter of 2012. The Partnership made an initial capital contribution of approximately $2.0 million during the year ended December 31, 2012 based upon its proportionate ownership interest.

The following table presents a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended December 31, 2012, 2011 and 2010:

The Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues or receivables:

The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership's senior secured credit facility was determined based upon a market approach and approximates the carrying value at December 31, 2012. The fair value of the Partnership's senior secured credit facility is a Level 2 measurement.

Other than the assets described in Note 6, the Partnership does not have any nonfinancial assets or nonfinancial liabilities measured at fair value.

Related Party	Description	2012			2011		2010

		(in thousands)
Wexford Capital LP	Expenses for legal, consulting, and advisory services	$	213		$	263	$	278
Wexford Capital LP	Distributions		27,704			38,602		—
Wexford Capital LP	Partner's contribution		13			1,450		—
Rhino Eastern LLC	Equity in net income of unconsolidated affiliate		6,023			3,338		4,699
Rhino Eastern LLC	Distributions from unconsolidated affiliate		2,958			3,351		—
Rhino Eastern LLC	Return of capital from unconsolidated affiliate		—			—		3,137
Rhino Eastern LLC	Expenses for legal, health claims, workers' compensation and other expenses		6,175			4,662		2,179
Rhino Eastern LLC	Receivable/(payable) for legal, health claims and workers' compensation and other expenses		(293	)		1,140		686
Rhino Eastern LLC	Investment in unconsolidated affiliate		21,802			18,736		18,749
Timber Wolf Terminals LLC	Investment in unconsolidated affiliate		114			—		—
Muskie Proppants LLC	Investment in unconsolidated affiliate		1,743			—		—
Muskie Proppants LLC	Equity in net (loss) of unconsolidated affiliate		(257	)		—		—

From time to time, employees from Wexford Capital perform legal, consulting, and advisory services to the Partnership. The Partnership incurred expenses of $0.2 million for the year ended December 31, 2012 and $0.3 million for each of the years ended December 31, 2011 and 2010 for legal, consulting, and advisory services performed by Wexford Capital.

During 2012, the Partnership provided loans to Rhino Eastern, a joint venture between the Partnership and Patriot, totaling approximately $11.9 million that were fully repaid as of December 31, 2012. During 2011, the Partnership provided loans based upon its ownership share to Rhino Eastern totaling approximately $5.8 million that were fully repaid as of December 31, 2011. During 2010, Rhino Eastern repaid an outstanding 10% fixed interest rate note receivable of $0.4 million to the Predecessor.

From time to time, the Partnership and Predecessor have allocated and paid expenses on behalf of the Rhino Eastern joint venture. During the years ended December 31, 2012, 2011 and 2010, the Partnership and Predecessor paid expenses for legal, health claims and workers' compensation of $6.2 million, $4.7 million and $2.2 million, respectively, on behalf of Rhino Eastern that were subsequently billed and paid by Rhino Eastern to the Partnership and Predecessor, as appropriate.

Cash payments for interest were $6.5 million, $4.3 million and $4.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The consolidated statement of cash flows for the year ended December 31, 2012 is exclusive of approximately $3.6 million of property, plant and equipment additions which are recorded in Accounts payable and $0.4 million related to the amount accrued for the acquisition of the western Kentucky assets discussed in Note 4, which is included in Accrued expenses and other. The consolidated statements of cash flows for the year ended December 31, 2012 also excludes approximately $0.7 million related to the value of LTIP units that were issued to certain employees and directors of the General Partner.

The consolidated statement of cash flows for the year ended December 31, 2011 is exclusive of approximately $3.2 million of property, plant and equipment additions which are recorded in accounts payable, approximately $5.2 million of property, plant and equipment additions which are included in accrued expenses and other liabilities and approximately $0.8 million related to the value of LTIP units that were issued to certain employees and directors of the General Partner.

In August 2010, the Partnership acquired certain assets of C.W. Mining Company for cash consideration of approximately $15.0 million. Because the fair value of the assets acquired was $25.8 million and exceeded the purchase price, the Partnership recorded a gain of $10.8 million and the consolidated statement of cash flows for the year ended December 31, 2010 is exclusive of $10.8 million of non-cash additions to property, plant and equipment. Additionally, the consolidated statement of cash flows for the year ended December 31, 2010 is exclusive of $0.9 million of non-cash additions to asset retirement obligations and mineral rights related to the C.W. Mining Company acquisition.

On October 5, 2010, 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. The consolidated statement of cash flows for the year ended December 31, 2010 is exclusive of the non-cash contribution of the membership interests in the Operating Company to the Partnership of $174.0 million and is also exclusive of the Partnership's issuance of the subordinated and common units to Rhino Energy Holdings LLC and the Partnership's issuance of incentive distribution rights to the General Partner.

The Partnership primarily produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah. The Partnership sells primarily to electric utilities in the United States. In addition, with the Elk Horn Acquisition mentioned earlier, the Partnership also leases coal reserves to third parties in exchange for royalty revenues. For the year ended December 31, 2012, the Partnership has four reportable business segments: Central Appalachia (comprised of both surface and underground mines located in Eastern Kentucky and Southern West Virginia, along with the Elk Horn operations), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Rhino Western (comprised of underground mines in Colorado and Utah) and Eastern Met (comprised solely of the Rhino Eastern joint venture with Patriot). Additionally, the Partnership has an Other category that is comprised of the Partnership's ancillary businesses and oil and natural gas investments. The Partnership has not provided disclosure of total expenditures by segment for long-lived assets, as the Partnership does not maintain discrete financial information concerning total segment expenditures for long lived assets, and accordingly such information is not provided to the Partnership's chief operating decision maker.

The Partnership has historically accounted for the Rhino Eastern joint venture (formed in the year ended December 31, 2008) under the equity method. Under the equity method of accounting, the Partnership has historically only presented limited information (net income). The Partnership considers this operation to comprise a separate operating segment and has presented additional operating detail (with corresponding eliminations and adjustments to reflect its percentage of ownership) below. Since

this equity method investment met the significance test of ten percent of net income in 2010 and 2012, the Partnership has presented additional summarized financial information for this equity method investment below.

During 2012, the Partnership changed the method to allocate certain corporate overhead and interest charges to its reportable segments from a method based on production tons to a method based upon the amount invested in fixed assets. The Partnership changed the allocation method as a result of additional investments that the Partnership has made in its non-coal operations. Reportable segment figures presented below have been re-cast for 2011 and 2010 for comparability purposes.

Reportable segment results of operations and financial position for the year ended December 31, 2012 are as follows (Note: "DD&A" refers to depreciation, depletion and amortization):

Reportable segment results of operations and financial position for the year ended December 31, 2011 are as follows:

Reportable segment results of operations and financial position for the year ended December 31, 2010 are as follows:

Additional summarized financial information for the equity method investment as of and for the periods ended December 31, 2012, 2011 and 2010 is as follows:

Additional information on the Partnership's revenue by product category for the periods ended December 31, 2012, 2011 and 2010 is as follows:

21. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

The following is revenue and cost information relating to the Partnership's proportionate share of oil and natural gas operations located entirely in the Utica Shale region of the United States:

The following schedule sets forth the Partnership's proportionate share revenues and expenses related to the production and sale of oil and natural gas.

(in thousands, except per unit data)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter

2012:
Revenues	$	81,882	$	89,998	$	93,575	$	86,536
Income from operations		8,688		12,599		9,151		11,693
Net income	$	8,974	$	12,996	$	8,876	$	9,376
Basic and diluted net income per limited partner unit:
Common units	$	0.32	$	0.46	$	0.31	$	0.33
Subordinated units	$	0.32	$	0.46	$	0.31	$	0.33
Weighted average number of limited partner units outstanding, basic:
Common units		15,313		15,329		15,332		15,348
Subordinated units		12,397		12,397		12,397		12,397
Weighted average number of limited partner units outstanding, diluted:
Common units		15,327		15,331		15,333		15,349
Subordinated units		12,397		12,397		12,397		12,397

(in thousands, except per unit data)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter

2011:
Revenues	$	82,755	$	89,877	$	93,564	$	101,026
Income from operations		6,494		9,506		10,424		14,319
Net income	$	6,136	$	9,377	$	9,846	$	12,712
Basic and diluted net income per limited partner unit:
Common units	$	0.24	$	0.37	$	0.36	$	0.45
Subordinated units	$	0.24	$	0.37	$	0.36	$	0.45
Weighted average number of limited partner units outstanding, basic:
Common units		12,402		12,416		14,732		15,309
Subordinated units		12,397		12,397		12,397		12,397
Weighted average number of limited partner units outstanding, diluted:
Common units		12,431		12,434		14,747		15,320
Subordinated units		12,397		12,397		12,397		12,397


ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to


Delaware (State or other jurisdiction of incorporation or organization)		27-2377517 (I.R.S. Employer Identification No.)
424 Lewis Hargett Circle, Suite 250 Lexington, KY (Address of principal executive offices)		40503 (Zip Code)

Title of each class		Name of each exchange on which registered

Common Units representing Limited Partner Interests		New York Stock Exchange


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

	For the year ended December 31, 2012

	Oil/Condensate (Mbbls)		Natural gas liquids (Mbbls)		Natural gas (MMcf)		Total oil and natural gas reserves (MBOE)
Proved developed		60		4		1,532		319
Proved undeveloped(1)		61		7		896		217

Total estimated proved reserves(2)		121		11		2,428		536


PART I
Item 1.	Business	1
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	57
Item 2.	Properties	57
Item 3.	Legal Proceedings	64
Item 4.	Mine Safety Disclosure	64
PART II
Item 5.	Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	65
Item 6.	Selected Financial Data	68
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	72
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	106
Item 8.	Financial Statements and Supplementary Data	107
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	107
Item 9A.	Controls and Procedures	107
Item 9B.	Other Information	110
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	111
Item 11.	Executive Compensation	117
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	131
Item 13.	Certain Relationships and Related Transactions, and Director Independence	133
Item 14.	Principal Accounting Fees and Services	136
PART IV
Item 15.	Exhibits, Financial Statement Schedules	137
FINANCIAL STATEMENTS
	Index to Financial Statements	F-1

	Non-Reserve Coal Deposits

			Total Tons
	Total Tons		Total Tons
Region	Total Tons		Owned			Leased
	(in million tons)
Central Appalachia		177.4		166.2			11.2
Northern Appalachia		30.8		25.8			5.0
Illinois Basin		33.5		—			33.5
Western Bituminous		175.7		—			175.7

Total		417.4		192.0			225.4

Percentage of total				46.00	%		54.00	%
Rhino Eastern (Central Appalachia)(1)		17.9		—			17.9

	Price Range

	Price Range				Cash Distribution(1)
	High		Low		Cash Distribution(1)
Year ended December 31, 2012
Fourth Quarter	$	17.41	$	12.11	$	0.445
Third Quarter	$	16.19	$	13.01	$	0.445
Second Quarter	$	19.17	$	12.61	$	0.445
First Quarter	$	22.26	$	17.91	$	0.480
Year ended December 31, 2011
Fourth Quarter	$	22.68	$	15.02	$	0.480
Third Quarter	$	28.23	$	17.05	$	0.480
Second Quarter	$	26.43	$	21.55	$	0.455
First Quarter	$	27.31	$	22.78	$	0.455

	Marginal Percentage Interest in Distributions

Total Quarterly Distribution Target Amount	Unitholders			General Partner
Above $0.51175 up to $0.55625		85.0	%		15.0	%
Above $0.55625 up to $0.6675		75.0	%		25.0	%
Above $0.6675		50.0	%		50.0	%

Segment	Year Ended December 31, 2012

	(in thousands, except %)
Central Appalachia		1,756.1	2,308.0	(551.9	)	(23.9	)%
Northern Appalachia		1,875.1	2,061.5	(186.4	)	(9.0	)%
Rhino Western		1,038.9	506.6	532.3		105.1	%

Total*†		4,670.1	4,876.1	(206.0	)	(4.2	)%

Segment	Year ended December 31, 2012			Year ended December 31, 2011			Increase (Decrease)

	(in millions)
Central Appalachia	$	4.3		$	16.9		$	(12.6	)
Northern Appalachia		29.6			27.4			2.2
Rhino Western		5.7			(2.6	)		8.3
Eastern Met*		6.0			3.3			2.7
Other		(5.4	)		(6.9	)		1.5

Total	$	40.2		$	38.1		$	2.1

Segment	Year ended December 31, 2012			Year ended December 31, 2011			Increase (Decrease)

	(in millions)
Central Appalachia	$	35.0		$	42.0		$	(7.0	)
Northern Appalachia		38.7			36.3			2.4
Rhino Western		11.1			1.0			10.1
Eastern Met*		7.1			4.9			2.2
Other		(1.4	)		(2.2	)		0.8

Total Adjusted EBITDA	$	90.5		$	82.0		$	8.5

	Payments Due by Period

	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		More than 5 Years
	(in thousands)
Long-term debt obligations (including interest)(1)		163,549	$	2,350	$	1,234	$	157,715	$	2,250
Asset retirement obligations		33,003		2,255		8,038		3,104		19,606
Operating lease obligations(2)		1,029		895		134		—		—
Diesel fuel obligations		3,284		3,284		—		—		—
Ammonia nitrate obligations		2,527		2,527		—		—		—
Advance royalties(3)		17,050		1,733		3,503		3,379		8,435
Retiree medical obligations		6,510		227		723		1,191		4,369

Total	$	226,952	$	13,271	$	13,632	$	165,389	$	34,660

Name and Principal Position	Base Salary		Bonus

David G. Zatezalo	$	520,000	0% to 150% of base salary
President and Chief Executive Officer
Richard A. Boone	$	295,000	0% to 75% of base salary
Senior Vice President and Chief Financial Officer
Christopher I. Walton	$	300,000	0% to 40% of base salary
Senior Vice President and Chief Operating Officer
Andrew W. Cox	$	220,000	0% to 40% of base salary
Vice President of Sales
Reford C. Hunt	$	235,000	0% to 40% of base salary
Vice President of Technical Services

Name	Automobile Use		Employer Contribution to Rhino 401(k) Plan		Employer Contribution to the Hopedale 401(k) Plan

David G. Zatezalo	$	277	$	—	$	15,000
Richard A. Boone		2,356		10,000		—
Christopher I. Walton		1,942		10,000		—
Andrew W. Cox		919		10,000		—
Reford C. Hunt		3,119		10,000		—

Name		Value of Units Granted ($)(1)

David G. Zatezalo	—	$	—
Richard A. Boone	3,045	$	55,998
Christopher I. Walton	1,196	$	21,994
Andrew W. Cox	1,305	$	23,999
Reford C. Hunt	1,414	$	26,003

	Unit Awards

Name	Number of Units That Have Not Vested (#)(1)		Market Value of Units That Have Not Vested ($)(2)
David G. Zatezalo		24,391	$	333,181
Richard A. Boone		11,175	$	152,651
Christopher I. Walton		1,604	$	21,911
Andrew W. Cox		1,713	$	23,400
Reford C. Hunt		1,822	$	24,889

	Unit Awards

Name	Number of Units Acquired Upon Vesting (#)		Value of Units Realized Upon Vesting ($)(1)
David G. Zatezalo		24,390	$	409,020
Richard A. Boone		8,130	$	136,340
Christopher I. Walton		406	$	6,809
Andrew W. Cox		406	$	6,809
Reford C. Hunt		406	$	6,809

Name	Fees Earned or Paid in Cash ($)(1)		Unit Awards ($)(2)		All Other Compensation ($)		Total ($)

Mark D. Zand(3)	$	30,000	$	25,008	$	—	$	55,008
Arthur H. Amron(3)	$	20,000	$	25,008	$	—	$	45,008
Joseph M. Jacobs(3)	$	20,000	$	25,008	$	—	$	45,008
Douglas Lambert(4)	$	40,000	$	25,008	$	—	$	65,008
Jay L. Maymudes(3)	$	25,000	$	25,008	$	—	$	50,008
Mark L. Plaumann(4)	$	50,000	$	25,008	$	—	$	75,008
Kenneth A. Rubin(3)	$	20,000	$	25,008	$	—	$	45,008
James F. Tompkins	$	40,000	$	25,008	$	—	$	65,008

Plan Category	Number of units to be issued upon exercise/vesting of outstanding options, warrants and rights as of December 31, 2012		Weighted-average exercise price of outstanding options, warrants and rights			Number of units remaining available for future issuance under equity compensation plans as of December 31, 2012 (excluding units reflected in column (a))

	(a)		(b)			(c)
Equity compensation plans not approved by unitholders(1):
Long-Term Incentive Plan		57,852		n/a	(2)		2,328,957

	2012		2011

	(in thousands)
Audit Fees(1)	$	945	$	960
Tax Fees(2)		—		10

Total	$	945	$	970

		Description

31.2	*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
32.1	*	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
32.2	*	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
95.1	*	Mine Health and Safety Disclosure pursuant to §1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act for the year ended December 31, 2012 and the three months ended December 31, 2012
99.1	*	Report of Ryder Scott Company, LP
101.INS	§	XBRL Instance Document
101.SCH	§	XBRL Taxonomy Extension Schema Document
101.CAL	§	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	§	XBRL Taxonomy Definition Linkbase Document
101.LAB	§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	§	XBRL Taxonomy Extension Presentation Linkbase Document


		RHINO RESOURCE PARTNERS LP
		By:		Rhino GP LLC, its general partner
		By:		/s/ DAVID G. ZATEZALO David G. Zatezalo President, Chief Executive Officer and Director

Signature	Title	Date


/s/ DAVID G. ZATEZALO David G. Zatezalo	President, Chief Executive Officer and Director (Principal Executive Officer)	March 8, 2013
/s/ RICHARD A. BOONE Richard A. Boone	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 8, 2013
/s/ MARK D. ZAND Mark D. Zand	Director	March 8, 2013
/s/ ARTHUR H. AMRON Arthur H. Amron	Director	March 8, 2013
/s/ JAY L. MAYMUDES Jay L. Maymudes	Director	March 8, 2013
/s/ KENNETH A. RUBIN Kenneth A. Rubin	Director	March 8, 2013

Signature	Title	Date


/s/ JOSEPH M. JACOBS Joseph M. Jacobs	Director	March 8, 2013
/s/ MARK L. PLAUMANN Mark L. Plaumann	Director	March 8, 2013
/s/ DOUGLAS LAMBERT Douglas Lambert	Director	March 8, 2013
/s/ JAMES F. TOMPKINS James F. Tompkins	Director	March 8, 2013

RHINO RESOURCE PARTNERS LP

Report of Independent Registered Public Accounting Firm			F-2
Consolidated Statements of Financial Position as of December 31, 2012 and 2011			F-3
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2012, 2011, and 2010			F-4
Consolidated Statements of Members' Equity/Partners' Capital for the Years Ended December 31, 2012, 2011 and 2010			F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010			F-6
Notes to Consolidated Financial Statements			F-7

	Members' Investment			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Members' Equity

BALANCE—January 1, 2010	$	22,907		$	114,016		$	1,478		$	138,401
Net income prior to initial public offering		—			35,703			—			35,703
Change in actuarial gain under ASC Topic 815		—			—			(113	)		(113	)
Contribution to successor		(22,907	)		(149,719	)		(1,365	)		(173,991	)

BALANCE—October 5, 2010	$	—		$	—		$	—		$	—

	(in thousands)

Mining and other equipment & related facilities	$	8,689
Asset retirement costs		933
Coal properties		17,100
Asset retirement obligation liability assumed		(933	)

Net assets acquired		25,789
Gain on bargain purchase		(10,789	)

Total consideration	$	15,000

		December 31,

	Useful Lives	2012			2011
		(in thousands)
Land and land improvements		$	34,978		$	33,298
Mining and other equipment and related facilities	2 - 20 Years		297,615			244,819
Mine development costs	1 - 15 Years		67,045			65,824
Coal properties and oil and natural gas properties(1)	1 - 15 Years		278,088			266,319
Construction work in process			5,943			27,303

Total			683,669			637,563
Less accumulated depreciation, depletion and amortization			(219,709	)		(187,447	)

Net		$	463,960		$	450,116

Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount

	(in thousands)
Patent	$	728	$	164	$	564
Developed Technology		78		18		60
Trade Name		184		14		170
Customer List		470		36		434

Total	$	1,460	$	232	$	1,228

	Patent		Developed Technology		Trade Name		Customer List		Total

	(in thousands)
2013	$	43	$	5	$	9	$	23	$	80
2014		43		5		9		23		80
2015		43		5		9		23		80
2016		43		5		9		23		80
2017		43		5		9		23		80

	in thousands

2013	$	2,414
2014		1,049
2015		210
2016		157,475
2017		241
Thereafter		2,249

Total principal payments		163,638
Less imputed interest on interest free notes payable		(89	)

Total debt	$	163,549

	December 31,

	2012			2011
*Weighted Average assumptions used to determine benefit obligations:*
Discount rate		2.80	%		4.15	%
Expected return on plan assets		n/a			n/a

	One-Percentage Point Increase		One-Percentage Point Decrease

	(in thousands)
Effect on total service and interest cost components	$	64	$	(57	)
Effect on postretirement benefit obligation	$	595	$	(546	)

	Common Units			Weighted Average Grant Date Fair Value (per unit)

	(in thousands)
Non-vested awards at December 31, 2010		135		$	20.50
Granted		10		$	19.90
Vested		(52	)	$	20.47
Forfeited		(1	)	$	20.50

Non-vested awards at December 31, 2011		92		$	20.45
Granted		32		$	17.40
Vested		(49	)	$	20.12
Forfeited		(8	)	$	20.28

Non-vested awards at December 31, 2012		67		$	19.23