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 30, 2014, 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 $132.0 million based on the closing price of the registrant's common units on the New York Stock Exchange on such date. As of March 6, 2015, the registrant had 16,696,398 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



PART I
Item 1.	Business	1
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	56
Item 2.	Properties	56
Item 3.	Legal Proceedings	59
Item 4.	Mine Safety Disclosure	59
PART II
Item 5.	Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	60
Item 6.	Selected Financial Data	63
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	67
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	109
Item 8.	Financial Statements and Supplementary Data	110
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	110
Item 9A.	Controls and Procedures	110
Item 9B.	Other Information	113
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	113
Item 11.	Executive Compensation	118
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	133
Item 13.	Certain Relationships and Related Transactions, and Director Independence	135
Item 14.	Principal Accounting Fees and Services	138
PART IV
Item 15.	Exhibits, Financial Statement Schedules	138
FINANCIAL STATEMENTS
	Index to Financial Statements	F-1

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

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

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

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

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

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

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

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

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, or "met", 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 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.

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.

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.

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 and energy related assets and activities, including energy infrastructure investments. 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 Cana Woodford region of western Oklahoma. 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. We have also invested in joint ventures 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 Cana Woodford region of western Oklahoma. As of December 31, 2014, we controlled an estimated 480.0 million tons of proven and probable coal reserves, consisting of an estimated 425.1 million tons of steam coal and an estimated 54.9 million tons of metallurgical coal. In addition, as of December 31, 2014, we controlled an estimated 290.0 million tons of non-reserve coal deposits. As discussed further below, Rhino Eastern LLC, a joint venture in which we had a 51% membership interest and for which we served as manager, was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above since the joint venture and its operations were effectively dissolved as of December 31, 2014. Our oil and natural gas investments as of December 31, 2014 also consisted of approximately 1,900 net mineral acres that we own in the Cana Woodford region.

As of December 31, 2014, we operated nine mines, including four underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. 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.

Due to the prolonged weakness in the U.S. coal markets and the dim prospects for an upturn in the coal markets in the near term, in the fourth quarter of 2014, we performed a comprehensive review of our current coal mining operations as well as potential future development projects to ascertain whether any of our investments were no longer recoverable. We identified various properties, projects and operations that were potentially impaired based upon changes in our strategic plans, market conditions or other factors. We recorded approximately $45.3 million of asset impairment and related charges for the year ended December 31, 2014. We also recorded an additional $5.9 million impairment

charge as of December 31, 2014 related to the January 2015 dissolution of our Rhino Eastern joint venture that is discussed further below. Please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", for a detailed discussion of these asset impairment and related charges.

In January 2015, we completed a Membership Transfer Agreement (the "Transfer Agreement") with an affiliate of Patriot Coal Corporation ("Patriot") that terminated the Rhino Eastern joint venture. Pursuant to the Transfer Agreement, Patriot sold and assigned its 49% membership interest in the Rhino Eastern joint venture to us and, in consideration of this transfer, Patriot received certain fixed assets, leased equipment and coal reserves associated with the mining area previously operated by the Rhino Eastern joint venture. Patriot also assumed substantially all of the active workforce related to the Eagle mining area that was previously employed by the Rhino Eastern joint venture. We retained approximately 34 million tons of coal reserves that are not related to the Eagle mining area as well as a prepaid advanced royalty balance of $6.3 million. As part of the closing of the Transfer Agreement, we and Patriot agreed to a dissolution payment based upon a final working capital adjustment calculation as defined in the Transfer Agreement.

Excluding results from the Rhino Eastern joint venture, for the year ended December 31, 2014, we produced approximately 3.4 million tons of coal, purchased approximately 0.1 million tons of coal and sold approximately 3.6 million tons of coal. Additionally, the Rhino Eastern joint venture produced and sold approximately 0.2 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2014. Lessees produced approximately 2.9 million tons of coal from our Elk Horn coal leasing properties in eastern Kentucky for the year ended December 31, 2014. We also received royalty revenue from hydrocarbons sold from our Cana Woodford investment for the year ended December 31, 2014. Please see Note 21 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 potentially diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. We believe that such assets will enhance the stability of 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 approximately $3.5 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 $357.5 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.

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 May 2012, we completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky. These coal leases and property are estimated to contain approximately 32.4 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is fully permitted and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers. During 2014, we completed the initial construction of a new underground mining operation on this property. Production began in late May 2014 and the first barge shipments of coal departed from this facility in early July 2014. We have a long-term sales contract with an electric utility anchor customer and we have conducted many test shipments to potential customers that we believe could lead to additional long-term sales agreements. 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, 2013, we had invested a total of approximately $31.1 million for a 5% net interest in a portfolio of oil and natural gas leases in the Utica Shale region along with approximately $23.3 million in drilling costs, which represented our proportionate ownership share in the portfolio. Gulfport, the operator of the portfolio, began drilling and testing wells in the region in 2012 and we received our proportionate share (5%) of revenue from the hydrocarbons produced and sold by the operator on our acreage, which totaled approximately $5.6 million for the year ended December 31, 2013. In March 2014, we completed a purchase and sale agreement to sell our entire Utica Shale joint interest investment to Gulfport for approximately $184.0 million, which has significantly reduced our debt and enhanced our financial flexibility. In addition, as of December 31, 2014, we have invested approximately $8.1 million for mineral rights in the Cana Woodford region.

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, 2014, we operated three mining complexes located in Central Appalachia (Tug River, Rob Fork and Deane) 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). We also had one underground mine located in the Western Bituminous region in Colorado (McClane Canyon) that was permanently idled at the end of 2013 (see Note 6 of the consolidated financial statements included elsewhere in this annual report for further information). During 2014, we developed a new mining complex in the Illinois Basin, our Riveredge mine at our Pennyrile mining complex, which began production in mid-2014. The Pennyrile complex consists of one underground mine, a preparation plant and river loadout facility.

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 seven active preparation plants and/or loadouts, 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, 2014 (Note: the McClane Canyon mine in Colorado was permanently idled at December 31, 2013):

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, 2014. 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, 2014(3)

				(in million tons)
Central Appalachia
Tug River Complex (KY, WV)	Tug Fork & Jamboree(4)	Truck, Barge, Rail (NS)	2S		0.5
Rob Fork Complex (KY)	Rob Fork	Truck, Barge, Rail (CSX)	1U, 1S		0.4
Deane Complex (KY)	Rapid Loader	Rail (CSX)	—		0.2
Northern Appalachia
Hopedale Complex (OH)	Nelms	Truck, Rail (OHC, WLE)	1U		0.8
Sands Hill Complex (OH)	Sands Hill(5)	Truck, Barge	2S		0.2
Illinois Basin
Taylorville Field (IL)	n/a	Rail (NS)	—		—
Pennyrile Complex (KY)(6)	Preparation plant & river loadout	Barge	1U		0.2
Western Bituminous
Castle Valley Complex (UT)	Truck loadout	Truck	1U		1.1
McClane Canyon Mine (CO)(6)	n/a	Truck	—		—

Total			4U,5S		3.4



Central Appalachia
Rhino Eastern Complex (WV)(7)	Rocklick	Truck, Rail (NS, CSX)	1U		0.2

Central Appalachia. As of December 31, 2014, we operated three mining complexes located in Central Appalachia consisting of one active underground mine and three surface mines. For the year ended December 31, 2014, the mines at our Tug River, Rob Fork and Deane mining complexes produced an aggregate of approximately 0.8 million tons of steam coal and an estimated 0.3 million tons of metallurgical coal. The underground mine at the Rhino Eastern mining complex, which was previously owned by the Rhino Eastern joint venture in which we had a 51% membership interest and for which we served as manager, produced approximately 0.2 million tons of metallurgical coal. The Rhino Eastern joint venture was dissolved in January 2015. In addition, for the year ended December 31, 2014, lessees of our Elk Horn properties produced approximately 2.9 million tons of coal.

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 Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail loadout for blending and shipping. Coal suitable for direct-ship to customers is delivered by truck directly to the Jamboree rail loadout from the mine sites. 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 0.3 million tons of steam coal and approximately 0.2 million tons of metallurgical coal for the year ended December 31, 2014.

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 0.3 million tons of steam coal and 0.1 million tons of metallurgical coal for the year ended December 31, 2014.

Deane Mining Complex. Our Deane mining complex is located in eastern Kentucky and produced steam coal from one company-operated underground mine that was idle as of December 31, 2014. 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, 2014.

Rhino Eastern Mining Complex. The Rhino Eastern mining complex was previously owned through a joint venture where we had a 51% membership interest in, and served as manager for the mining complex located in Raleigh and Wyoming Counties, West Virginia. The joint venture was dissolved in January 2015 and an affiliate of Patriot, our previous joint venture partner, assumed ownership and operation of the mining operations.

The Rhino Eastern mining complex produced approximately 0.2 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2014.

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, 2014, Elk Horn lessees produced approximately 2.9 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, 2014, these mines produced an aggregate of approximately 1.0 million tons of steam coal.

Hopedale Mining Complex. The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to our customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 0.8 million tons of steam coal for the year ended December 31, 2014.

Sands Hill Mining Complex. We currently 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 0.2 million tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2014.

Western Bituminous Region. In January 2011, we began production at an underground mine in Emery and Carbon Counties, Utah. We also had one underground mine located in the Western Bituminous region in Colorado (McClane Canyon) that was permanently idled at the end of 2013 (see Note 6 of the consolidated financial statements included elsewhere in this annual report for further information).

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 1.1 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2014.

Illinois Basin. In May 2012, we completed the purchase of certain rights to coal leases and surface property that is contiguous to the Green River and located in Daviess and McLean counties in western Kentucky where we constructed a new underground mining complex.

Pennyrile Mining Complex. In mid-2014, we completed the initial construction of a new underground mining operation on the purchased property, referred to as our Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. Production from this new underground mine began in mid-2014 and initial production was 0.2 million tons for the year ended December 31, 2014. We believe the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex.

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.

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.

In 2011 we began to invest in oil and natural gas mineral rights and operations in the Utica Shale region of eastern Ohio. As of December 31, 2013, we had invested a total of approximately $31.1 million for a 5% net interest in a portfolio of oil and natural gas leases in the Utica Shale region along with approximately $23.3 million in drilling costs, which represented our proportionate ownership share in the portfolio. Gulfport, the operator of the portfolio, began drilling and testing wells in the region in 2012 and we received our proportionate share (5%) of revenue from the hydrocarbons produced and sold by the operator on our acreage, which totaled approximately $5.6 million for the year ended December 31, 2013. In March 2014, we completed a purchase and sale agreement to sell our entire Utica Shale joint interest investment to Gulfport for approximately $184.0 million, which provided us a substantial return on our initial investment.

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 $149,000 and $115,000 in royalty revenue during 2014 and 2013, respectively.

In September 2014, we made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC ("Sturgeon"), with affiliates of Wexford Capital and Gulfport. Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. We account for the investment in this joint venture and results of operations under the equity method. We recorded our proportionate portion of the operating gains for this investment during 2014 of approximately $0.4 million.

In December 2012, we made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant 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 share of the operating loss for 2014 and 2013 of approximately $0.1 million and $0.5 million, respectively. During the year ended December 31, 2014 and 2013, we contributed additional capital based upon our ownership interest to the Muskie joint venture in the amount of $0.2 million and $0.5 million, respectively. In addition, during the year ended December 31, 2013, we provided a loan based upon our ownership share to Muskie in the amount of $0.2 million, which was fully repaid in November 2014 in conjunction with our contribution of our interest in Muskie to Mammoth Energy Partners LP ("Mammoth"). In November 2014, we contributed our investment interest in Muskie to Mammoth in return for a limited partner interest in Mammoth. Mammoth was formed to own various companies that provide services to companies who engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth's companies provide services that include completion and production services, contract land and directional drilling services and remote accommodation services.

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 has completed the construction of numerous drill pads since its inception, along with the construction of impoundments for fracking water and the construction of several access roads for operators in the Utica Shale region.

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 interest to purchase land for the construction site of the condensate river terminal. Timber Wolf has had no operating activities since its inception.

In March 2012, we completed a lease agreement with a third party for approximately 1,232 acres that we own 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. 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 April 2013, we completed an agreement with a third party to sell the 20% royalty interest for approximately $10.5 million on the 1,232 acres in the Utica Shale. The sale of the royalty interest resulted in a gain of approximately $10.5 million since we had no cost basis associated with the royalty interest.

In September 2013, we completed an agreement with a third party to sell the oil and natural gas mineral rights for approximately 57 acres we own in the Utica Shale region in Harrison County, Ohio for approximately $0.6 million. The sale of this acreage resulted in a gain of approximately $0.6 million since we had no cost basis associated with this 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, 2014, approximately 91% of our coal sales tons consisted of steam coal and approximately 9% consisted of metallurgical coal. For the year ended December 31, 2014, 100% of the Rhino Eastern joint venture's coal sales tons consisted of metallurgical coal. For the year ended December 31, 2014, excluding results from the Rhino Eastern joint venture, approximately 81% 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, 2014, we derived approximately 81.0% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 39.2% of our coal revenues for that period: NRG Energy, Inc. (fka GenOn Energy, Inc.) (15.6%); PPL Corporation (12.1%); and Intermountain Power Agency (11.5%). Additionally, pursuant to the terms of a coal purchase agreement entered into under the previous

Rhino Eastern joint venture agreement, we sold 100% of Rhino Eastern's production to an affiliate of our joint venture partner, Patriot, which controlled the amount and terms of sales of the coal produced from Rhino Eastern. As discussed earlier, the Rhino Eastern joint venture was dissolved in January 2015. 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 each of the years ended December 31, 2014 and 2013, approximately 78% and 88%, 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, 2014, we had commitments under supply contracts to deliver annually scheduled base quantities as follows:

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, 2014, 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. For our new Pennyrile complex in western Kentucky, coal is transported to our customers via barge from our river loadout on the Green River located on our Pennyrile mining complex. In addition, coal from certain of our Central Appalachia and southern Ohio 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., Murray Energy Corporation, Foresight Energy LP, Westmoreland Resource Partners, LP, Patriot and Bowie Resource Partners LLC.

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, 2014 was 1.63 as compared to the most recent national average of 2.42, as reported by MSHA, or 32.76% 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, 2014 our average MSHA violations per inspection day was 0.46 as compared to the most recent national average of 0.62 violations per inspection day for coal mining activity as reported by MSHA, or 25.80% 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, in 2013, MSHA began implementing its recently released Pattern of Violation ("POV") regulations under the Mine Act. Under this regulation, MSHA eliminated 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, 2014 (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 January 1, 1970. 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 2014, we recorded approximately $3.0 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, 2014, we had accrued approximately $29.9 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, a February 2014 decision by the U.S. District Court for the District of Columbia invalidated the Office of Surface Mining Reclamation and Enforcement's ("OSM") 2008 Stream Buffer Zone Rule, which prohibited mining disturbances within 100 feet of streams, subject to various exemptions. In December 2014, OSM reinstated the 1983 version of the Stream Buffer Zone regulations, which offer fewer exemptions to the 100 foot buffer requirement, as a direct final rule. In 2009, OSM published an advance notice of proposed rulemaking to revise the Stream Buffer Zone Rule through a more protective regulatory strategy called the Stream Protection Rule, which would prohibit mining disturbances within 100 feet of streams if there would be a negative effect on water quality. The Stream Protection Rule has not yet been proposed or finalized. OSM is currently developing an environmental impact statement ("EIS") for use in drafting the anticipated Stream Protection Rule. A notice of proposed rulemaking for the Stream Protection Rule is expected to be issued in April 2015. 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 Stream Buffer Zone 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, 2014, we had approximately $70.2 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 greenhouse gas ("GHG") 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.

Non-government organizations have also petitioned EPA to regulate coal mines as stationary sources under the Clean Air Act. On May 13, 2014, the D.C. Circuit in WildEarth Guardians v. United States Environmental Protection Agency upheld EPA's denial of one such petition. On July 18, 2014, the D.C. Circuit denied a petition to rehear that case en banc. If such efforts 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 EPA also recently proposed new source performance standards for GHG for new coal and oil-fired power plants, which could require partial carbon capture and sequestration to comply. In addition, in October 2013, the U.S. Supreme Court granted certiorari to hear arguments related to a combination of several petitions challenging EPA's approach to CO2 regulation. In addition, passage of any comprehensive federal 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 include:

All of these regulations are subject to legal challenges, but the D.C. Circuit has generally 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. In March 2012, the EPA proposed New Source Performance Standards ("NSPS") for carbon dioxide emissions from new and modified EGUs. EPA revised its proposal in September 2013, and intends to finalize the rule in mid-summer 2015. 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.

Additionally, in June 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. The plan sets a national carbon pollution standard that is projected to cut emissions produced by United States power plants by 2030, by 30% from 2005 levels. Although states can choose to rely on the four measures set by the EPA to meet this goal, the states themselves will ultimately decide the means to use. States can develop individual plans, or they can collaborate with other states. These measures states may employ include: renewable energy standards, efficiency improvements at plants, switching to natural gas, transmission efficiency improvements, energy storage technology, expanding renewables or nuclear, and energy conservation programs. Under the proposed rule, states will have until June 2016 to submit final plans, although extensions may be allotted if needed. The final rule is expected to be issued by mid-summer 2015 and the emission reductions are scheduled to commence in 2020. An Ohio-based coal company has already filed a legal challenge to the proposed rulemaking in the D.C. Circuit, and nine states have joined as amici.

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. The EPA also recently proposed new source performance standards for GHG for new coal and oil-fired power plants, which could require partial carbon capture and sequestration to comply. 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 was appealed and reversed by the D.C. Circuit Court of Appeals in April 2013, finding that EPA has the authority to issue a retroactive veto, but remanding for consideration of whether that decision was arbitrary and capricious. The mining company has also petitioned the U.S. Supreme Court

for certiorari to overturn the ruling. The Supreme Court denied certiorari in March 2014. 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 anti-degradation review before approving discharge permits. The adoption of new TMDLs and load allocations or any changes to anti-degradation 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.

Moreover, in April 2014, EPA proposed changes to its definition of "waters of the United States." Because the content of EPA's final rule, if any, is unknown, we cannot assess the potential impact of the EPA's proposal on our operations. However, any expansion to Clean Water Act jurisdiction could impose additional permitting obligations on our operations, which may adversely impact our coal production or results of operations.

In May 2014, EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power plants. These requirements could increase our customers' costs and cause them to reduce their demand for coal, which may materially impact our results or operations.

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.

In June 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 called 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 called 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. In December 2014, EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rule also requires fugitive dust controls and imposes various monitoring, cleanup, and closure requirements. The rule leaves intact the Bevill exemption for beneficial uses of CCB, though it defers a final Bevill regulatory determination with respect to CCB that is disposed of in landfills or surface impoundments. The costs of complying with these new requirements may result in a material adverse effect on our business, financial condition or results of operations, and could potentially increase our customers' operating costs, thereby reducing their ability to purchase coal as a result. 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.

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.

In January 2015, OSM announced that it intends to pursue a rulemaking to address clouds of nitrogen oxide associated with blasting operations pursuant to a petition by a nongovernmental organization. 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 our blasting 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.

To carry out our operations, our general partner and our subsidiaries, excluding our Rhino Eastern joint venture, employed 715 full-time employees as of December 31, 2014. 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 $13.2 million per quarter, or $52.8 million per year, based on the number of common and subordinated units outstanding as of December 31, 2014 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:

We may reduce or eliminate distributions at any time we determine that our cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs. In October 2014, we reduced our quarterly distribution to $0.05 per common unit due to insufficient distributable cash generated from our operations. Thus, we have arrearages accumulating on our common units since the distribution level has been below our minimum quarterly level of $0.445 per unit. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. We may not have sufficient cash available for distributions on our common or subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay any quarterly distribution on our common units. Moreover, we may not be able to increase distributions on our common units if we are unable to pay the accumulated arrearages on our common units as well as 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. Prices for coal tend to be cyclical; however, prices have become more volatile and depressed as a result of oversupply in the marketplace. 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.

In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. A decline in the price of natural gas has made natural gas more competitive against coal and resulted in utilities switching from coal to natural gas. Sustained low natural gas prices may also cause utilities to phase out or close existing coal-fired power plants or reduce or eliminate construction of any new coal-fired power plants, which could have a material adverse effect on demand

and prices received for our coal. 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 Cana Woodford region. Significant or extended price declines could also adversely affect the amount of oil and natural gas that 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 our 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 91% of our coal sales volume for the year ended December 31, 2014. 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, sustained 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 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.

For example, MSHA recently finalized a new rule limiting miners' exposure to respirable coal dust. The first phase of the rule went into effect in August 2014, and requires, among other things, single shift sampling to determine noncompliance and corrective action to remedy any excessive levels of dust. The next phase of the rule takes effect in February 2016, and requires increased sampling frequency and the use of continuous personal dust monitors. This and other future mine safety rules could potentially result in or require significant expenditures, as well as additional safety training and planning, enhanced safety equipment, more frequent mine inspections, stricter enforcement practices and enhanced reporting requirements.

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 and those of our competitors 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 alleged 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 any advance notice of inspections in the future. That became a Permanent Injunction on July 14, 2011. The Permanent Injunction is for three years and expired on July 14, 2014. On June 17, 2011, MSHA also issued a 104(a) citation in this matter to the Mine for allegedly giving advance notice of the inspection. The citation was assessed at $10,000 and was settled for $8,000 in 2014 upon approval by the administrative law judge.

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. During periods of high demand for coal, the coal industry has experienced 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 a shortage of experienced labor should occur 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.

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 million to $13 million for 2015. 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 state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA.

For example, in June 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. The plan sets a national carbon pollution standard that is projected to cut emissions produced by United States power plants by 2030, by 30% from 2005 levels. Although states can choose to rely on the four measures set by the EPA to meet this goal, the states themselves will ultimately decide the means to use. States can develop individual plans, or they can collaborate with other states. These measures states may employ include: renewable energy standards, efficiency improvements at plants, switching to natural gas, transmission efficiency improvements, energy storage technology, and expanding renewables or nuclear, and energy conservation programs. Under the proposed rule, states will have until June 2016 to submit final plans, although extensions may be allotted if needed. The final rule is expected to be issued by mid-summer 2015 and the emission reductions are scheduled to commence in 2020. An Ohio-based coal company has already filed a legal challenge to the proposed rulemaking in the D.C. Circuit, and nine states have joined as amici.

In the meantime, the EPA and other regulators are using existing laws, including the federal Clean Air Act,to limit emissions of carbon dioxide and other GHGs from major sources, including coal-fired power plants that may require the use of "best available control technology," or "BACT." For example, the EPA has issued regulations restricting GHG emissions from any new U.S. power plants, and from any existing U.S. power plants that undergo major modifications that increase their GHG emissions.

The EPA also recently proposed new source performance standards for GHG emissions for new coal and oil-fired power plants, which could require partial carbon capture and sequestration. 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 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, 2014, we had $70.2 million in reclamation surety bonds, secured by $10.9 million in letters of credit outstanding under our credit agreement. Our credit agreement provides for a $200 million working capital revolving credit facility, of which up to $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, 2014, we had sales commitments for approximately 83% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2015. 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 50% in 2015, 33% in 2016, and 17% in 2017. We derived approximately 81.0% of our total coal revenues from coal sales (excluding results from the joint venture) to our ten largest customers for the year ended December 31, 2014, with affiliates of our top three customers accounting for approximately 39.2% 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, 2014 our current portion of long-term debt that will be funded from cash flows from operating activities during 2015 was approximately $0.2 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 March 6, 2015, Wexford owned an aggregate of approximately 61% 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 (the "Exchange Act"). As of March 6, 2015, Wexford owned an aggregate of approximately 44% 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, 2014, we had 16,696,398 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 March 6, 2015, Wexford owned approximately 44% 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.

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. 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.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration's budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration's proposal, or other similar proposals, could 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.

In addition, the Internal Revenue Service has been considering changes to its private letter ruling policy concerning which activities give rise to qualifying income within the meaning of section 7704 of the Code. The implementation of changes to this policy could include the modification or revocation of existing rulings, including ours.

Any modifications to the U.S. federal income tax laws 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. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If 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.

Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Our unitholders are required to pay 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. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due with respect to that 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 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 raise 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 subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on its 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 common units actually 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 between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction 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 to have 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 could recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have 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 have adopted certain valuation methodologies in determining a unitholder's allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of 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 calendar 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 calendar year, 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 2016 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 September 30, 2013, 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 estimates were updated through December 31, 2014 by our internal staff of engineers based upon production data. The coal reserve and non-reserve coal deposit information for our Elk Horn operation was updated by John T. Boyd Company as of December 31, 2014 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, 2014, we controlled an estimated 480.0 million tons of proven and probable coal reserves and an estimated 290.0 million tons of non-reserve coal deposits. As discussed earlier, Rhino Eastern, a joint venture in which we had a 51% membership interest and for which we served as manager, was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above since the joint venture and its operations were effectively dissolved as of December 31, 2014.

The following table provides information as of December 31, 2014 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)		22.3		22.0			0.3			18.0			4.3			7.4			14.9			14.7			7.6
Rob Fork Complex (KY)		18.7		17.8			0.9			18.7			—			7.3			11.4			13.5			5.2
Deane Complex (KY)		39.3		23.3			16.0			6.8			32.5			38.7			0.6			39.3			—
Rhino Eastern Complex (WV)(3)		33.9		17.1			16.8			29.2			4.7			—			33.9			—			33.9
Rich Mountain Field (WV)		8.2		2.7			5.5			—			8.2			8.2			—			—			8.2
Elk Horn (KY)		111.6		76.1			35.5			52.2			59.4			109.4			2.2			111.6			—

Total Central Appalachia(5)		234.0		159.0			75.0			124.9			109.1			171.0			63.0			179.1			54.9

Northern Appalachia
Hopedale Complex (OH)		22.0		18.0			4.0			22.0			—			8.1			13.9			22.0			—
Sands Hill Complex (OH)		11.3		9.8			1.5			11.3			—			—			11.3			11.3			—
Leesville Field (OH)		27.7		10.5			17.2			—			27.7			27.7			—			27.7			—
Springdale Field (PA)		13.7		8.8			4.9			—			13.7			13.7			—			13.7			—

Total Northern Appalachia(5)		74.7		47.1			27.6			33.3			41.4			49.5			25.2			74.7			—

Illinois Basin
Taylorville Field (IL)		111.1		38.8			72.3			—			111.1			—			111.1			111.1			—
Pennyrile Field (KY)		32.4		18.3			14.1			32.4			—			—			32.4			32.4			—

Total Illinois Basin(5)		143.5		57.1			86.4			32.4			111.1			—			143.5			143.5			—

Western Bituminous
Castle Valley Complex (UT)		21.5		15.2			6.3			21.5			—			—			21.5			21.5			—
McClane Canyon Mine (CO)(4)		6.3		4.2			2.1			6.3			—			0.1			6.2			6.3			—

Total Western Bituminous(5)		27.8		19.4			8.4			27.8			—			0.1			27.7			27.8			—

Total(5)		480.0		282.6			197.4			218.4			261.6			220.6			259.4			425.1			54.9



Percentage of total(5)				58.9	%		41.1	%		45.5	%		54.5	%		46.0	%		54.0	%		88.6	%		11.4	%

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 coal reserves as of December 31, 2014:

	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)		10.34	%		1.19	%		12,967		1.83		22.3		7.7			13.2			1.4			—
Rob Fork Complex (KY)		6.09	%		1.17	%		13,389		1.74		18.7		9.5			5.6			2.0			1.6
Deane Complex (KY)		5.39	%		0.91	%		13,442		1.35		39.3		21.1			11.5			1.0			5.7
Rhino Eastern Complex (WV)(3)		4.32	%		0.68	%		14,025		0.97		33.9		29.1			4.8			—			—
Rich Mountain (WV)		7.33	%		0.60	%		13,313		0.91		8.2		8.2			—			—			—
Elk Horn (KY)		11.50	%		1.51	%		13,100		2.31		111.6		17.1			46.8			47.6			—

Total Central Appalachia		8.49	%		1.18	%		12,843		1.84		234.0		92.7			81.9			52.0			7.3

Northern Appalachia
Hopedale Complex (OH)		6.32	%		2.14	%		13,045		3.28		22.0		—			—			22.0			—
Sands Hill Complex (OH)		9.66	%		3.50	%		11,791		5.94		11.3		—			—			11.3			—
Leesville Field (OH)		5.52	%		2.31	%		12,910		3.58		27.7		—			—			27.7			—
Springdale Field (PA)		7.08	%		1.91	%		13,337		2.87		13.7		—			—			13.7			—

Total Northern Appalachia		6.67	%		2.37	%		12,858		3.68		74.7		—			—			74.7			—

Illinois Basin
Taylorville Field (IL)		7.75	%		3.53	%		11,057		6.38		111.1		—			—			111.1			—
Pennyrile Field (KY)		7.79	%		2.53	%		11,475		4.42		32.4		—			—			32.4			—

Total Illinois Basin		7.76	%		3.30	%		11,151		5.93		143.5		—			—			143.5			—

Western Bituminous
Castle Valley Complex (UT)		10.23	%		0.72	%		12,118		1.19		21.5		21.5			—			—			—
McClane Canyon Mine (CO)(4)		11.19	%		0.57	%		11,241		1.01		6.3		6.3			—			—			—

Total Western Bituminous		10.45	%		0.69	%		11,921		1.15		27.8		27.8			—			—			—

Total(5)		7.58	%		1.80	%		11,513		3.13		480.0		120.5			81.9			270.2			7.3



Percentage of total(5)														25.1	%		17.1	%		56.3	%		1.5	%

The following table provides information on our and Rhino Eastern's non-reserve coal deposits as of December 31, 2014:

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 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, 2014.

We lease office space at 424 Lewis Hargett Circle, Lexington, Kentucky for our executives and administrative support staff. We executed an amendment to this lease in 2013 to extend the lease term for five additional years to August 2018. In addition, we lease a building primarily for our administrative support staff at 265 Hambley Boulevard, Pikeville, Kentucky, which lease expires June 2015, subject to us having a five-year renewal option.

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

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the year ended December 31, 2014 is included in Exhibit 95.1 to this report.

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 March 6, 2015, the closing market price for our common units was $2.37 per unit. The following table sets forth the range of the daily high and low sales prices and cash distribution per common unit for the periods indicated:

As of March 6, 2015, we had outstanding 16,696,398 common units, 12,397,000 subordinated units, a 2% general partner interest and incentive distribution rights, or IDRs. As of March 6, 2015, Rhino Energy Holdings LLC, a Wexford owned entity, owned approximately 36.0% 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 March 6, 2015, there were 94 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 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.

For each of the quarters ended September 30, 2014 and December 31, 2014, we paid distributions to our common unitholders of $0.05 per common unit, which was below the minimum quarterly distribution of $0.445 per unit. Thus, we have accumulated distribution arrearages of approximately $13.7 million related to our common units. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. Our subordinated units do not accrue arrearages for unpaid distributions.

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 December 31, 2012, 2011 and 2010 and for the year ended December 31, 2011 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, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 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 we believe 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 was dissolved in January 2015 and was accounted for under the equity method. Adjusted EBITDA also excludes the effect of certain non-cash and/or 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.

Certain prior year amounts have also been reclassified from continuing operations to discontinued operations due to the sale of our Utica Shale property in March 2014. See "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and

"Item 8. Financial Statements and Supplementary Data." for more information regarding the sale of our Utica Shale property.

	For the Year Ended December 31,

(in thousands, except per unit and per ton data)	2014			2013			2012			2011			2010
Statement of Operations Data:
Total revenues	$	239,057		$	272,265		$	351,743		$	367,221		$	305,647
Costs and Expenses:
Cost of operations (exclusive of depreciation, depletion and amortization)		200,141			199,705			247,719			267,603			220,756
Freight and handling costs		1,877			1,294			5,833			4,329			2,634
Depreciation, depletion and amortization		37,233			39,627			41,274			36,325			34,108
Selling, general and administrative (exclusive of depreciation, depletion and amortization)		19,226			19,800			20,442			21,815			16,449
Asset impairment loss		45,296			1,667			—			—			652
(Gain) loss on sale/acquisition of assets—net		(569	)		(10,359	)		(4,890	)		(3,172	)		(10,716	)

Total costs and expenses		303,204			251,734			310,378			326,900			263,883

Income from operations		(64,147	)		20,531			41,365			40,321			41,764
Interest and other income (expense):
Interest expense and other		(5,708	)		(7,898	)		(7,767	)		(6,062	)		(5,338	)
Interest income and other		274			207			92			51			24
Equity in net income (loss) of unconsolidated affiliate		(11,712	)		(4,729	)		5,757			2,988			4,699

Total interest and other income (expense)		(17,146	)		(12,420	)		(1,918	)		(3,023	)		(615	)

Income before income taxes from continuing operations		(81,293	)		8,111			39,447			37,298			41,149
Income tax		—			—			—			—			—

Net income from continuing operations		(81,293	)		8,111			39,447			37,298			41,149

Income from discontinued operations		130,342			1,307			88			—			—

Net income	$	49,049		$	9,418		$	39,535		$	37,298		$	41,149



Basic and diluted net income per limited partner common unit:(1)
Net income per unit from continuing operations	$	(2.74	)	$	0.29		$	1.39		$	1.40		$	0.22
Net income per unit from discontinued operations		4.39			0.04			0.01			—			—

Net income per common unit, basic and diluted	$	1.65		$	0.33		$	1.40		$	1.40		$	0.22



Distributions paid per limited partner unit	$	1.385		$	1.78		$	1.85		$	1.8108			n/a
Weighted average number of limited partner common units outstanding:
Basic		16,678			15,751			15,331			13,725			12,400
Diluted		16,685			15,760			15,335			13,744			12,413
Balance Sheet Data:
Cash and cash equivalents	$	626		$	423		$	461		$	449		$	76
Property and equipment, net		383,437			424,990			433,791			430,242			282,577
Total assets		473,338			567,767			559,876			539,203			358,645
Total liabilities		152,413			271,396			260,082			237,266			111,028
Total debt—short term and long term		57,432			171,046			163,549			143,098			36,528
Partners' capital/Members' equity	$	320,925		$	296,371		$	299,794		$	301,937		$	247,617
Operating Data(2):
Tons of coal sold		3,557			3,673			4,670			4,876			4,306
Tons of coal produced/purchased		3,514			3,689			4,699			4,873			4,312
Coal revenues per ton(3)	$	57.03		$	64.42		$	65.22		$	68.47		$	67.32
Cost of operations per ton(4)	$	56.26		$	54.37		$	53.04		$	54.88		$	51.27
Other Financial Data:
Net cash provided by operating activities	$	21,181		$	51,730		$	79,744		$	66,916		$	55,001
Net cash used in investing activities		116,741			(43,908	)		(58,404	)		(188,024	)		(37,644	)
Net cash (used in) provided by financing activities		(137,719	)		(7,860	)		(21,328	)		121,481			(17,968	)
Adjusted EBITDA from continuing operations		15,531			59,239			89,637			81,221			71,473
Adjusted EBITDA		145,873			63,528			89,821			81,221			71,473
Capital expenditures(5)	$	62,986		$	54,522		$	61,772		$	211,473		$	41,250

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 included our proportionate share of DD&A and interest expense for the Rhino Eastern joint venture, which was dissolved in January 2015, is appropriate since our portion of Rhino Eastern's net income that was recognized as a single line item in our financial statements was affected by these expense items. Since we did 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-cash and/or 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,

	2014			2013			2012			2011		2010
	(in thousands)
Reconciliation of Adjusted EBITDA to net income:
Net income from continuing operations	$	(81,293	)	$	8,111		$	39,447		$	37,298	$	41,149
Plus:
Depreciation, depletion and amortization		37,233			39,627			41,274			36,325		34,108
Interest expense		5,708			7,898			7,767			6,062		5,338

EBITDA from continuing operations(a)		(38,352	)		55,636			88,488			79,685		80,595

Plus: Rhino Eastern DD&A-51%		948			994			1,070			1,509		1,630
Plus: Rhino Eastern interest expense-51%		41			8			79			27		37
Less: Gain from Castle Valley acquisition(b)		—			—			—			—		(10,789	)
Plus: Impairment of Rhino Eastern joint venture(c)		5,863			—			—			—		—
Plus: Asset impairments and related charges(c)		47,031			2,601			—			—		—

Adjusted EBITDA from continuing operations(a)		15,531			59,239			89,637			81,221		71,473

Net income from discontinued operations		130,342			1,307			88			—		—
DD&A included in net income from discontinued operations		—			2,982			96			—		—

Adjusted EBITDA	$	145,873		$	63,528		$	89,821		$	81,221	$	71,473



Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	21,181		$	51,730		$	79,744		$	66,916	$	55,001
Plus:
Increase in net operating assets		—			—			—			8,466		10,260
Decrease in provision for doubtful accounts		—			—			—			19		—
Gain on sale of assets		130,621			10,359			4,878			3,172		—
Gain on acquisition		—			—			—			—		10,789
Gain on retirement of advance royalties		—			—			—			—		—
Amortization of deferred revenue		1,731			1,553			929			532		—
Amortization of actuarial gain		368			145			295			—		—
Interest expense		5,708			7,898			7,767			6,062		5,338
Settlement of litigation		—			—			—			—		—
Equity in net income of unconsolidated affiliates		—			—			5,757			2,988		4,699
Less:
Decrease in net operating assets		4,540			599			3,330			—		—
Accretion on interest-free debt		—			57			222			210		206
Amortization of advance royalties		440			270			244			1,104		865
Amortization of debt issuance costs		2,127			1,295			1,075			1,043		844
Increase in provision for doubtful accounts		724			—			—			—		—
Equity-based compensation		255			605			873			727		291
Loss on sale of assets		—			—			—			—		73
Loss on asset impairments		45,296			1,667			—			—		652
Loss on retirement of advance royalties		244			182			100			79		396
Accretion on asset retirement obligations		2,281			2,356			1,896			1,956		2,165
Equity in net loss of unconsolidated affiliate		11,712			4,729			—			—		—
Distributions from unconsolidated affiliate		—			—			2,958			3,351		—

EBITDA(a)		91,990			59,925			88,672			79,685		80,595

Plus: Rhino Eastern DD&A-51%		948			994			1,070			1,509		1,630
Plus: Rhino Eastern interest expense-51%		41			8			79			27		37
Less: Gain from Castle Valley acquisition(b)		—			—			—			—		(10,789	)
Plus: Impairment of Rhino Eastern joint venture(c)		5,863			—			—			—		—
Plus: Non-cash write-off of mining equipment and asset impairment(c)		47,031			2,601			—			—		—

Adjusted EBITDA(a)		145,873			63,528			89,821			81,221		71,473

Less: Net income from discontinued operations		(130,342	)		(1,307	)		(88	)		—		—
Less: DD&A included in net income from discontinued operations		—			(2,982	)		(96	)		—		—

Adjusted EBITDA from continuing operations(a)	$	15,531		$	59,239		$	89,637		$	81,221	$	71,473

(b): During 2010, we acquired certain assets for cash consideration of approximately $15.0 million from the Trustee of the Federal Bankruptcy Court charged with the sale of the C.W. Mining Company assets, located in Emery and Carbon Counties, Utah (referred to as our Castle Valley mining complex). Because the fair value of the assets acquired exceeded the purchase price, we recorded a non-cash gain of $10.8 million that is reflected in our 2010 financial results. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy. Management believes that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors' understanding of how management assesses the performance of our business. Management believes the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, management believes the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.
(c): During the fourth quarter of 2014, we incurred non-cash charges of approximately $52.9 million. Of this total, approximately $45.3 million related to asset impairment and related charges associated with our various mining properties that were evaluated for impairment and reduced to our estimate of fair value during the fourth quarter of 2014. An additional component of the $52.9 million of non-cash charges relates to the $5.9 million impairment charge for our Rhino Eastern joint venture. Please see our more detailed discussion of these asset impairment and related charges in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. During the fourth quarter of 2014, we also incurred other non-cash charges that included an approximate $0.8 million mark-to-market adjustment for a portion of our low quality steam coal inventory located in Central Appalachia, an approximate $0.7 million charge for an accounts receivable allowance for one of our customers in Central Appalachia that entered bankruptcy proceedings and an approximate $0.2 million charge incurred for the write-off of obsolete supplies inventory at one of our Northern Appalachia operations. We believe that the isolation and presentation of these specific items to arrive at Adjusted EBITDA is useful because it enhances investors' understanding of how we assess the performance of our business. We believe the adjustment of these items provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of these items provides investors with enhanced comparability to prior and future periods of our operating results.

During the first quarter of 2013, we incurred a non-cash expense of approximately $0.9 million due to the write-off of a continuous miner that was damaged at one of our underground mines in Central Appalachia. In addition, during the fourth quarter of 2013, we made a strategic decision to permanently close the mining operations at our McClane Canyon mine in Colorado, which resulted in a non-cash impairment charge of approximately $1.7 million. We believe that the isolation and presentation of these specific items to arrive at Adjusted EBITDA is useful because it enhances investors' understanding of how we assess the performance of our business. We believe the adjustment of these items provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of these items provides investors with enhanced comparability to prior and future periods of our operating results.

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

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."

In March 2014, we completed a purchase and sale agreement with Gulfport Energy to sell our oil and gas properties in the Utica Shale region for approximately $184.0 million. Our consolidated statements of operations and comprehensive income have been retrospectively adjusted to reclassify our portion of our Utica Shale operations to discontinued operations for the years ended December 31, 2013 and 2012. The following discussion of our operating results includes revised financial data for the 2013 and 2012 periods.

We are a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. 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 Cana Woodford region of western Oklahoma where we receive royalty revenue from any hydrocarbons produced and sold by operators on our 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. We have also invested in joint ventures that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S.

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 Cana Woodford region in western Oklahoma. As of December 31, 2014, we controlled an estimated 480.0 million tons of proven and probable coal reserves, consisting of an estimated 425.1 million tons of steam coal and an estimated 54.9 million tons of metallurgical coal. In addition, as of December 31, 2014, we controlled an estimated 290.0 million tons of non-reserve coal deposits. As discussed further below, Rhino Eastern LLC, a joint venture in which we had a 51% membership interest and for which we served as manager, was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above since the joint venture and its operations were effectively dissolved as of December 31, 2014.

As of December 31, 2014, we operated nine mines, including four underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. 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, 2014 also consisted of 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 potentially 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 Cana Woodford region. 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, 2014, we generated revenues of approximately $239.1 million and net income of approximately $49.0 million. Net income consisted primarily of an approximate $121.7 million gain from the sale of our Utica Shale oil and natural gas assets, which was partially offset by approximately $45.3 million of asset impairment and related charges as well as a $5.9 million impairment charge of our Rhino Eastern joint venture. Excluding results from the Rhino Eastern joint venture, for the year ended December 31, 2014, we produced approximately 3.4 million tons of coal, purchased approximately 0.1 million tons of coal and sold approximately 3.6 million tons of coal, approximately 78% of which were pursuant to supply contracts. Additionally, Rhino Eastern produced and sold approximately 0.2 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2014.

Due to the prolonged weakness in the U.S. coal markets and the dim prospects for an upturn in the coal markets in the near term, in the fourth quarter of 2014, we performed a comprehensive review of our current coal mining operations as well as potential future development projects to ascertain any potential impairment losses. We identified various properties, projects and operations that were potentially impaired based upon changes in our strategic plans, market conditions or other factors. We recorded approximately $45.3 million of asset impairment and related charges for the year ended December 31, 2014, which is recorded on the Asset impairment and related charges line of our

consolidated statements of operations and comprehensive income. We also recorded an impairment charge of $5.9 million related to our Rhino Eastern joint venture that is recorded on the Equity in net (loss)/income of unconsolidated affiliates line of our consolidated statements of operations and comprehensive income. The major components that comprise this total asset impairment and related loss are described below, including the $5.9 million impairment charge related to our Rhino Eastern joint venture.

We control certain mineral rights and related surface land located eleven miles north of Loma, Colorado (referred to as the "Red Cliff" property). We had been working with the U.S. Bureau of Land Management ("BLM") agency since 2005 on an environmental impact statement report ("EIS report") that was required to be completed before we could move forward with the development and permitting of a mining project on the Red Cliff property. We capitalized the cost associated with the ongoing EIS report process as mine development costs, which had accumulated to approximately $11.2 million at December 31, 2014. In addition, we invested approximately $11.0 million to acquire land for the purpose of building a rail spur to the property and also purchased certain land tracts at a cost of approximately $5.0 million for the purpose of constructing a rail load-out facility. At December 31, 2014, we had a carrying amount of approximately $16.2 million for the purchased land and approximately $2.0 million for mineral rights associated with a lease of coal reserves with the BLM. These amounts are in addition to the $11.2 million of mine development cost discussed above. Additionally, we had $0.3 million of accrued liabilities in BLM refunds related to the Red Cliff EIS report. In summary, we had total carrying costs of approximately $29.1 million for the Red Cliff property at December 31, 2014. In early 2010, we had a detailed mine development study performed for the Red Cliff property by an independent third party, which estimated the total cost to build out the project would be approximately $420 million once the EIS report was finalized.

The EIS report outlines the environmental effects a potential project would have on the affected area. An initial EIS report was issued for public comment and review in 2009, which received over 20,000 comments in the 90-day comment period. Based on the volume of comments received on the initial report, the BLM decided that the EIS report process needed to be restarted. We agreed to restart the EIS report and the first two chapters of the EIS report were completed and work on chapters three and four was ready to begin in November 2014. Chapters three and four of the EIS report involve the costlier portion of report project since this includes detailed studies of the impacts to air quality, wildlife, etc. Up to the fourth quarter of 2014, we had decided to continue with the EIS report despite the prolonged weakness in the coal markets. However, the decision was made by our executive management to limit capital spending on all projects due to the weak coal market conditions that had adversely affected our financial results during 2014. Thus, due to the lack of progress in getting the EIS report finalized, the amount of money spent on the project to date, the impending higher costs to be incurred on the next phase of the EIS report and the desire to limit capital spending on certain projects due to the ongoing weakness in the coal markets, we decided to suspend the EIS report process in November 2014. Based on the fact pattern described above, we determined at December 31, 2014 that we would not pursue the development of the Red Cliff property and the related assets would be abandoned or sold for current market value.

Since we reached a decision to abandon the development of the Red Cliff asset group at December 31, 2014, we evaluated the assets for impairment in accordance with applicable accounting guidelines. We determined that the mine development costs and mineral rights could not be sold to a third party, so we recorded an asset impairment loss of $13.2 million for the year ended December 31, 2014 for these assets, which represented the write down of the previous carrying value of these assets to zero. The land related to the Red Cliff project was recorded at fair value (based on the third party appraisal) less costs to sell for a total net fair value of approximately $6.9 million since we had

committed to a plan to sell these assets, which resulted in an additional asset impairment charge of $9.3 million. In total, after netting the $0.3 million of BLM refunds that will not be repaid due to abandoning the EIS report process, we recorded total asset impairment and related charges of $22.2 million related to our Red Cliff assets at December 31, 2014.

In June 2011, we acquired coal mineral rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million (referred to as the "Rich Mountain" property). These development stage properties were unpermitted and contained no infrastructure. We conducted a core drilling program on the Rich Mountain property after it was purchased and determined the property contained an estimated 8.2 million tons of proven and probable underground metallurgical coal reserves. We capitalized the cost associated with our core drilling as mine development costs and the total value in property, plant and equipment for the Rich Mountain property was $8.3 million at December 31, 2014.

During the course of our core drilling program, we could not locate enough proven and probable coal reserves within a contiguous location that would substantiate the development of a mining operation. As stated above, the coal reserves are located on undeveloped property and we would have to spend a large amount of capital in order to develop a mining operation on this property, which would include building a coal preparation plant, loadout, etc. In addition, the ongoing deterioration in the metallurgical coal markets has resulted in weak demand and historically low prices for this quality of coal. In the fourth quarter of 2014, we reassessed our strategy for these mineral rights and determined that it was not economical to develop this small coal reserve given the cost of building the required infrastructure. Although we did not have an active marketing strategy for the Rich Mountain property, we contacted a third party coal company with current operations in the general area of the Rich Mountain property to determine if there would be any interest in acquiring these mineral rights from us. Repeated attempts to obtain a non-binding price quote for the Rich Mountain mineral rights from this third party resulted in no indicative bids being offered. Based on the factors discussed above, we determined at December 31, 2014 that we would not pursue the development of the Rich Mountain property and the related assets would be abandoned.

In accordance with applicable accounting guidelines, we reviewed our Rich Mountain assets as of December 31, 2014 for any impairment indicators that may have been present for this long-lived asset group. Since we reached a decision to abandon the potential development of this asset group and could not obtain any bids to indicate any fair value, we recorded an asset impairment loss of $8.3 million for the year ended December 31, 2014, which represented the write down of the previous carrying value of this asset group to zero.

We have a steam coal surface mine operation in eastern Kentucky (referred to as "Bevins Branch") that was idled during mid-2014 as that location's contract with its single customer expired at that time. We actively attempted to market the coal from this operation to potential new customers and had maintained the mine so that production could resume in a relatively short time period whenever new customers could be secured. We had unsuccessfully been able to market the coal from this operation as the coal markets have been especially weak for coal from Central Appalachia and the lower quality of coal from the Bevins Branch operation proved especially difficult to market. As we found it difficult to market the quality of coal found at this mine in the current market place, the we initiated negotiations in October 2014 with a third party for the potential sale of the Bevins Branch operation. At December 31, 2014, we received a letter of intent with the third party interested in the Bevins Branch operation to accept ownership of this operation, including its related reclamation obligations. We are finalizing the contractual agreement with this third party. The contractual agreement has the third party assume the Bevins Branch operation where the only financial

compensation we will receive is a future override royalty and the assumption of the reclamation obligations by the buyer. The closing of the transaction would also allow us to avoid the ongoing maintenance costs of this operation. We considered these events to warrant an impairment analysis for this operation as of December 31, 2014.

We reviewed the Bevins Branch operation as of December 31, 2014 in accordance with the accounting guidance for long-lived asset impairment. We determined this asset group should be written down to an estimated fair value of approximately $2.4 million, which equates to the estimated fair value of the future royalty of approximately $0.2 million and the benefit to be recognized of transferring the reclamation obligations of approximately $2.2 million. Based on this analysis, we recorded total asset impairment and related charges of $8.3 million for the Bevins Branch operation for the year ended December 31, 2014. The total asset impairment and related charges include approximately $1.7 million for the write-off of advanced royalty balances related to the Bevins Branch operation that we do not expect to recover in the future. We also recorded an $6.6 million write-down of mineral value and mine development costs to the estimated fair value of $2.4 million of the royalty asset and benefit from transferring the reclamation obligations. We have reported the remaining assets and any related liabilities as held for sale on our consolidated statements of financial position as of December 31, 2014.

As of December 31, 2014, we also performed a comprehensive review of our other mining operations, primarily in Central Appalachia since this region has experienced the most extensive downturn in the coal markets, to determine if any other assets might be potentially impaired. Our review resulted in an additional $6.5 million of asset impairment and related charges, with $3.2 million related to mineral rights, $1.8 million of mine development costs and $1.5 million of advanced royalties that we do not expect to recover. The majority of these additional charges, approximately $4.9 million, related to low quality steam coal operations in Central Appalachia that we determined were uneconomical to mine due to the ongoing downturn in the markets for this quality of coal. The remaining $1.6 million primarily related to advanced royalties that we do not expect to recover at our Central Appalachia operations due to the extended downturn in demand for coal from this region.

For the quarters ended September 30, 2014 and December 31, 2014, we announced cash distributions of $0.05 per common unit, or $0.20 per unit on an annualized basis, which was lower than the previous quarters' distribution amounts of $0.445 per common unit, or $1.78 per unit on an

annualized basis. The distribution reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow. In conjunction with the distribution reductions, we have increased our focus on cost and productivity improvements at our ongoing core operations, along with a focus on reducing the carrying costs of non-core and idled operations. The distribution reductions and cost improvements are designed to preserve liquidity to enhance our long-term value.

Our common units accrue arrearages every quarter when the distribution level is below the minimum level of $0.445 per unit, as outlined in our Partnership agreement. Since our distributions for the quarters ended September 30, 2014 and December 31, 2014 were below the minimum level, we have accumulated arrearages at December 31, 2014 related to the common unit distribution of approximately $13.7 million.

We and an affiliate of Wexford 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. 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, 2013, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 152,300 gross acres, or approximately 7,615 net acres, for a total purchase price of approximately $31.1 million. In addition, per the joint operating agreement among us, Gulfport and an affiliate of Wexford Capital, we funded our proportionate share of drilling costs to Gulfport for wells drilled on our acreage. As of December 31, 2013, we funded approximately $23.3 million of drilling costs. We received approximately $5.6 million of revenue from this investment for the year ended December 31, 2013.

In March 2014, we completed a purchase and sale agreement (the "Purchase Agreement") with Gulfport to sell our oil and natural gas properties in the Utica Shale region for approximately $184.0 million (the "Purchase Price"). The Purchase Agreement was effective as of January 1, 2014 and the Purchase Price was adjusted for any unsettled expenditures made and/or proceeds received from our portion of the Utica Shale properties prior to the effective date. At the closing of the Purchase Agreement, we were immediately due approximately $179.0 million, net of any adjustments described above, and the remaining approximately $5.0 million was scheduled to be paid within approximately 90 days of March 20, 2014, subject to ongoing legal title work related to specific properties. In December 2014, we settled the remaining $5.0 million due from Gulfport based upon net amounts payable from us to Gulfport prior to the effective date of the Purchase Agreement as well as amounts due us related to legal reviews of the properties subject to the Purchase Agreement and other unsettled items due to us prior to the effective date of the Purchase Agreement. The net effect of this settlement resulted in us paying Gulfport approximately $46,000 in December 2014. We recorded a gain of approximately $121.7 million during the year ended December 31, 2014 related to this sale. The sale of our investment in the Utica Shale significantly reduced our debt and enhanced our financial flexibility. The elimination of our debt provides us the capability to opportunistically expand our operations and increase our cash flow through the development of existing coal reserves or the potential acquisition of MLP qualifying assets.

described above in the sale of the Utica Shale investment, which previously constituted a portion of the collateral of the administrative agent and lenders under the amended and restated senior secured credit facility. This second amendment also reduces the borrowing capacity under the amended and restated senior secured credit facility to a maximum of $200 million and alters the maximum leverage ratio to 3.5 from January 1, 2014 through September 30, 2015. The maximum leverage ratio decreases to 3.25 from October 1, 2015 through December 31, 2015 and then decreases to 3.0 after December 31, 2015. In addition, the second amendment adjusts the maximum investments (other than directly by us) in hydrocarbons, hydrocarbon interests and assets and activities related to hydrocarbons, in each case, excluding coal, in an aggregate amount not to exceed $50 million. All other terms of the amended and restated senior secured credit facility were not affected by the second amendment. Due to the second amendment, we recorded a non-cash charge of approximately $1.1 million to write-off a portion of our unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility.

In January 2014, we received approximately $8.4 million of net proceeds from the sale by Blackhawk Midstream LLC ("Blackhawk") of its equity interest in two entities, Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, to Summit Midstream Partners, LLC. As part of the joint operating agreement for the Utica Shale investment discussed above, we had the right to approximately 5% of the proceeds of the sale by Blackhawk.

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 were subsequently required to pay an additional $2.0 million related to this acquisition after certain conditions were met, of which $1.6 million was paid in the third quarter of 2012 and the remaining $0.4 million was paid in the fourth quarter of 2013. The $2.0 million in total payments was recorded in Property, plant and equipment. An additional $1.0 million was paid in the third quarter of 2014 due to conditions that were met in the quarter requiring payment and this additional $1.0 million was recorded in Property, plant and equipment. As of December 31, 2014, the coal leases and property were estimated to contain approximately 32.4 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is fully permitted and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers.

In mid-2014, we completed the initial construction of a new underground mining operation on the purchased property, referred to as our Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. Production and sales from this new underground mine began in mid-2014.

We have invested in 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. Our investment includes approximately 1,900 net mineral acres that we own in the Cana Woodford region which provide us with monthly royalty revenue.

In September 2014, we made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC ("Sturgeon"), with affiliates of Wexford Capital and Gulfport. Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. We account for the investment in this joint venture and results of operations under the equity method. We recorded our proportionate portion of the operating income for this investment during 2014 of approximately $0.4 million.

In December 2012, we made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant 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 Muskie during 2014 of approximately $0.1 million. During the year ended December 31, 2014, we contributed additional capital based upon our ownership share to the Muskie joint venture in the amount of $0.2 million. In addition, during the year ended December 31, 2013, we provided a loan based upon its ownership share to Muskie in the amount of $0.2 million, which was fully repaid in November 2014 in conjunction with our contribution of our interest in Muskie to Mammoth Energy Partners LP ("Mammoth"). In November 2014, we contributed our investment interest in Muskie to Mammoth in return for a limited partner interest in Mammoth. Mammoth was formed to own various companies that provide services to companies who engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth's companies provide services that include completion and production services, contract land and directional drilling services and remote accommodation services.

Our results of operations in the near term could be impacted by a number of factors, including (1) the availability of transportation for coal shipments, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems at mining locations, (4) adverse weather conditions and natural disasters 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, 2014, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

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

As of December 31, 2014, we have five reportable business segments: Central Appalachia, Northern Appalachia, Eastern Met, Rhino Western and Illinois Basin. Additionally, we have an Other category that includes our ancillary businesses and our remaining oil and natural gas activities. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which, as of December 31, 2014, together included two underground mines, three surface mines and four preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, our Central Appalachia segment includes our Elk Horn coal leasing operations. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining

complex, and the Leesville field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of December 31, 2014. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2014. The Eastern Met segment included our 51% equity interest in the results of operations of the Rhino Eastern joint venture, which owned the Rhino Eastern mining complex, located in West Virginia, and for which we served as manager. The Rhino Eastern joint venture was dissolved in January 2015 and the 2014 financial results are shown since the joint venture owned, and we operated, this mining complex during the year. Our Rhino Western segment includes our underground mine in the Western Bituminous region at our Castle Valley mining complex in Utah. Beginning with our 2014 year-end reporting, we have included a reportable business segment, referred to as our Illinois Basin segment, which includes our new underground mine, preparation plant and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our Taylorville field reserves located in central Illinois. All periods have been recast to reflect this change in our segment reporting. Our new Pennyrile mining complex began production and sales in mid-2014.

Beginning with 2013 year-end reporting, we had included a reportable business segment for our oil and natural gas activities since the total assets for these operations met the quantitative threshold for separate segment reporting. The Oil and Natural Gas segment included our Utica Shale activities, which were sold during the first quarter of 2014 as described earlier, as well as our Cana Woodford activities, the Razorback drill pad construction operations and the Muskie joint venture to provide sand for fracking operations. Prior to 2013, our oil and natural gas activities were included in our Other category for segment reporting purposes. Since the majority of our oil and natural gas activities were in the Utica Shale and the Utica Shale financial results are now included in discontinued operations due to their sale, the segment data for our remaining oil and natural gas activities has been included in the Other category for segment reporting purposes for 2014 and the 2013 comparable periods since they are not material for separate segment reporting. Our Other category is comprised of our ancillary businesses and our remaining oil and natural gas activities.

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 the Rhino Eastern LLC joint venture through the end of 2014 before it was dissolved in January 2015, while also excluding certain non-cash and/or 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, 2014, 2013 and 2012:

	Year Ended December 31,

	2014			2013			2012
	(in millions)
Statement of Operations Data:
Total revenues	$	239.1		$	272.2		$	351.7
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below)		200.2			199.7			247.7
Freight and handling costs		1.9			1.3			5.8
Depreciation, depletion and amortization		37.2			39.6			41.3
Selling, general and administrative (exclusive of DD&A shown separately above)		19.3			19.8			20.5
Asset impairment and related charges		45.3			1.7			—
(Gain) on sale/disposal of assets		(0.6	)		(10.4	)		(4.9	)

(Loss)/income from operations		(64.2	)		20.5			41.3
Interest and other income (expense):
Interest expense and other		(5.7	)		(7.9	)		(7.8	)
Interest income and other		0.3			0.2			0.1
Equity in net (loss)/income of unconsolidated affiliates		(11.7	)		(4.7	)		5.8

Total interest and other income (expense)		(17.1	)		(12.4	)		(1.9	)

Net (loss)/income from continuing operations		(81.3	)		8.1			39.4

Net income from discontinued operations		130.3			1.3			0.1

Net income	$	49.0		$	9.4		$	39.5



Other Financial Data
Adjusted EBITDA from continuing operations	$	15.5		$	59.2		$	89.6
Net income from discontinued operations		130.3			1.3			0.1
DD&A included in net income from discontinued operations		—			3.0			0.1

Adjusted EBITDA	$	145.8		$	63.5		$	89.8

Summary. For the year ended December 31, 2014, our total revenues decreased to $239.1 million from $272.2 million for the year ended December 31, 2013. We sold 3.6 million tons of coal for the year ended December 31, 2014, which is 0.1 million tons less, or a 3.1% decrease, than the 3.7 million tons of coal sold for the year ended December 31, 2013. This decrease in tons sold was the result of weak demand in the steam coal markets as well as railroad transportation constraints, which also resulted in lower coal revenues for 2014 compared to 2013. Coal revenues in 2014 were also negatively impacted by weak met coal prices compared to 2013 levels. We believe the weak demand in the steam coal markets was primarily driven by an over-supply of low-priced natural gas that increased stockpiles of coal at electric utilities. We believe utilities have worked to decrease their coal stockpiles, but the utilities remain slow to replenish their coal inventories as natural gas prices remain relatively low. In addition, we believe that lower than normal summer weather temperatures and a mild start to the winter of 2014-15 have resulted in reduced demand for steam coal for 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 ongoing economic weakness in China and Europe.

For the year ended December 31, 2014, our coal inventories remained relatively flat compared to the year ended December 31, 2013 as we matched our production levels to our sales.

Net loss from continuing operations and Adjusted EBITDA from continuing operations decreased for the year ended December 31, 2014 compared to the year ended December 31, 2013. We generated a net loss from continuing operations of approximately $81.3 million for the year ended December 31, 2014 compared to net income from continuing operations of approximately $8.1 million for the year ended December 31, 2013. For the year ended December 31, 2014, our net income from continuing operations was negatively impacted by approximately $45.3 million of asset impairment and related charges along with a $5.9 million impairment charge related to our Rhino Eastern joint venture. For the year ended December 31, 2013, our net income from continuing operations was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property, while net income from continuing operations for this period was negatively impacted by approximately $0.9 million due to the non-cash write-off of a continuous miner that was destroyed at one of our Central Appalachia underground mines and by approximately $1.7 million due to an asset impairment loss from permanently idling our McClane Canyon mine. Net loss from continuing operations for the year ended December 31, 2014 was also negatively impacted period to period due to a $12.1 million net loss from the Rhino Eastern joint venture, which includes the $5.9 million impairment charge discussed above, compared to net loss of $4.3 million for the year ended December 31, 2013, which represents our proportionate share of loss from Rhino Eastern in which we had a 51% membership interest and which was effectively dissolved in January 2015.

Adjusted EBITDA from continuing operations decreased to $15.5 million for the year ended December 31, 2014, from $59.2 million for the year ended December 31, 2013. Adjusted EBITDA from continuing operations decreased year to year primarily due to the net loss from continuing operations generated in 2014 as described above.

Including income from discontinued operations of approximately $130.3 million, our net income and Adjusted EBITDA for the year ended December 31, 2014 were $49.0 million and $145.8 million, respectively. Income from discontinued operations for the year ended December 31, 2014 consisted primarily of the gain of approximately $121.7 million from the sale of our Utica Shale oil and natural gas properties.

Tons Sold. The following table presents tons of coal sold by reportable segment for the years ended December 31, 2014 and 2013:

We sold approximately 3.6 million tons of coal in the year ended December 31, 2014 as compared to approximately 3.7 million tons sold for the year ended December 31, 2013. The decrease in total tons sold year-to-year was primarily due to fewer met coal tons sold from our Central Appalachia segment due to weak market conditions and lower sales from our Hopedale complex in Northern Appalachia due to railroad transportation constraints, partially offset by tons sold from our new Pennyrile mine in our Illinois Basin segment. Tons of coal sold in our Central Appalachia segment decreased by approximately 0.2 million, or 16.3%, to approximately 1.3 million tons for the year ended December 31, 2014 from approximately 1.5 million tons for the year ended December 31, 2013. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to a decrease in met coal tons sold due to weak market conditions. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.2 million, or 17.1%, to approximately 1.0 million tons for the year ended December 31, 2014 from approximately 1.2 million tons for the year ended December 31, 2013, primarily due to lower sales from our Hopedale complex as discussed above. Coal sales from our Rhino Western segment increased by approximately 0.1 million, or 13.5%, to approximately 1.1 million tons for the year ended December 31, 2014 as our Castle Valley mine saw an increase in customer demand. Our Illinois Basin segment includes our initial sales from our new Pennyrile mining complex in western Kentucky that began production and sales in mid-2014.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2014 and 2013:

Segment	Year ended December 31, 2014		Year ended December 31, 2013		Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	89.0	$	126.4	$	(37.4	)	(29.6	)%
Freight and handling revenues		—		—		—		n/a
Other revenues		20.5		21.0		(0.5	)	(2.6	)%

Total revenues	$	109.5	$	147.4	$	(37.9	)	(25.8	)%



Coal revenues per ton*	$	70.53	$	83.85	$	(13.32	)	(15.9	)%
Northern Appalachia
Coal revenues	$	60.5	$	72.2	$	(11.7	)	(16.3	)%
Freight and handling revenues		2.0		2.2		(0.2	)	(6.4	)%
Other revenues		9.0		6.0		3.0		49.8	%

Total revenues	$	71.5	$	80.4	$	(8.9	)	(11.1	)%



Coal revenues per ton*	$	59.51	$	58.95	$	0.56		0.9	%
Rhino Western
Coal revenues	$	44.0	$	38.0	$	6.0		16.0	%
Freight and handling revenues		—		—		—		n/a
Other revenues		0.1		0.3		(0.2	)	(79.1	)%

Total revenues	$	44.1	$	38.3	$	5.8		15.2	%



Coal revenues per ton*	$	41.27	$	40.37	$	0.90		2.2	%
Illinois Basin
Coal revenues	$	9.4	$	—	$	9.4		n/a
Freight and handling revenues		—		—		—		n/a
Other revenues		0.3		0.3		—		0.1	%

Total revenues	$	9.7	$	0.3	$	9.4		n/a



Coal revenues per ton*	$	44.28	$	—	$	44.28		n/a
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	$	4.3	$	5.8	$	(1.5	)	(26.6	)%

Total revenues	$	4.3	$	5.8	$	(1.5	)	(26.6	)%



Coal revenues per ton*		n/a		n/a		n/a		n/a
Total
Coal revenues	$	202.9	$	236.6	$	(33.7	)	(14.3	)%
Freight and handling revenues		2.0		2.2		(0.2	)	(6.4	)%
Other revenues		34.2		33.4		0.8		1.9	%

Total revenues	$	239.1	$	272.2	$	(33.1	)	(12.2	)%



Coal revenues per ton*	$	57.03	$	64.42	$	(7.39	)	(11.5	)%

Our total revenues for the year ended December 31, 2014 decreased by $33.1 million, or 12.2%, to $239.1 million from $272.2 million for the year ended December 31, 2013. The decrease in total revenues was primarily due to lower coal revenues due to fewer met coal tons sold and lower met coal prices in Central Appalachia, as well as fewer tons sold from our Hopedale complex in Northern Appalachia due to railroad transportation constraints. Coal revenues per ton were $57.03 for the year ended December 31, 2014, a decrease of $7.39, or 11.5%, from $64.42 per ton for the year ended December 31, 2013. This decrease in coal revenues per ton was primarily the result of lower prices for met coal sold in Central Appalachia.

For our Central Appalachia segment, coal revenues decreased by $37.4 million, or 29.6%, to $89.0 million for the year ended December 31, 2014 from $126.4 million for the year ended December 31, 2013 primarily due to fewer met coal tons sold and a decrease in the price for met coal tons sold due to ongoing weakness in the met coal market. Coal revenues per ton for our Central Appalachia segment decreased by $13.32, or 15.9%, to $70.53 per ton for the year ended December 31, 2014 as compared to $83.85 for the year ended December 31, 2013, primarily due to lower prices for metallurgical coal sold, along with the expiration during 2014 of a long-term, above-market steam coal sales contract. Other revenues decreased slightly for our Central Appalachia segment primarily due to lower coal royalty revenue from our coal leasing business as our lessees mined slightly more tons during 2014 compared to 2013, but experienced lower sales prices.

For our Northern Appalachia segment, coal revenues were $60.5 million for the year ended December 31, 2014, a decrease of $11.7 million, or 16.3%, from $72.2 million for the year ended December 31, 2013. This decrease was primarily due to fewer tons sold from our Hopedale complex in Northern Appalachia as mentioned earlier. Coal revenues per ton for our Northern Appalachia segment increased by $0.56, or 0.9%, to $59.51 per ton for the year ended December 31, 2014 as compared to $58.95 per ton for the year ended December 31, 2013. This increase was primarily due to an increase in the contracted sales price for tons sold from our Hopedale complex.

For our Rhino Western segment, coal revenues increased by $6.0 million, or 16.0%, to $44.0 million for the year ended December 31, 2014 from $38.0 million for the year ended December 31, 2013, primarily due to increased customer demand at our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $41.27 for the year ended December 31, 2014, an increase of $0.90, or 2.2%, from $40.37 for the year ended December 31, 2013. The increase in coal revenues per ton were due to an increase in the contracted sales prices for steam coal sales from our Castle Valley mine in 2014 compared to 2013.

In our Illinois Basin segment, coal revenues were $9.4 million and coal revenues per ton were $44.28 for the year ended December 31, 2014 as we had our initial sales from our Pennyrile mining complex in western Kentucky.

Other revenues for our Other category decreased by $1.5 million for the year ended December 31, 2014 from the year ended December 31, 2013. The decrease in other revenues was primarily due to lower revenues from our Razorback drill pad construction company due to fewer drill pads completed during the year ended December 31, 2014 compared to 2013.

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. Our Northern Appalachia, Rhino Western and Illinois Basin segments currently only produce and sell steam coal.

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, 2014 and 2013:

Segment	Year ended December 31, 2014		Year ended December 31, 2013			Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	81.2	$	100.0		$	(18.8	)	(18.8	)%
Freight and handling costs		—		0.3			(0.3	)	n/a
Depreciation, depletion and amortization		20.2		24.2			(4.0	)	(16.3	)%
Selling, general and administrative		18.6		18.5			0.1		0.2	%
Cost of operations per ton*	$	64.33	$	66.33		$	(2.00	)	(3.0	)%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	56.5	$	52.4		$	4.1		7.8	%
Freight and handling costs		1.9		1.0			0.9		84.3	%
Depreciation, depletion and amortization		7.6		8.1			(0.5	)	(6.8	)%
Selling, general and administrative		0.2		0.3			(0.1	)	(21.0	)%
Cost of operations per ton*	$	55.67	$	42.79		$	12.88		30.1	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	36.0	$	30.7		$	5.3		17.2	%
Freight and handling costs		—		—			—		n/a
Depreciation, depletion and amortization		6.0		5.5			0.5		9.9	%
Selling, general and administrative		0.1		0.1			—		9.2	%
Cost of operations per ton*	$	33.70	$	32.62		$	1.08		3.3	%
Illinois Basin
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	12.0	$	(0.3	)	$	12.3		n/a
Freight and handling costs		—		—			—		n/a
Depreciation, depletion and amortization		2.3		0.3			2.0		n/a
Selling, general and administrative		0.1		—			0.1		n/a
Cost of operations per ton*	$	56.35	$	—		$	56.35		n/a
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	14.5	$	16.9		$	(2.4	)	(14.4	)%
Freight and handling costs		—		—			—		n/a
Depreciation, depletion and amortization		1.1		1.5			(0.4	)	(27.4	)%
Selling, general and administrative		0.3		0.9			(0.6	)	(68.9	)%
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)	$	200.2	$	199.7		$	0.5		0.2	%
Freight and handling costs		1.9		1.3			0.6		45.1	%
Depreciation, depletion and amortization		37.2		39.6			(2.4	)	(6.0	)%
Selling, general and administrative		19.3		19.8			(0.5	)	(2.9	)%
Cost of operations per ton*	$	56.26	$	54.37		$	1.89		3.5	%

Cost of Operations. Total cost of operations was $200.2 million for the year ended December 31, 2014 as compared to $199.7 million for the year ended December 31, 2013. Our cost of operations per ton was $56.26 for the year ended December 31, 2014, an increase of $1.89, or 3.5%, from the year ended December 31, 2013. Total cost of operations increased primarily due to production commencing in mid-2014 at our new Pennyrile mine in the Illinois Basin, partially offset by a decrease in tons produced in Central Appalachia, which was in response to weak market conditions for coal from this complex. The increase in the cost of operations on a per ton basis was primarily due to adverse mining conditions at our Hopedale operation, partially offset by a decrease in Central Appalachia due to production at lower cost operations.

Our cost of operations for the Central Appalachia segment decreased by $18.8 million, or 18.8%, to $81.2 million for the year ended December 31, 2014 from $100.0 million for the year ended December 31, 2013. The decrease in total cost of operations was primarily due to a decrease in tons produced for the year ended December 31, 2014 compared to 2013, which was in response to weak market conditions. Our cost of operations per ton decreased to $64.33 per ton for the year ended December 31, 2014 from $66.33 per ton for year ended December 31, 2013. The decrease in cost of operations per ton was primarily due to production at lower cost operations for the year ended December 31, 2014, which was partially offset by higher per ton costs due to the temporarily idling of the Rob Fork facility due to a fire that closed the railroad tunnel to this location during the second quarter of 2014.

In our Northern Appalachia segment, our cost of operations increased by $4.1 million, or 7.8%, to $56.5 million for the year ended December 31, 2014 from $52.4 million for the year ended December 31, 2013. Our cost of operations per ton increased to $55.67 for the year ended December 31, 2014 from $42.79 for the year ended December 31, 2013, an increase of $12.88 per ton, or 30.1%. The increase in total cost of operations and cost of operations per ton was primarily due to adverse mining conditions at our Hopedale operation as discussed earlier. For the year ended December 31, 2014, cost of operations for our Northern Appalachia segment was also impacted by an approximate $0.2 million charge incurred for the write-off of obsolete supplies inventory at our Sands Hill complex.

Cost of operations in our Rhino Western segment increased by $5.3 million, or 17.2%, to $36.0 million for the year ended December 31, 2014 from $30.7 million for the year ended December 31, 2013. Our cost of operations per ton increased to $33.70 for the year ended December 31, 2014 from $32.62 for the year ended December 31, 2013, an increase of $1.08 per ton, or 3.3%. The increases in cost of operations and cost of operations per ton were primarily due to abnormally high maintenance and other expenses at our Castle Valley mine.

Cost of operations in our Illinois Basin segment was $12.0 million while cost of operations per ton was $56.35 for the year ended December 31, 2014, both of which related to our new Pennyrile mining complex in western Kentucky.

Cost of operations in our Other category decreased by $2.4 million to $14.5 million for the year ended December 31, 2014 compared to $16.9 million the year ended December 31, 2013. This decrease was primarily due to lower costs from our Razorback drill pad construction company due to fewer drill pads completed during the year ended December 31, 2014 compared to 2013.

Freight and Handling. Total freight and handling cost for the year ended December 31, 2014 increased by $0.6 million, or 45.1%, to $1.9 million from $1.3 million for the year ended December 31, 2013. This increase was primarily due to the increase in tons of coal sold for 2014 compared to 2013 from our Sands Hill complex that required transportation by truck to customers' locations.

Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2014 was $37.2 million as compared to $39.6 million for the year ended December 31, 2013.

For the year ended December 31, 2014, our depreciation cost was $30.5 million as compared to $31.5 million for the year ended December 31, 2013. This decrease is primarily due to a decrease in machinery and equipment depreciation from our Central Appalachia operations as excess equipment was disposed as coal production decreased due to weakness in the met and steam coal markets.

For the year ended December 31, 2014, our depletion cost was $4.7 million as compared to $5.4 million for the year ended December 31, 2013. This decrease is primarily attributable to a decrease in depletion cost from fewer tons produced for the year ended December 31, 2014 compared to 2013 due to weakness in the met and steam coal markets.

For the year ended December 31, 2014, our amortization cost was $2.0 million as compared to $2.7 million for the year ended December 31, 2013. This decrease is primarily attributable to lower amortization costs of mine development in Central Appalachia due to changes in mining plans in response to weakness in the met and steam coal markets.

Selling, General and Administrative. Selling, general and administrative ("SG&A") expense for the year ended December 31, 2014 decreased to $19.3 million as compared to $19.8 million for the year ended December 31, 2013. For the year ended December 31, 2014, SG&A was impacted by an approximate $0.7 million charge for an accounts receivable allowance related to one of our Central Appalachia customers that entered bankruptcy proceedings.

Interest Expense. Interest expense for the year ended December 31, 2014 was $5.7 million as compared to $7.9 million for the year ended December 31, 2013, a decrease of $2.2 million, or 27.7%. This decrease was primarily due a lower balance on our revolving credit facility, partially offset by the write-off of approximately $1.1 million of a portion of our unamortized debt issuance costs. This write-off was due to an amendment of our credit facility that reduced the borrowing capacity from $300 million to $200 million. See the discussion on our credit agreement in the Liquidity section that follows for more information on this amendment.

Eastern Met Supplemental Data. Operational and financial data for the Rhino Eastern joint venture in which we had a 51% membership interest and for which we served 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 accounted for this operation under the equity method. We only recorded 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 contributed to our overall performance. The Rhino Eastern joint venture was dissolved in January 2015.

The decrease in tons produced and sold for the year ended December 31, 2014 compared to 2013 was due to weakness in the met coal market, which resulted in a significant decrease in the market price for the quality of met coal that Rhino Eastern produced. The decrease in tons sold resulted in decreased revenue and a larger net loss for the year ended December 31, 2014 compared to 2013.

Net Income (Loss) from Continuing Operations. The following table presents net income (loss) from continuing operations by reportable segment for the years ended December 31, 2014 and 2013:

For the year ended December 31, 2014, total net loss from continuing operations was a loss of approximately $81.3 million compared to net income from continuing operations of approximately $8.1 million for the year ended December 31, 2013. Our net loss from continuing operations was negatively impacted by approximately $45.3 million of asset impairment and related charges along with other non-cash charges. Our net loss from continuing operations for the year ended December 31, 2014 was also negatively impacted by a $5.9 million impairment charge related to our Rhino Eastern joint

venture. For the year ended December 31, 2013, our net income was positively impacted by $10.5 million from the sale of our royalty interest in our separately owned Utica Shale oil and natural gas properties. Including our income from discontinued operations of approximately $130.3 million, our net income for the year ended December 31, 2014 was approximately $49.0 million. Our income from discontinued operations for the year ended December 31, 2014 consisted primarily of the approximately $121.7 million gain from the sale of our Utica Shale oil and natural gas joint interest properties to Gulfport. Income from discontinued operations of approximately $1.3 million for the year ended December 31, 2013 resulted in net income of approximately $9.4 million as the Utica Shale oil and gas joint interest properties had limited production and sales during the year ended 2013.

For our Central Appalachia segment, net loss from continuing operations was approximately $33.0 million for the year ended December 31, 2014, a $25.9 million larger net loss as compared to the year ended December 31, 2013. The loss from continuing operations for the year ended December 31, 2014 was primarily due to asset impairment and related charges of $14.4 million along with a $0.8 million charge for a market-to-market inventory adjustment and an approximate $0.7 million charge for an accounts receivable allowance for one of our customers that entered bankruptcy proceedings. For the year ended December 31, 2014, the ongoing weakness in the met and steam coal markets also negatively impacted the results from our Central Appalachia segment. For the year ended December 31, 2013, net loss from continuing operations was impacted by an approximate $0.9 million charge incurred for the write-off of a continuous miner that was destroyed at one of our underground Central Appalachia mines.

Net income from continuing operations in our Northern Appalachia segment decreased by $24.0 million to $2.1 million for the year ended December 31, 2014, from $26.1 million for the year ended December 31, 2013. This decrease was primarily due to higher costs attributable to difficult mining conditions at our Hopedale complex that were discussed earlier as well as fewer tons sold at our Hopedale complex due to railroad transportation constraints. For the year ended December 31, 2014, net loss from continuing operations for our Northern Appalachia segment was impacted by an approximate $0.2 million charge incurred for the write-off of obsolete supplies inventory at our Sands Hill complex. For the year ended December 31, 2013, net income from continuing operations in our Northern Appalachia segment was positively impacted by $10.5 million from the sale of our 20% royalty interest in our separately owned Utica Shale property.

Net loss from continuing operations in our Rhino Western segment was $22.8 million for the year ended December 31, 2014, compared to a net loss from continuing operations of $2.4 million for the year ended December 31, 2013. This decrease in net loss from continuing operations was primarily due to asset impairment and related charges of $22.6 million that were discussed earlier. For the year ended December 31, 2013, net loss from continuing operations for our Rhino Western segment was impacted from an asset impairment loss of approximately $1.7 million due to permanently idling our McClane Canyon mine at the end of 2013.

For our Illinois Basin segment, we generated a net loss from continuing operations of $6.4 million for the year ended December 31, 2014 as we incurred additional costs at the new Pennyrile mining complex, which began its initial production and sales in mid-2014.

Our Eastern Met segment recorded a net loss from continuing operations of $12.1 million for the year ended December 31, 2014 compared to a net loss from continuing operations of $4.3 million for the year ended December 31, 2013. The net loss for the year ended December 31, 2014 includes a $5.9 million impairment charge of the joint venture discussed earlier. Our net loss from continuing operations also increased from 2013 at Rhino Eastern as weak pricing in the met coal market continued to cause Rhino Eastern to generate a net loss from continuing operations for the year ended December 31, 2014.

For the Other category, we had a net loss from continuing operations of $9.1 million for the year ended December 31, 2014, which was a $5.1 million larger loss as compared to a net loss from continuing operations of $4.0 million for the year ended December 31, 2013. The increase in the net loss from continuing operations was primarily due to $8.3 million of asset impairment and related charges associated with our undeveloped Rich Mountain property that was discussed earlier. These asset impairment and related charges were partially offset by decreased costs in 2014 compared to 2013 in our ancillary businesses that support our coal operations.

Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the years ended December 31, 2014 and 2013:

Adjusted EBITDA from continuing operations for the year ended December 31, 2014 was $15.5 million, a decrease of $43.7 million from the year ended December 31, 2013. Adjusted EBITDA from continuing operations decreased primarily as a result of a decrease in net income from continuing operations, as described previously. Adjusted EBITDA for the year ended December 31, 2014 and 2013 was $145.8 million and $63.5 million. The increase in Adjusted EBITDA year to year was primarily attributable to the approximately $121.7 million gain from the sale of our Utica Shale oil and natural gas properties, as well as the $8.4 million gain recognized from the sale of Blackhawk. Please read "—Reconciliation of Adjusted EBITDA to Net Income by Segment" for reconciliations of Adjusted EBITDA from continuing operations to net income on a segment basis.

Summary. For the year ended December 31, 2013, our total revenues decreased to $272.2 million from $351.7 million for the year ended December 31, 2012. We sold 3.7 million tons of coal for the year ended December 31, 2013, which is 1.0 million tons less, or a 21.4% decrease, than the 4.7 million tons of coal sold for the year ended December 31, 2012. This decrease in tons sold was the result of weak demand in the steam coal markets, which resulted in lower coal revenues for 2013 compared to 2012. Coal revenues in 2013 were also negatively impacted by weak met coal prices compared to 2012 levels. We believe the weak demand in the steam coal markets was primarily driven by an over-supply of low priced natural gas that increased stockpiles of coal at electric utilities. We believe utilities are still working to decrease their coal stockpiles, which has extended the weakness in the steam coal markets even though natural gas prices have risen from their previous historic lows. We believe the weak prices in the met coal markets were primarily driven by a decrease in world-wide steel production due to economic weakness in China and Europe.

For the year ended December 31, 2013, our coal inventories decreased by approximately 28,000 tons from the year ended December 31, 2012 as we lowered production levels and sold excess inventory tons.

Net income from continuing operations was $8.1 million for the year ended December 31, 2013 compared to $39.4 million for the year ended December 31, 2012. Adjusted EBITDA from continuing operations decreased to $59.2 million for the year ended December 31, 2013, from $89.6 million for the year ended December 31, 2012. Net income from continuing operations and Adjusted EBITDA from continuing operations decreased year to year as reductions in costs were offset by lower coal revenues. For the year ended December 31, 2013, our net income from continuing operations and Adjusted EBITDA from continuing operations was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property, while net income for this period was negatively impacted by approximately $0.9 million due to the non-cash write-off of a continuous miner that was damaged at one of our Central Appalachia underground mines and by approximately $1.7 million due to an asset impairment loss from permanently idling our McClane Canyon mine. For the year ended December 31, 2012, net income from continuing operations and Adjusted EBITDA from continuing operations was positively impacted by the $7.4 million lease bonus payments received for our Utica Shale acreage, which had relatively immaterial costs associated with the transaction. The Utica Shale transactions discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why these transactions are included in continuing operations. Net income from continuing operations and Adjusted EBITDA from continuing operations were negatively impacted in 2013 due to approximately $4.3 million of net loss from our Rhino Eastern joint venture compared to income of $6.0 million for 2012, 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.

Including the income from discontinued operations of approximately $1.3 million from our Utica Shale activities, our net income for the year ended December 31, 2013 was approximately $9.4 million and our Adjusted EBITDA was $63.5 million when our discontinued operations items are included. Including discontinued operations items for the year ended December 31, 2012, our net income and Adjusted EBITDA were approximately $39.5 million and $89.8 million, respectively. The year to year decrease in net income and Adjusted EBITDA are due to the same factors discussed above for the year to year decrease in net income from continuing operations and Adjusted EBITDA from continuing operations.

Tons Sold. The following table presents tons of coal sold by reportable segment for the years ended December 31, 2013 and 2012:

We sold approximately 3.7 million tons of coal in the year ended December 31, 2013 as compared to approximately 4.7 million tons sold for the year ended December 31, 2012. This decrease in tons sold was primarily due to weakness in the steam coal markets, primarily in Northern Appalachia and Central Appalachia. Tons of coal sold in our Central Appalachia segment decreased by approximately 0.3 million, or 14.1%, to approximately 1.5 million tons for the year ended December 31, 2013 from approximately 1.8 million tons for the year ended December 31, 2012. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the steam coal markets, partially offset by an increase in met coal tons sold as met coal sales in the spot market increased in 2013 compared to 2012. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.7 million, or 34.7%, to approximately 1.2 million tons for the year ended December 31, 2013 from approximately 1.9 million tons for the year ended December 31, 2012. The decrease in total tons sold year-to-year was primarily due to lower sales from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened year-to-year, as well as slightly fewer tons sold at our Hopedale complex. Coal sales from our Rhino Western segment decreased by approximately 0.1 million, or 9.5%, to approximately 0.9 million tons for the year ended December 31, 2013 from approximately 1.0 million tons for the year ended December 31, 2012 as our Castle Valley mine continued to fulfill contracted customer shipments, but had fewer spot sales in 2013 compared to 2012.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2013 and 2012:

Segment	Year ended December 31, 2013		Year ended December 31, 2012		Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	126.4	$	161.3	$	(34.9	)	(21.6	)%
Freight and handling revenues		—		—		—		n/a
Other revenues		21.0		22.1		(1.1	)	(4.9	)%

Total revenues	$	147.4	$	183.4	$	(36.0	)	(19.6	)%



Coal revenues per ton*	$	83.85	$	91.83	$	(7.98	)	(8.7	)%
Northern Appalachia
Coal revenues	$	72.2	$	102.9	$	(30.7	)	(29.8	)%
Freight and handling revenues		2.2		6.3		(4.1	)	(66.1	)%
Other revenues		6.0		12.8		(6.8	)	(52.9	)%

Total revenues	$	80.4	$	122.0	$	(41.6	)	(34.1	)%



Coal revenues per ton*	$	58.95	$	54.87	$	4.08		7.4	%
Rhino Western
Coal revenues	$	38.0	$	40.4	$	(2.4	)	(6.1	)%
Freight and handling revenues		—		—		—		n/a
Other revenues		0.3		0.3		—		0.3	%

Total revenues	$	38.3	$	40.7	$	(2.4	)	(6.0	)%



Coal revenues per ton*	$	40.37	$	38.89	$	1.48		3.8	%
Illinois Basin
Coal revenues	$	—	$	—	$	—		n/a
Freight and handling revenues		—		—		—		n/a
Other revenues		0.3		0.2		0.1		16.8	%

Total revenues	$	0.3	$	0.2	$	0.1		16.8	%



Coal revenues per ton*	$	—	$	—	$	—		n/a
Other**
Coal revenues		n/a		n/a		n/a		n/a
Freight and handling revenues		n/a		n/a		n/a		n/a
Other revenues	$	5.8	$	5.4	$	0.4		9.1	%

Total revenues	$	5.8	$	5.4	$	0.4		9.1	%



Coal revenues per ton*		n/a		n/a		n/a		n/a
Total
Coal revenues	$	236.6	$	304.6	$	(68.0	)	(22.3	)%
Freight and handling revenues		2.2		6.3		(4.1	)	(66.0	)%
Other revenues		33.4		40.8		(7.4	)	(17.9	)%

Total revenues	$	272.2	$	351.7	$	(79.5	)	(22.6	)%



Coal revenues per ton*	$	64.42	$	65.22	$	(0.80	)	(1.2	)%

Our total revenues for the year ended December 31, 2013 decreased by $79.5 million, or 22.6%, to $272.2 million from $351.7 million for the year ended December 31, 2012. The decrease in total revenues was primarily due to lower coal revenues from fewer steam coal tons sold and lower met coal prices in Central Appalachia, as well as fewer tons sold from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened year-to-year. Coal revenues per ton were $64.42 for the year ended December 31, 2013, a decrease of $0.80, or 1.2%, from $65.22 per ton for the year ended December 31, 2012. This decrease in coal revenues per ton was primarily the result of lower prices for met coal sold in Central Appalachia, partially offset by an increase in coal revenues per ton in our Northern Appalachia segment primarily due to fewer lower priced tons being sold from our Sands Hill complex in 2013 compared to 2012.

For our Central Appalachia segment, coal revenues decreased by $34.9 million, or 21.6%, to $126.4 million for the year ended December 31, 2013 from $161.3 million for the year ended December 31, 2012 primarily due to fewer steam coal tons sold and a decrease in the price for met coal tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $7.98, or 8.7%, to $83.85 per ton for the year ended December 31, 2013 as compared to $91.83 for the year ended December 31, 2012, primarily due to lower price for metallurgical coal sold. Other revenues decreased for our Central Appalachia segment primarily due to lower coal royalty revenue from our coal leasing operations as our lessees had lower selling prices for their coal in 2013 compared to 2012.

For our Northern Appalachia segment, coal revenues were $72.2 million for the year ended December 31, 2013, a decrease of $30.7 million, or 29.8%, from $102.9 million for the year ended December 31, 2012. This decrease was primarily due to fewer tons sold from our Sands Hill complex in Northern Appalachia as mentioned earlier and slightly fewer tons sold at our Hopedale complex. Coal revenues per ton for our Northern Appalachia segment increased by $4.08, or 7.4%, to $58.95 per ton for the year ended December 31, 2013 as compared to $54.87 per ton for the year ended December 31, 2012. This increase was primarily due to fewer lower priced tons being sold from our Sands Hill complex as market conditions for coal from this operation weakened year-to-year. Other revenues decreased for our Northern Appalachia segment primarily due to the $7.4 million lease bonus received in 2012 for acreage owned in the Utica Shale region that was not present in the 2013 comparable period. The Utica Shale transaction discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why this transaction is included in continuing operations.

For our Rhino Western segment, coal revenues decreased by $2.4 million, or 6.1%, to $38.0 million for the year ended December 31, 2013 from $40.4 million for the year ended December 31, 2012 due to slightly fewer tons sold from our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $40.37 for the year ended December 31, 2013, an increase of $1.48, or 3.8%, from $38.89 for the year ended December 31, 2012. The increase in coal revenues per ton was due to a decrease in lower-priced spot sales from our Castle Valley mine in 2013 when compared to 2012.

Four our Illinois Basin segment, other revenue increased slightly as we had higher rental income in 2013 as compared to the same 2012 period for a portion of our Taylorville field property in central Illinois.

Other revenues for our Other category increased by $0.4 million for the year ended December 31, 2013 from the year ended December 31, 2012. The increase in other revenues was primarily due to our Razorback drill pad service company that began generating revenue in 2013, partially offset by the sale of our Triad roof bolt manufacturing operation in September 2012, which generated revenue in 2012 that is not present in the 2013 comparable period.

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.

Segment	Year ended December 31, 2013			Year ended December 31, 2012		Increase/ (Decrease) $

	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	100.0		$	125.8	$	(25.8	)	(20.5	)%
Freight and handling costs		0.3			0.5		(0.2	)	(44.8	)%
Depreciation, depletion and amortization		24.2			26.3		(2.1	)	(7.8	)%
Selling, general and administrative		18.5			19.0		(0.5	)	(2.5	)%
Cost of operations per ton*	$	66.33		$	71.62	$	(5.29	)	(7.4	)%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	52.4		$	76.0	$	(23.6	)	(31.0	)%
Freight and handling costs		1.0			5.3		(4.3	)	(80.9	)%
Depreciation, depletion and amortization		8.1			8.3		(0.2	)	(2.5	)%
Selling, general and administrative		0.3			0.3		—		(17.6	)%
Cost of operations per ton*	$	42.79		$	40.54	$	2.25		5.5	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	30.7		$	27.5	$	3.2		11.7	%
Freight and handling costs		—			—		—		n/a
Depreciation, depletion and amortization		5.5			4.7		0.8		17.7	%
Selling, general and administrative		0.1			0.1		—		(5.4	)%
Cost of operations per ton*	$	32.62		$	26.42	$	6.20		23.5	%
Illinois Basin
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	(0.3	)	$	0.3	$	(0.6	)	n/a
Freight and handling costs		—			—		—		n/a
Depreciation, depletion and amortization		0.3			—		0.3		n/a
Selling, general and administrative		—			—		—		n/a
Cost of operations per ton*	$	—		$	—	$	—		n/a
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	16.9		$	18.1	$	(1.2	)	(7.0	)%
Freight and handling costs		—			—		—		n/a
Depreciation, depletion and amortization		1.5			2.0		(0.5	)	(24.6	)%
Selling, general and administrative		0.9			1.1		(0.2	)	(14.2	)%
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)	$	199.7		$	247.7	$	(48.0	)	(19.4	)%
Freight and handling costs		1.3			5.8		(4.5	)	(77.8	)%
Depreciation, depletion and amortization		39.6			41.3		(1.7	)	(4.0	)%
Selling, general and administrative		19.8			20.5		(0.7	)	(3.1	)%
Cost of operations per ton*	$	54.37		$	53.04	$	1.33		2.5	%

Cost of Operations. Total cost of operations was $199.7 million for the year ended December 31, 2013 as compared to $247.7 million for the year ended December 31, 2012. Total cost of operations decreased primarily due to lower production at our Sands Hill complex in Northern Appalachia, which was in response to weak market conditions for coal from this complex, as well as decreased costs from purchased coal in Central Appalachia. Our cost of operations per ton was $54.37 for the year ended December 31, 2013; an increase of $1.33, or 2.5%, from the year ended December 31, 2012. The increase in the cost of operations on a per ton basis was primarily due to the sequence of mining at our Castle Valley mine in our Rhino Western segment where we performed more higher cost advance mining during 2013 compared to more lower cost retreat mining that was performed in 2012.

Our cost of operations for the Central Appalachia segment decreased by $25.8 million, or 20.5%, to $100.0 million for the year ended December 31, 2013 from $125.8 million for the year ended December 31, 2012. Our total cost of operations decreased for Central Appalachia primarily due to decreased costs from purchased coal in 2013 compared to 2012. Our cost of operations per ton decreased to $66.33 per ton for the year ended December 31, 2013 from $71.62 per ton for year ended December 31, 2012. The decrease in cost of operations per ton was primarily due to the fact that we idled a majority of the Central Appalachia operations in June and early July of 2012 in order to reduce higher than normal inventory levels, which resulted in a higher cost per ton figure for the 2012 period when compared to 2013.

In our Northern Appalachia segment, our cost of operations decreased by $23.6 million, or 31.0%, to $52.4 million for the year ended December 31, 2013 from $76.0 million for the year ended December 31, 2012. The decrease in cost of operations was primarily due to lower production at our Sands Hill complex in Northern Appalachia, which was in response to weak market conditions for coal from this complex. Our cost of operations per ton increased to $42.79 for the year ended December 31, 2013 from $40.54 for the year ended December 31, 2012, an increase of $2.25 per ton, or 5.5%. The increase in cost of operations per ton was primarily due to reducing production volumes at Sands Hill.

Cost of operations in our Rhino Western segment increased by $3.2 million, or 11.7%, to $30.7 million for the year ended December 31, 2013 from $27.5 million for the year ended December 31, 2012. Our cost of operations per ton increased to $32.62 for the year ended December 31, 2013 from $26.42 for the year ended December 31, 2012, an increase of $6.20 per ton, or 23.5%. The increases in cost of operations and cost of operations per ton were primarily due to the sequence of mining at our Castle Valley mine. During 2013, the mine was primarily advancing the sections which drove higher cost compared to the lower-cost retreat mining that was performed in 2012.

Cost of operations in our Illinois Basin segment decreased by $0.6 million for the year ended December 31, 2013 compared to the same 2012 period as the development of our new Pennyrile mine in western Kentucky experienced a credit to cost due to our inter-company development cost allocation process.

Cost of operations in our Other category decreased by $1.2 million to $16.9 million for the year ended December 31, 2013 compared to $18.1 million the year ended December 31, 2012. This decrease was primarily due to the sale of our Triad roof bolt manufacturing operation in September 2012, which incurred cost in 2012 that is not present in the 2013 comparable period.

Freight and Handling. Total freight and handling cost for the year ended December 31, 2013 decreased by $4.5 million, or 77.8%, to $1.3 million from $5.8 million for the year ended December 31, 2012. This decrease was primarily due to the decrease in tons of coal sold for 2013 compared to 2012 from our Sands Hill complex, which requires transportation by truck to customers' locations.

Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2013 was $39.6 million as compared to $41.3 million for the year ended December 31, 2012.

For the year ended December 31, 2013, our depreciation cost was $31.5 million as compared to $32.7 million for the year ended December 31, 2012. This decrease is primarily due to a decrease in machinery and equipment depreciation from our Central Appalachia operations.

For the year ended December 31, 2013, our depletion cost was $5.4 million as compared to $5.8 million for the year ended December 31, 2012. This decrease is primarily attributable to fewer tons produced for the year ended December 31, 2013 compared to 2012 due to weakness in the met and steam coal markets.

For the year ended December 31, 2013, our amortization cost was relatively flat at $2.7 million as compared to $2.8 million for the year ended December 31, 2012.

Selling, General and Administrative. Selling, general and administrative expense for the year ended December 31, 2013 was $19.8 million as compared to $20.5 million for the year ended December 31, 2012. 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, 2013 was $7.9 million as compared to $7.8 million for the year ended December 31, 2012, an increase of $0.1 million, or 1.7%. This increase was the result of an increase in the balance outstanding under our credit facility.

The decrease in tons produced and sold for the year ended December 31, 2013 compared to 2012 was due to weakness in the met coal market, which resulted in a significant decrease in the market

price for the quality of met coal that Rhino Eastern produces. The decrease in tons sold resulted in decreased revenue and net income for the year ended December 31, 2013 compared to the same period in 2012.

Net Income (Loss) from Continuing Operations. The following table presents net income (loss) from continuing operations by reportable segment for the years ended December 31, 2013 and 2012:

For the year ended December 31, 2013, net income from continuing operations was $8.1 million compared to $39.4 million for the year ended December 31, 2012 as decreases in costs and expenses were offset by decreases in coal revenues, including lower royalty revenue from our coal leasing business, as well as lower results from our Rhino Eastern joint venture. For the year ended December 31, 2013, our net income from continuing operations was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property. Net income from continuing operations 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. The Utica Shale transactions discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why these transactions are included in continuing operations.

For our Central Appalachia segment, we generated a net loss from continuing operations of approximately $7.1 million for the year ended December 31, 2013, a decrease of $10.7 million, as compared to the year ended December 31, 2012. The year to year decrease was primarily due to a decrease in tons sold, which decreased revenue, and an approximate $0.9 million charge incurred for the write-off of a continuous miner that was destroyed at one of our underground Central Appalachia mines.

Net income from continuing operations in our Northern Appalachia segment decreased by $3.5 million to $26.1 million for the year ended December 31, 2013, from $29.6 million for the year ended December 31, 2012. Net income from continuing operations in our Northern Appalachia segment was impacted from the $10.5 million received from the sale of our 20% royalty interest on our Utica Shale property in the year ended December 31, 2013 as compared to approximately $7.4 million of lease bonus payments that we received on our Utica Shale property in the year ended December 31, 2012. The increase period to period due to the Utica Shale payments received was partially offset by decreased tons of coal sold from our Sands Hill complex due to weakness in the steam coal market. The Utica Shale transactions discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why these transactions are included in continuing operations.

Net income from continuing operations in our Rhino Western segment decreased by $8.1 million to a loss of $2.4 million for the year ended December 31, 2013, compared to net income from continuing operations of $5.7 million for the year ended December 31, 2012. This decrease was primarily the result of an increase in cost of operations at our Castle Valley operation due to the sequence of mining discussed earlier, as well as decreased revenue from lower tons sold at Castle Valley due to fewer spot sales. Net income from continuing operations for our Rhino Western segment was also impacted from an asset impairment loss of approximately $1.7 million due to the permanently idling of our McClane Canyon mine at the end of 2013.

For our Illinois Basin segment, our net loss from continuing operations was $0.2 million for the year ended December 31, 2013, compared to net loss from continuing operations of $0.4 million for the year ended December 31, 2012. The smaller net loss was primarily due to lower costs in 2013 compared to 2012.

Our Eastern Met segment recorded a net loss from continuing operations of $4.3 million for the year ended December 31, 2013, a decrease of $10.3 million from net income from continuing operations of $6.0 million for the year ended December 31, 2012, as weakness in the met coal market caused a decrease in the number of tons sold and lower prices for tons sold.

For the Other category, we had a net loss from continuing operations of $4.0 million for the year ended December 31, 2013, a benefit of $1.1 million as compared to a net loss from continuing operations of $5.1 million for the year ended December 31, 2012. The improvement was primarily due to decreased costs in 2013 compared to 2012 in our ancillary businesses that support our coal operations.

Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the years ended December 31, 2013 and 2012:

Adjusted EBITDA from continuing operations for the year ended December 31, 2013 was $59.2 million, a decrease of $30.4 million from $89.6 million for the year ended December 31, 2012. Adjusted EBITDA from continuing operations decreased primarily as a result of a decrease in net income from continuing operations, as described previously. Please read "—Reconciliation of Adjusted EBITDA to Net Income by Segment" for reconciliations of Adjusted EBITDA from continuing operations to net income from continuing operations on a segment basis.

The following tables present reconciliations of Adjusted EBITDA to net income/(loss) from continuing operations 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 was recognized as a single line item in our financial statements was 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.

Year ended December 31, 2014	Central Appalachia			Northern Appalachia		Rhino Western			Illinois Basin			Eastern Met*			Other			Total

	(in millions)
Net (loss)/income from continuing operations	$	(33.0	)	$	2.1	$	(22.8	)	$	(6.4	)	$	(12.1	)	$	(9.1	)	$	(81.3	)
Plus:
DD&A		20.2			7.6		6.0			2.3			—			1.1			37.2
Interest expense		2.0			0.5		0.3			0.3			—			2.6			5.7

EBITDA from continuing operations†**	$	(10.8	)	$	10.2	$	(16.5	)	$	(3.8	)	$	(12.1	)	$	(5.4	)	$	(38.4	)



Plus: Rhino Eastern DD&A-51%		—			—		—			—			1.0			—			1.0
Plus: Rhino Eastern interest expense-51%		—			—		—			—			—			—			—
Plus: Non-cash asset impairment and other non-cash charges ***		16.0			0.2		22.6			—			5.9			8.2			52.9

Adjusted EBITDA from continuing operations†		5.2			10.4		6.1			(3.8	)		(5.2	)		2.8			15.5

Net income from discontinued operations		—			—		—			—			—			—			130.3
DD&A included in net income from discontinued operations		—			—		—			—			—			—			—

Adjusted EBITDA†	$	5.2		$	10.4	$	6.1		$	(3.8	)	$	(5.2	)	$	2.8		$	145.8

Year ended December 31, 2013	Central Appalachia			Northern Appalachia		Rhino Western			Illinois Basin			Eastern Met*			Other			Total

	(in millions)
Net (loss)/income from continuing operations	$	(7.1	)	$	26.1	$	(2.4	)	$	(0.2	)	$	(4.3	)	$	(4.0	)	$	8.1
Plus:
DD&A		24.2			8.1		5.5			0.3			—			1.5			39.6
Interest expense		3.9			0.8		0.6			0.2			—			2.4			7.9

EBITDA from continuing operations†**	$	21.0		$	35.0	$	3.7		$	0.3		$	(4.3	)	$	(0.1	)	$	55.6



Plus: Rhino Eastern DD&A-51%		—			—		—			—			1.0			—			1.0
Plus: Rhino Eastern interest expense-51%		—			—		—			—			—			—			—
Plus: Non-cash write-off of mining equipment and asset impairment****		0.9			—		1.7			—			—			—			2.6

Adjusted EBITDA from continuing operations†		21.9			35.0		5.4			0.3			(3.3	)		(0.1	)		59.2

Net income from discontinued operations		—			—		—			—			—			—			1.3
DD&A included in net income from discontinued operations		—			—		—			—			—			—			3.0

Adjusted EBITDA†	$	21.9		$	35.0	$	5.4		$	0.3		$	(3.3	)	$	(0.1	)	$	63.5

Year ended December 31, 2012	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin			Eastern Met*		Other			Total**

	(in millions)
Net income/(loss) from continuing operations	$	3.6	$	29.6	$	5.7	$	(0.4	)	$	6.0	$	(5.1	)	$	39.4
Plus:
DD&A		26.3		8.3		4.7		—			—		2.0			41.3
Interest expense		4.4		0.8		0.7		0.2			—		1.7			7.8

EBITDA from continuing operations†**	$	34.3	$	38.7	$	11.1	$	(0.2	)	$	6.0	$	(1.4	)	$	88.5



Plus: Rhino Eastern DD&A-51%		—		—		—		—			1.0		—			1.0
Plus: Rhino Eastern interest expense-51%		—		—		—		—			0.1		—			0.1

Adjusted EBITDA from continuing operations†		34.3		38.7		11.1		(0.2	)		7.1		(1.4	)		89.6

Net income from discontinued operations		—		—		—		—			—		—			0.1
DD&A included in net income from discontinued operations		—		—		—		—			—		—			0.1

Adjusted EBITDA†	$	34.3	$	38.7	$	11.1	$	(0.2	)	$	7.1	$	(1.4	)	$	89.8

*: Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
†: Calculated based on actual amounts and not the rounded amounts presented in this table.
**: Totals may not foot due to rounding
***: For the total $52.9 million of non-cash charges incurred during the year ended December 31, 2014, approximately $45.3 million related to asset impairment and related charges associated with our various mining properties that were evaluated for impairment and reduced to our estimate of fair value during the fourth quarter of 2014. An additional component of the $52.9 million of non-cash charges relates to the $5.9 million impairment charge for our Rhino Eastern joint venture. Please see our more detailed discussion of these asset impairment and related charges that is included earlier in this section. During the fourth quarter of 2014, we also incurred other non-cash charges that included an approximate $0.8 million mark-to-market adjustment for a portion of our low quality steam coal inventory located in Central Appalachia, an approximate $0.7 million charge for an accounts receivable allowance for one of our customers in Central Appalachia that entered bankruptcy proceedings and an approximate $0.2 million charge incurred for the write-off of obsolete supplies inventory at one of our Northern Appalachia operations. A summary of these charges is detailed in the table below:

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, 2014, our available liquidity was $127.3 million, including cash on hand of $0.6 million and $126.7 million of available borrowing capacity under our credit agreement. The amount available under our credit agreement is based upon a maximum borrowing capacity of 3.5 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement).

With respect to the quarters ended September 30, 2014 and December 31, 2014, we reduced our quarterly cash distribution to $0.05 per common unit, or $0.20 per unit on an annualized basis, compared to the previous quarters' distribution amount of $0.445 per common unit, or $1.78 per unit on an annualized basis. The distribution reduction was the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow. The distribution reduction is designed to preserve liquidity to ensure we meet our future financial requirements described above and to enhance our long-term value

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

Net cash provided by operating activities was $21.2 million for the year ended December 31, 2014 as compared to $51.7 million for the year ended December 31, 2013. This decrease in cash provided by operating activities was primarily the result of lower net income from continuing operations, which resulted from decreased tons of coal sold and coal revenue.

Net cash provided by investing activities was $116.7 million for the year ended December 31, 2014 as compared to net cash used in investing activities of $43.9 million for the year ended December 31, 2013. The increase in cash provided by investing activities was primarily due to the proceeds received from the sale of our Utica Shale oil and natural gas assets during the year ended December 31, 2014, partially offset by an increase in additions to property, plant and equipment that were primarily due to the development of our new Pennyrile mine in western Kentucky.

Net cash used in financing activities for the year ended December 31, 2014 was $137.7 million, which was primarily attributable to repayments on debt during this period with the proceeds from the Utica Shale oil and natural gas property sale, along with distributions paid to unitholders. Net cash used in financing activities for the year ended December 31, 2013 was $7.9 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 used in financing activities for the year ended December 31, 2013 also included the net proceeds from our public offering of common units, which resulted in net proceeds after offering expenses of approximately $14.6 million that was used to repay outstanding debt.

Net cash provided by operating activities was $51.7 million for the year ended December 31, 2013 as compared to $79.7 million for the year ended December 31, 2012. This decrease in cash provided by operating activities was primarily the result of lower net income, which resulted from decreased tons sold and revenue as well as unfavorable results from our Rhino Eastern joint venture.

Net cash used in investing activities was $43.9 million for the year ended December 31, 2013 as compared to $58.4 million for the year ended December 31, 2012. The decrease in cash used in investing activities was primarily due to the decreased amounts expended for the purchase and construction of mining equipment. For the year ended December 31, 2012, our primary expenditures related to the new preparation plant in our Tug River mining complex, which resulted in increased expenditures when compared to the year ended December 31, 2013. In addition, the $10.5 million received from the sale of our 20% royalty interest on our Utica Shale property in the year ended December 31, 2013 resulted in lower net cash used in investing activities when compared to 2012.

Net cash used in financing activities for the year ended December 31, 2013 was $7.9 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 used in financing activities for the year ended December 31, 2013 also included the net proceeds from our public offering of common units, which resulted in net proceeds after offering expenses of approximately $14.6 million that was used to repay outstanding debt. 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.

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, 2014 were approximately $12.2 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the year ended December 31, 2014 were approximately $50.8 million, which were primarily related to the development of our new Riveredge

mine on our Pennyrile property in western Kentucky. For the year ending December 31, 2015, we have budgeted $10 million to $13 million for maintenance capital expenditures. We expect a minimal amount of 2015 expansion capital expenditures since we have completed the development of the Pennyrile mine and we currently do not anticipate developing any of our other internal projects in 2015 due to the current weak coal market conditions.

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 could affect the future distribution amounts paid to our unitholders.

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 was $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 was available for letters of credit. As described below, in March 2014 the amended and restated credit facility was amended and the borrowing capacity under the facility was reduced to $200.0 million, with the amount available for letters of credit unchanged.

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 2.50%, and the applicable margin for the LIBOR option is 2.50% to 3.50%, 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 3.50% 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, 2014, we are in compliance with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.

On April 19, 2013, we entered into an amendment of the amended and restated senior secured credit facility. The amendment provided for an increase in the maximum allowed investments in coal-related entities outside of our current partnership structure (i.e. joint ventures) under the amended and restated senior secured credit facility from $25 million to $40 million. The amendment also altered the maximum leverage ratio allowed under the amended and restated senior secured credit facility and also altered the pricing grid to include applicable interest rates for borrowings, letter of credit fees and commitment fees on unused borrowings based upon the new maximum leverage ratio. The amendment increases the maximum leverage ratio of the amended and restated senior secured credit facility to 3.75 from April 1, 2013 through March 31, 2015, then steps the maximum leverage ratio down to its previous level of 3.0 after December 31, 2015. All other terms of the amended and restated senior secured credit facility were not affected by the amendment.

In March 2014, we entered into a second amendment of our amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. This second amendment permitted us to sell certain assets to Gulfport, as described earlier in the discussion of our oil and natural gas activities, which previously constituted a portion of the collateral under the amended and restated senior secured credit facility. This second amendment also reduced the borrowing capacity under the amended and restated senior secured credit facility to a maximum of $200 million and altered the maximum leverage ratio to 3.5 from January 1, 2014 through September 30, 2015. The maximum leverage ratio decreases to 3.25 from October 1, 2015 through December 31, 2015 and then decreases to 3.0 after December 31, 2015. In addition, the second amendment adjusts the maximum investments (other than directly by us) in hydrocarbons, hydrocarbon interests and assets and activities related to hydrocarbons, in each case, excluding coal, in an aggregate amount not to exceed $50 million. All other terms of the amended and restated senior secured credit facility were not affected by the second amendment.

At December 31, 2014, $54.5 million was outstanding under the facility at a variable interest rate of LIBOR plus 2.50% (2.66% at December 31, 2014). In addition, we had outstanding letters of credit of approximately $15.8 million at a fixed interest rate of 2.50% at December 31, 2014. Based upon a maximum borrowing capacity of 3.5 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), we had not used $126.7 million of the borrowing availability at December 31, 2014. During the three month period ended December 31, 2014, we had average borrowings outstanding of approximately $54.3 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, 2014, we had $15.8 million in letters of credit outstanding, of which $10.9 million served as collateral for approximately $70.2 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, 2014:

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 13 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.

Investments in joint ventures 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 21 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, 2014, 2013 and 2012, 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 and the fact that the Rhino Eastern joint venture is managed by a committee of an equal number of representatives from Patriot and us. 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.

In January 2015, we completed a Membership Transfer Agreement (the "Transfer Agreement") with an affiliate of Patriot that terminated the Rhino Eastern joint venture. Pursuant to the Transfer Agreement, Patriot sold and assigned its 49% membership interest in the Rhino Eastern joint venture to us and, in consideration of this transfer, Patriot received certain fixed assets, leased equipment and coal reserves associated with the mining area previously operated by the Rhino Eastern joint venture. Patriot also assumed substantially all of the active workforce related to the Eagle mining area that was previously employed by the Rhino Eastern joint venture. We retained approximately 34 million tons of coal reserves that are not related to the Eagle mining area as well as a prepaid advanced royalty balance of $6.3 million. As part of the closing of the Transfer Agreement, we and Patriot agreed to a dissolution payment based upon a final working capital adjustment calculation as defined in the Transfer Agreement.

As of December 31, 2014 and 2013, we recorded our equity method investment of $13.2 million and $19.4 million, respectively, in the Rhino Eastern joint venture as a long-term asset. As a result of the dissolution of the Rhino Eastern joint venture, we will eliminate the amount recorded as our equity method investment in the Rhino Eastern joint venture during the first quarter of 2015. We recorded an approximate $5.9 million impairment charge as of December 31, 2014 related to our equity investment in Rhino Eastern based upon the fair value of the assets we received and liabilities assumed in the dissolution compared to the amount recorded as our equity method investment in the Rhino Eastern joint venture. During the year ended December 31, 2014, we made capital contributions to the Rhino Eastern joint venture of approximately $4.8 million based upon our proportionate ownership percentage. As disclosed in Note 19 to the audited consolidated financial statements that are included elsewhere in this report, we provided loans to the Rhino Eastern joint venture during 2012 that totaled approximately $11.9 million, which were fully repaid as of December 31, 2012.

Property, plant, and equipment, including coal properties, oil and natural gas 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.

Due to the prolonged weakness in the U.S. coal markets and the dim prospects for an upturn in the coal markets in the near term, in the fourth quarter of 2014, we performed a comprehensive review of our current coal mining operations as well as potential future development projects to ascertain any potential impairment losses. We identified various properties, projects and operations that were potentially impaired based upon changes in our strategic plans, market conditions or other factors. We recorded approximately $45.3 million of impairment and related charges for the year ended December 31, 2014. Refer to Note 6 to the audited consolidated financial statements that are included elsewhere in this report for more information on the asset impairment losses recorded for the year ended December 31, 2014.

During the fourth quarter of 2013, we made a strategic decision to permanently close the mining operations at our McClane Canyon mine in Colorado. Since the McClane Canyon mine had been idled at the end of 2010, we had been actively marketing the coal from this mine to potential buyers, but had not been able to obtain suitable sales contracts. Due to the unfavorable long-term prospects for the coal market in the Colorado area and to avoid the ongoing costs that were being incurred to actively idle this mine, we made the decision to permanently close this operation at the end of 2013. While a

portion of the equipment from this operation was relocated to other operating locations, we incurred an impairment charge of approximately $1.7 million during 2013 related to specific property, plant and equipment at this complex. There were no impairment losses recorded during the year ended December 31, 2012.

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

We estimate our future cost requirements for reclamation of land where we have conducted surface and underground mining operations, based on our interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground 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. Each respective year includes a range of discount rates that are dependent upon the timing of the cash flows of the specific obligations. Changes in the asset retirement obligations for the year ended December 31, 2014 were calculated with discount rates that ranged from 1.6% to 5.3%. Changes in the asset retirement obligations for the year ended December 31, 2013 were calculated with discount rates that ranged from 2.3% to 5.6%. 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%. The discount rates changed from previous years due to changes in applicable market indicators that are used to arrive at an appropriate discount rate. 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 2014, 2013 and 2012.

Certain of our subsidiaries are liable under federal and state laws to pay workers' compensation and coal workers' 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.

Our black lung benefit liability is calculated using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation. The actuarial calculations using the service cost method for our black lung benefit liability are based on numerous

assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates.

In addition, our liability for traumatic workers' compensation injury claims is the estimated present value of current workers' compensation benefits, based on actuarial estimates. The actuarial estimates for our workers' compensation liability are based on numerous assumptions including claim development patterns, mortality, medical costs and interest rates.

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 occasionally use diesel fuel contracts to manage the risk of fluctuations in the cost of diesel fuel. Our diesel fuel contracts meet the requirements 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 April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity" ("ASU 2014-08"). ASU 2014-08 changes the requirements for reporting discontinued operations in Accounting Standards Codification ("ASC") 205, Presentation of Financial Statements, by updating the criteria for determining which disposals can be presented as discontinued operations and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of discontinued operations. ASU 2014-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. We do not anticipate the adoption of ASU 2014-08 on January 1, 2015 will have a material impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"). ASU 2014-09 clarifies the principles for recognizing revenue and establishes a common revenue standard for U.S. financial reporting purposes. The guidance in ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). ASU 2014-09 supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific accounting guidance. Additionally, ASU 2014-09 supersedes some cost guidance included in ASC 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of ASC 360, Property, Plant, and Equipment, and intangible assets within the scope of ASC 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in ASU 2014-09. ASU 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application of ASU 2014-09 is not permitted. We are currently evaluating the requirements of this new accounting guidance.

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, 2014, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

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 $0.2 million for the year ended December 31, 2014. A hypothetical increase of 10% in steel prices would have reduced net income by $0.9 million for the year ended December 31, 2014. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.4 million for the year ended December 31, 2014.

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 $1.1 million for the year ended December 31, 2014.

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-50 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, 2014 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 (2013 Framework). Based on our evaluation under this framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2014. The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by Ernst & Young 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 112.

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 Rhino Resource Partners LP and subsidiaries' internal control over financial reporting as of December 31, 2014, based on criteria established in the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Rhino Resource Partners LP and subsidiaries' 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 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

In our opinion, Rhino Resource Partners LP and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated statements of financial position of Rhino Resource Partners LP and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations and comprehensive income, partners' capital and cash flows for each of the two years in the period ended December 31, 2014 and our report dated March 11, 2015 expressed an unqualified opinion thereon.

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 seven 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, 2014:

Mark D. Zand. Mr. Zand has served as the Chairman of our general partner's board of directors since November 2014 and from October 2013 to November 2014, Mr. Zand served as a director of our general partner's board of directors. From January 2010 to October 2013, Mr. Zand served as the Chairman of our general partner's board of directors and Mr. Zand has served as a member of our general partner's compensation committee since January 2010. 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.

Joseph E. Funk. Mr. Funk has served as President and Chief Executive Officer of our general partner since November 2014. From July 2011 to November 2014, Mr. Funk served as the President of our Elk Horn coal leasing operation, which was acquired in July 2011. Prior to our acquisition of Elk Horn, Mr. Funk served as Executive Vice President of The Elk Horn Coal Company since joining that organization in 2010. From 2007 to 2010, Mr. Funk served as Chief Financial Officer at BD Acquisition LLC, a coal mining company with operations in eastern Kentucky, which emerged from its predecessor, Black Diamond Mining Company, where Mr. Funk served as a senior financial executive. Mr. Funk is a Certified Public Accountant and has approximately 30 years of experience in the coal industry.

Richard A. Boone. Mr. Boone has served as Executive Vice President and Chief Financial Officer of our general partner since June 2014. Prior to June 2014, Mr. Boone 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 34 years of experience in the coal industry.

Reford C. Hunt. Mr. Hunt has served as our general partner's Senior Vice President of Business Development since August 2014. From May 2010 to August 2014, Mr. Hunt served as our general partner's Vice President of Technical Services. 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 Vice President of Rhino Energy WV LLC and McClane Canyon Mining LLC since September 2009 and as Vice 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 18 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.

Brian T. Aug. Mr. Aug has served as our general partner's Vice President of Sales since August 2013. From April 2011 to August 2013, Mr. Aug served as Director of Sales and Marketing for Rhino Energy LLC. Prior to joining Rhino Energy LLC, he was Vice President of Marketing and Trading Analysis for Greenstar Global Energy, a US based corporation focused on the selling of US coals into India. From 1994 until 2010 he worked for Duke Energy Ohio, a Midwest utility with coal and natural gas power generation. The last 10 years of his career at Duke Energy Ohio was spent as Director of Fuels.

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.

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 and has served as a member of our general partner's compensation committee since July 2014. 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 served as audit committee chairman of Republic Airways Holdings, Inc. until February 2014. Mr. Plaumann currently serves as a director and audit committee member of Republic Airways Holdings, Inc., and serves as director and audit committee chairman of 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 with Alvarez & Marsal Inc., a position he has held since November 2006, and had previously served as Chief Executive Officer of Legacy Asset Management Company, a wholly-owned subsidiary of Lehman Brothers Holdings, Inc. 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 March 6, 2015, beneficially owns an aggregate 50% 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, 2014. 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 Rubin, 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, 2014, 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.

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. Funk, 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 2014, 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 2014 and during the first quarter of 2015, we granted additional phantom unit awards to Messrs. Funk, Boone, Aug, and Hunt and Ms. Kegley 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.

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 June 1, 2014, we entered into an amended and restated employment agreement with Mr. Boone, which is substantially similar to his prior agreement. The amendment and restatement of Mr. Boone's employment agreement extends his employment term to May 31, 2016 and increases his annual performance-based discretionary bonus to up to 100% of his base salary, but otherwise does not materially alter the terms of his prior agreement.

Effective August 31, 2014, we entered into an amended and restated employment agreement with Mr. Hunt, which is substantially similar to his prior agreement. The amendment and restatement of Mr. Hunt's employment agreement extends his employment term to August 31, 2017, increases his annual base salary to $265,000 per year and changes his title to Senior Vice President of Business Development, but otherwise does not materially alter the terms of his prior agreement.

Effective November 2014, we entered into an employment agreement with Mr. Funk in connection with his appointment as President and Chief Executive Officer. Mr. Funk's employment agreement provides for an employment term that ends on December 31, 2017 (unless earlier terminated as provided in the agreement or by the mutual agreement of the parties) and an annual base salary of $365,000 per year. Mr. Funk's employment agreement also entitles him to receive an annual bonus calculated as 1% of our annual "EBITDA" (as defined in Mr. Funk's employment agreement). For 2014, Mr. Funk earned an annual bonus that consists of (i) for January 1, 2014 through November 13, 2014, an amount equal to the bonus paid to Mr. Funk for 2013 pro-rated for such period and (ii) for November 14, 2014 through December 31, 2014, an amount equal to 1% of our estimated EBITDA for 2014 pro-rated for such period. Under the employment agreement, we will also provide Mr. Funk with use of an automobile suitable for his duties and responsibilities.

The severance benefits provided under 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, Messrs. Funk, Boone and Hunt had their annual base salaries set at $365,000, $315,000 and $265,000, respectively, during 2014 as described above under "—Employment Agreements". Ms. Kegley's and Mr. Aug's annual base salaries remained at $190,000 and $200,000, respectively, for 2014 and did not change. Mr. Walton's annual base salary for 2014 was $440,000 through the date of his termination of employment.

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. Approximately one-half of each named executive officer's bonus for 2014 was determined based upon achievement of certain entity-wide safety measures and coal production goals. The other one-half of each named executive officer's annual bonus amount was purely discretionary based upon a review of the named executive officer's individual performance. The total amount of the annual 2014 bonuses was reviewed and approved by the compensation committee.

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, except Mr. Funk, 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 base salary (up to 100% of annual base salary in the case of Mr. Boone). Prior to his termination of employment, Mr. Walton's employment agreement provided that his annual bonus could have been up to 150% of his annual base salary. In order to incentivize Mr. Funk to improve our performance, we have structured his potential bonus to be calculated as 1% of our annual EBITDA.

The following table sets forth the annual rate of base salary payable for fiscal 2014 and potential bonus amounts for the named executive officers pursuant to their employment agreements:


Name and Principal Position	Base Salary		Bonus(1)
Joseph E. Funk President and Chief Executive Officer	$	365,000		1% of annual EBITDA
Christopher I. Walton Former President and Chief Executive Officer	$	440,000		0% to 150% of base salary
Richard A. Boone Executive Vice President and Chief Financial Officer	$	315,000		0% to 100% of base salary
Reford C. Hunt Vice President of Business Development	$	265,000		0% to 40% of base salary
Whitney C. Kegley Vice President, Secretary and General Counsel	$	190,000		0% to 40% of base salary
Brian T. Aug Vice President of Sales	$	200,000		0% to 40% of base salary

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."

On November 14, 2014, Mr. Walton ceased providing services to us. Upon his departure, the compensation provided to Mr. Walton included his accrued base salary and vacation earned through the date of his departure. We did not enter into any consulting or severance agreements with Mr. Walton upon his departure.

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 each of the first quarters from 2012 through 2015, 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, 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." 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). 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 "401(k) Plan"). The 401(k) Plan is used to assist their eligible employees in saving for retirement on a tax-deferred basis. The 401(k) Plan permits all eligible employees, including the named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. The companies make safe harbor matching contributions to the 401(k) Plan for those eligible employees who meet certain conditions and subject to certain limitations under federal law. Under the 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. In addition, discretionary employer non-elective contributions may be made under the 401(k) Plan. Employee and employer contributions are subject to annual dollar limitations, which are periodically adjusted for changes in the cost of living. The 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 2014, 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, 2014.

The following table sets forth the cash and other compensation earned by each of our named executive officers for the years ended December 31, 2014, 2013 and 2012.

Name and Principal Position

Joseph E. Funk	2014	228,829	100,000	24,994	11,272	365,095
President and Chief Executive Officer	2013	213,473	51,000	28,999	9,599	303,071
	2012	190,241	48,700	60,007	9,000	307,948
Christopher I. Walton	2014	418,001	—	124,997	12,984	555,982
Former President and Chief Executive	2013	332,597	150,000	40,000	10,842	533,439
Officer(4)	2012	255,578	63,500	21,994	11,942	353,014
Richard A. Boone	2014	315,000	25,000	45,002	12,169	397,171
Executive Vice President and Chief	2013	306,232	90,000	57,998	12,509	466,739
Financial Officer	2012	286,308	117,100	55,998	12,356	471,762
Reford C. Hunt	2014	251,154	19,000	17,006	14,220	301,380
Senior Vice President of Business	2013	238,078	35,000	28,002	13,992	315,072
Development	2012	228,076	51,600	26,003	13,119	318,798
Whitney C. Kegley	2014	190,000	17,000	19,996	8,880	235,876
Vice President, Secretary and General	2013	190,000	32,000	29,997	10,200	262,197
Counsel	2012	84,039	17,800	—	840	102,679
Brian T. Aug	2014	200,000	15,000	11,003	11,522	237,525
Vice President of Sales	2013	167,107	37,493	—	7,265	211,865
	2012	—	—	—	—	—

Certain named executive officers received discretionary annual awards of phantom units that were granted on March 1, 2014. 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 2013 performance. The following table sets forth information concerning equity awards for the named executive officers that were granted during the year ended December 31, 2014.

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

During 2014, we had employment agreements in effect with each of the named executive officers. The employment agreements with each named executive officer set forth the annual base salary payable to each named executive officer. We entered into an amended and restated employment agreement with Mr. Boone, effective June 1, 2014, and Mr. Hunt, effective September 30, 2014. 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 amended and restated employment agreement with Mr. Hunt provides for an automatic annual base salary increase of $10,000 every September 1 during the employment term beginning on September 1, 2015. The employment agreements with

Messrs. Boone and Aug and Ms. Kegley provide that their annual base salary shall be reviewed annually for potential increases. Per Mr. Funk's employment agreement, his annual base salary does not change for the duration of his employment agreement.

Except for Mr. Funk, the named executive officers were each entitled under their respective employment agreements to receive an annual discretionary bonus of up to 40% of their annual base salary (100% of base salary in the case of Mr. Boone) in 2014. Mr. Funk's employment agreement entitles him to receive an annual bonus calculated as 1% of our annual EBITDA, as defined in his employment agreement. For 2014, Mr. Funk will receive an annual bonus consisting of (i) for January 1, 2014 through November 13, 2014, an amount equal to the bonus paid to Mr. Funk for 2013 pro-rated for such period and (ii) for November 14, 2014 through December 31, 2014, an amount equal to 1% of our estimated EBITDA pro-rated for such period. Prior to his termination of employment, Mr. Walton was entitled to an annual bonus of up to 150% of his annual base salary in 2014.

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. Funk, Boone, Hunt and Aug with automobiles suitable for their duties and responsibilities to us.

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."

Certain named executives received discretionary awards of phantom units in 2014, 2013 and 2012 in respect of fiscal 2013, 2012 and 2011 performance, respectively. 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 2017, 2016 and 2015, respectively), 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).

The following table sets forth information concerning outstanding equity awards held by each of our named executive officers as of December 31, 2014.

The following table sets forth information concerning equity awards for the named executive officers that vested during the year ended December 31, 2014.

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. Funk, Boone, Hunt and Aug and the employment agreement with Ms. Kegley, if the employment of the executive is terminated by us for "cause," by the executive voluntarily without "good reason," (or, with respect to Mr. Aug and Ms. Kegley, voluntarily for any reason or no reason whatsoever) 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. Funk or Mr. Boone is terminated by us without "cause" or by the executive for "good reason," the executive shall receive a lump sum cash payment equal to twelve months' worth of his base salary (six months in the case of Mr. Funk), in each case, subject to the executive's timely execution and delivery (and nonrevocation) of a release agreement for our benefit. Mr. Funk 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. Funk or Mr. Boone, their estate will be entitled to receive the accrued obligations and a pro-rated annual discretionary bonus.

Under Mr. Funk's employment agreement, we have the right to reassign Mr. Funk to his prior position as President of Elk Horn, with compensation equal to the compensation that was payable prior to Mr. Funk's appointment as President and CEO of Rhino GP. In addition, upon providing us 90 days written notice, Mr. Funk has the right under his employment agreement to return to his prior position as President of Elk Horn, with compensation equal to the compensation that was payable prior to Mr. Funk's appointment as President and CEO of Rhino GP. Mr. Funk also has the right to terminate the employment agreement if substantially all of Rhino GP's assets or 50% of its voting membership units are sold to one or more entities that are not subsidiaries or affiliates of Rhino GP, Wexford Capital LP or any investment fund managed by Wexford Capital LP. In such event, such a termination is defined in Mr. Funk's agreement as termination for "good reason" and Mr. Funk would be entitled to receive a lump sum cash payment equal to six months' worth of his base salary and payment for outstanding earned vacation. In such event, Mr. Funk would also be subject to the non-compete provisions described below.

Messrs. Funk and Boone 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 (six

months following the executive's termination for any reason in the case of the non-compete and non-solicitation covenant for Mr. Funk).

For purposes of the employment agreement with Mr. Funk, the terms listed below have been defined as follows:

For purposes of the employment agreement with Mr. Boone, the terms listed below have been defined as follows:

Under the employment agreements with Messrs. Hunt and Aug and Ms. Kegley, if their employment is terminated by us without "cause" (or if Mr. Hunt resigns for "good reason", which such term has the same meaning as described above with respect to the employment agreement with Mr. Boone), 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 while Mr. Aug and Ms. Kegley are entitled to receive a lump sum payment equal to six months' worth of their 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 six months or the date they become covered under a new employer's plan. Messrs. Hunt and Aug and Ms. Kegley 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 six months following Mr. Aug's and Ms. Kegley's termination by us with or without "cause"). The non-solicitation period runs until the end of the six month period

following the end of the applicable non-compete period. In the event of the death of Mr. Hunt, his estate will be entitled to receive the accrued obligations and a pro-rated annual discretionary bonus.

For purposes of the agreements with Messrs. Hunt and Aug and Ms. Kegley, "cause" means (a) the commission by executive of an act of dishonesty or fraud against us, (b) a breach of the executive's obligations under the employment agreement and failure to cure such breach within five days (ten days for Mr. Hunt) after written notice from us, (c) executive is indicted for or convicted of a crime involving moral turpitude or (d) executive materially fails or neglects to diligently perform his duties and "disability".

Messrs. Funk, Boone, Hunt and Aug and Ms. Kegley 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. For this purpose, "good reason" has the meaning set forth above and "cause" has the meaning set forth in the respective employment agreement of the named executive officer, except that with respect to Messrs. Hunt and Aug and Ms. Kegley, "cause" has the meaning set forth in the employment agreement of Mr. 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.

Per Mr. Funk's employment agreement, we will use reasonable efforts to accelerate the vesting of the 4,453 unvested phantom units outstanding as of December 31, 2014 that were previously granted to Mr. Funk, plus we will use reasonable efforts to accelerate the vesting of any phantom units awarded during the first quarter of 2015 as part of his 2014 bonus.

As described above under "Compensation Discussion and Analysis—Departure of Mr. Walton", Mr. Walton ceased providing services to us on November 14, 2014. Under his employment agreement, Mr. Walton was entitled to receive his accrued base salary and vacation earned through the date of his departure.

The table below discloses the amount of compensation and/or benefits due to Messrs. Funk, Boone, Hunt and Aug and Ms. Kegley 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, 2014, taking into account the arrangements described above and the salary and bonus rates in effect for the named executive officers for fiscal 2014, and (ii) that the price per common unit was $2.25, which was the closing price of our common units on December 31, 2014 (the last trading day in 2014). The table excludes amounts accrued through fiscal 2014 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		Disability or Death		Resignation with Good Reason

Joseph E. Funk
Cash Payment	$	182,500	(1)	$	182,500	$	157,408	$	365,000
Accelerated Equity Vesting(2)	$	10,019		$	10,019	$	10,019	$	10,019

Total	$	192,519		$	192,519	$	167,427	$	375,019
Richard Boone
Cash Payment	$	—		$	315,000	$	315,000	$	315,000
Accelerated Equity Vesting(2)	$	16,538		$	8,066	$	16,538	$	8,066

Total	$	16,538		$	323,066	$	331,538	$	323,066
Reford Hunt
Cash Payment	$	—		$	265,000	$	106,000	$	265,000
Accelerated Equity Vesting(2)	$	7,099		$	3,569	$	7,099	$	3,569

Total	$	7,099		$	268,569	$	113,099	$	268,569
Whitney Kegley
Cash Payment	$	—		$	95,000	$	—	$	—
Accelerated Equity Vesting(2)	$	6,784		$	2,797	$	6,784	$	2,797

Total	$	6,784		$	97,797	$	6,784	$	2,797
Brian T. Aug
Cash Payment	$	—		$	100,000	$	—	$	—
Accelerated Equity Vesting(2)	$	1,971		$	657	$	1,971	$	657

Total	$	1,971		$	100,657	$	1,971	$	657

We provide compensation to the 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. 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 directors for the fiscal year ended December 31, 2014.

(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 2014, computed in accordance with FASB ASC Topic 718. See Note 2 to our consolidated financial statements for fiscal 2014 for additional detail regarding assumptions underlying the value of these equity awards. As of December 31, 2014, each director held 1,570 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 2014 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 March 6, 2015 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	36.0	%	8,597,487	69.4	%	50.2	%
Charles E. Davidson(1)(2)(3)(4)(5)	7,133,904	42.7	%	10,151,520	81.9	%	59.4	%
Joseph M. Jacobs(1)(2)(3)(4)	6,788,126	40.7	%	9,656,894	77.9	%	56.5	%
Wexford Capital LP(1)(2)(3)(4)	6,647,160	39.8	%	9,455,252	76.3	%	55.3	%
Wexford GP LLC(1)(2)(3)(4)	6,647,160	39.8	%	9,455,252	76.3	%	55.3	%
Mark D. Zand	14,493	*		20,729	*		*
Joseph E. Funk	1,849	*		—	—		*
Richard A. Boone	15,564	*		—	—		*
Reford C. Hunt	—	—		—	—		—
Whitney C. Kegley	451	*		—	—		*
Brian T. Aug	—	—		—	—		—
Arthur H. Amron	12,199	*		17,447	*		*
Kenneth A. Rubin	8,914	*		12,754	*		*
Mark L. Plaumann(6)	8,552	*		682	*		*
Douglas Lambert(6)	8,075	*		—	—		*
James F. Tompkins(6)	9,075	*		—	—		*
All executive officers and directors as a group (12 persons)	6,867,298	41.1	%	9,708,506	78.3	%	57.0	%

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

(2): 599,631 common units and 857,765 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 3, 2014 included a total of 8,376 common units granted to four Wexford Capital affiliated directors of our general partner on behalf of Wexford Capital. These units vest as follows: 2,096 units vested on the grant date, 2,092 units vested on January 1, 2015, 2,092 units will vest on April 1, 2015 and 2,096 units will vest on July 1, 2015. 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 2,094 units on October 3, 2014 pursuant to the LTIP. These units vest as follows: 25% of the units vested upon the grant, 25% vested on January 1, 2015, and the remaining 50% vest ratably on April 1, 2015 and July 1, 2015.

For more information relating to our Long-Term Incentive Plan and the unit awards granted thereunder, please see Note 14 of the consolidated financial statements included elsewhere in this annual report.

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

As of March 6, 2015, Wexford owned 7,310,476 common units and 10,404,092 subordinated units representing approximately 60.9% 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, 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 2014, Wexford received distributions of approximately $0.8 million on the 2.0% general partner interest and approximately $10.1 million on its common units. No distributions were paid on subordinated units during 2014.

On February 13, 2015, Wexford received a distribution for the fourth quarter of 2014 of approximately $30,000 on the 2.0% general partner interest and approximately $366,000 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 19 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, 2014, 2013 and 2012.

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.

In September 2014, we made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC ("Sturgeon"), with affiliates of Wexford Capital and Gulfport Energy ("Gulfport"). Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. We recorded our proportionate portion of the operating income for this investment during 2014 of approximately $0.4 million.

We and an affiliate of Wexford participated with Gulfport to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. 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, 2013, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 152,300 gross acres, or approximately 7,615 net acres, for a total purchase price of approximately $31.1 million. In addition, per the joint operating agreement among us, Gulfport and an affiliate of Wexford Capital, we funded our proportionate share of drilling costs to Gulfport for wells drilled on our acreage. As of December 31, 2013, we funded approximately $23.3 million of drilling costs. We received approximately $5.6 million of revenue from this investment for the year ended December 31, 2013.

items due to us prior to the effective date of the Purchase Agreement. The net effect of this settlement resulted in us paying Gulfport approximately $46,000 in December 2014. We recorded a gain of approximately $121.7 million during the year ended December 31, 2014 related to this sale.

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 provided by Ernst & Young LLP for 2014 and 2013:

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

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	†	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

10.2	†	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

10.3	†	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

10.4	†	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

10.5	†*	Amended and Restated Employment Agreement of Joseph E. Funk effective as of November 14, 2014.

10.6	†	Amended and Restated Employment Agreement of Richard A. Boone effective June 1, 2014, incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q (File No. 001-34892), filed on August 6, 2014

10.7	†	Amended and Restated Employment Agreement of Reford C. Hunt effective September 1, 2014, incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q (File No. 001-34892) filed on November 5, 2014

10.8	†*	Amended and Restated Employment Agreement of Brian T. Aug effective as of August 1, 2013

10.10		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

		Description

10.11		First Amendment to Amended and Restated Credit Agreement, dated April 18, 2013 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 April 19, 2013

10.12		Second Amendment to Amended and Restated Credit Agreement, dated March 19, 2014 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 10.2 of the Current Report on Form 8-K (File No. 001-34892), filed on March 25, 2014

10.13		Purchase and Sale Agreement with Gulfport Energy Corporation dated March 19, 2014, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on March 25, 2014

21.1	*	List of Subsidiaries of Rhino Resource Partners LP

23.1	*	Consent of Ernst & Young LLP

23.2	*	Consent of Deloitte & Touche LLP

23.3	*	Consent of John T. Boyd Company

31.1	*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

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, 2014 and the three months ended December 31, 2014

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

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 as of December 31, 2014 and 2013, and the related consolidated statements of operations and comprehensive income, partners' capital and cash flows for each of the two years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these 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, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Rhino Resource Partners LP and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Rhino Resource Partners LP's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 11, 2015 expressed an unqualified opinion thereon.

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 operations and comprehensive income, partners' capital, and cash flows of Rhino Resource Partners LP and subsidiaries (the "Partnership") for the year 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 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 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 audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of Rhino Resource Partners LP's operations and cash flows for the year ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

Cincinnati, Ohio
March 8, 2013
(October 10, 2014 as to the retrospective reclassifications related to the sale of oil and gas properties in the Utica Shale region described in Note 4 and changes in segment reporting related to this sale to remove the Oil and Natural Gas segment described in Note 21, and March 11, 2015 as to the changes in segment reporting for the new Illinois Basin segment described in Note 21)

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(In thousands)

	As of December 31,

	2014			2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	626		$	423
Accounts receivable, net of allowance for doubtful accounts ($724 as of December 31, 2014 and $0 as of December 31, 2013)		22,467			25,461
Inventories		13,030			18,580
Advance royalties, current portion		1,032			179
Prepaid expenses and other		3,974			4,572
Current assets held for sale		—			454

Total current assets		41,129			49,669

PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs		663,662			674,708
Less accumulated depreciation, depletion and amortization		(280,225	)		(249,718	)

Net property, plant and equipment		383,437			424,990

Advance royalties, net of current portion		1,363			5,580
Investment in unconsolidated affiliates		20,653			21,243
Intangible assets, net		1,067			1,148
Other non-current assets		16,410			9,640
Non-current assets held for sale		9,279			55,497

TOTAL	$	473,338		$	567,767



LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	10,924		$	17,710
Accrued expenses and other		17,334			20,567
Current portion of long-term debt		210			1,024
Current portion of asset retirement obligations		1,431			1,614
Current portion of postretirement benefits		425			334
Current liabilities held for sale		—			5,241

Total current liabilities		30,324			46,490

NON-CURRENT LIABILITIES:
Long-term debt, net of current portion		57,222			170,022
Asset retirement obligations, net of current portion		28,452			32,837
Other non-current liabilities		27,942			16,220
Postretirement benefits, net of current portion		6,223			5,786
Non-current liabilities held for sale		2,250			41

Total non-current liabilities		122,089			224,906

Total liabilities		152,413			271,396

COMMITMENTS AND CONTINGENCIES (NOTE 15)
PARTNERS' CAPITAL:
Limited partners		308,586			283,339
General partner		10,966			10,801
Accumulated other comprehensive income		1,373			2,231

Total partners' capital		320,925			296,371

TOTAL	$	473,338		$	567,767

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(In thousands, except per unit data)

	Year Ended December 31,

	2014			2013			2012
REVENUES:
Coal sales	$	202,881		$	236,601		$	304,568
Freight and handling revenues		2,020			2,159			6,357
Other revenues		34,156			33,505			40,818

Total revenues		239,057			272,265			351,743
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		200,141			199,705			247,719
Freight and handling costs		1,877			1,294			5,833
Depreciation, depletion and amortization		37,233			39,627			41,274
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)		19,226			19,800			20,442
Asset impairment and related charges		45,296			1,667			—
(Gain) on sale/disposal of assets, net		(569	)		(10,359	)		(4,890	)

Total costs and expenses		303,204			251,734			310,378

(LOSS)/INCOME FROM OPERATIONS		(64,147	)		20,531			41,365

INTEREST AND OTHER (EXPENSE)/INCOME:
Interest expense and other		(5,708	)		(7,898	)		(7,767	)
Interest income and other		274			207			92
Equity in net (loss)/income of unconsolidated affiliates		(11,712	)		(4,729	)		5,757

Total interest and other (expense)		(17,146	)		(12,420	)		(1,918	)

(LOSS)/INCOME BEFORE INCOME TAXES FROM CONTINUING OPERATIONS		(81,293	)		8,111			39,447
INCOME TAXES		—			—			—

NET (LOSS)/INCOME FROM CONTINUING OPERATIONS		(81,293	)		8,111			39,447

DISCONTINUED OPERATIONS
Income from discontinued operations		130,342			1,307			88

NET INCOME		49,049			9,418			39,535
Other comprehensive income:
Change in actuarial gain under ASC Topic 815		(858	)		800			(917	)

COMPREHENSIVE INCOME	$	48,191		$	10,218		$	38,618



General partner's interest in net (loss)/income:
Net (loss)/income from continuing operations	$	(1,626	)	$	162		$	789
Net income from discontinued operations		2,607			26			1

General partner's interest in net income	$	981		$	188		$	790
Common unitholders' interest in net (loss)/income:
Net (loss)/income from continuing operations	$	(45,705	)	$	4,448		$	21,374
Net income from discontinued operations		73,271			769			48

Common unitholders' interest in net income	$	27,566		$	5,217		$	21,422
Subordinated unitholders' interest in net (loss)/income:
Net (loss)/income from continuing operations	$	(33,962	)	$	3,501		$	17,284
Net income from discontinued operations		54,464			512			39

Subordinated unitholders' interest in net income	$	20,502		$	4,013		$	17,323
Net (loss)/income per limited partner unit, basic:
Common units:
Net (loss)/income per unit from continuing operations	$	(2.74	)	$	0.29		$	1.39
Net income per unit from discontinued operations		4.39			0.04			0.01

Net income per common unit, basic	$	1.65		$	0.33		$	1.40
Subordinated units
Net (loss)/income per unit from continuing operations	$	(2.74	)	$	0.28		$	1.39
Net income per unit from discontinued operations		4.39			0.04			0.01

Net income per subordinated unit, basic	$	1.65		$	0.32		$	1.40
Net (loss)/income per limited partner unit, diluted:
Common units
Net (loss)/income per unit from continuing operations	$	(2.74	)	$	0.29		$	1.39
Net income per unit from discontinued operations		4.39			0.04			0.01

Net income per common unit, diluted	$	1.65		$	0.33		$	1.40
Subordinated units
Net (loss)/income per unit from continuing operations	$	(2.74	)	$	0.28		$	1.39
Net income per unit from discontinued operations		4.39			0.04			0.01

Net income per subordinated unit, diluted	$	1.65		$	0.32		$	1.40
Distributions paid per limited partner unit(1)	$	1.385		$	1.78		$	1.85
Weighted average number of limited partner units outstanding, basic:
Common units		16,678			15,751			15,331
Subordinated units		12,397			12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units		16,685			15,760			15,335
Subordinated units		12,397			12,397			12,397

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(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—December 31, 2011		15,311	$	194,840			12,397	$	93,202		$	11,547		$	2,348		$	301,937
Net income		—		21,422			—		17,323			790			—			39,535
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	$	188,436			12,397	$	98,624		$	11,303		$	1,431		$	299,794

Net income		—		5,217			—		4,013			188			—			9,418
Distributions to unitholders and general partner		—		(28,119	)		—		—			(1,020	)		—			(29,139	)
General partners' contributions		—		—			—		—			330			—			330
Offering of common units		1,265		14,788			—		—			—			—			14,788
Offering costs		—		(214	)		—		—			—			—			(214	)
Issuance of units under LTIP		45		594			—		—			—			—			594
Change in actuarial gain under ASC Topic 815		—		—			—		—			—			800			800

BALANCE—December 31, 2013		16,660	$	180,702			12,397	$	102,637		$	10,801		$	2,231		$	296,371



Net income		—		27,566			—		20,502			981			—			49,049
Distributions to unitholders and general partner		—		(23,140	)		—		—			(822	)		—			(23,962	)
General partners' contributions		—		—			—		—			6			—			6
Offering costs		—		(2	)		—		—			—			—			(2	)
Issuance of units under LTIP		25		321			—		—			—			—			321
Change in actuarial gain under ASC Topic 815		—		—			—		—			—			(858	)		(858	)

BALANCE—December 31, 2014		16,685	$	185,447			12,397	$	123,139		$	10,966		$	1,373		$	320,925

RHINO RESOURCE PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,

	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	49,049		$	9,418		$	39,535
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		37,233			42,609			41,370
Accretion on asset retirement obligations		2,281			2,356			1,896
Accretion on interest-free debt		—			57			222
Amortization of deferred revenue		(1,731	)		(1,553	)		(929	)
Amortization of advance royalties		440			270			244
Amortization of debt issuance costs		2,127			1,295			1,075
Amortization of actuarial gain		(368	)		(145	)		(295	)
Provision for doubtful accounts		724			—			—
Equity in net loss/(income) of unconsolidated affiliates		11,712			4,729			(5,757	)
Distributions from unconsolidated affiliate		—			—			2,958
Loss on retirement of advance royalties		244			182			100
(Gain) on sale/disposal of assets—net		(130,621	)		(10,359	)		(4,878	)
Loss on impairment of assets		45,296			1,667			—
Equity-based compensation		255			605			873
Changes in assets and liabilities:
Accounts receivable		634			7,441			6,465
Inventories		5,550			163			(3,114	)
Advance royalties		(1,453	)		(1,517	)		(1,687	)
Prepaid expenses and other assets		485			(1,395	)		1,341
Accounts payable		(1,731	)		(2,036	)		(5,540	)
Accrued expenses and other liabilities		2,841			(135	)		6,497
Asset retirement obligations		(1,824	)		(2,240	)		(1,108	)
Postretirement benefits		38			318			476

Net cash provided by operating activities		21,181			51,730			79,744

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment		(62,986	)		(54,522	)		(61,772	)
Proceeds from sales/recoveries of property, plant, and equipment		189,618			12,489			5,479
Principal payments received on notes receivable		205			—			11,945
Cash paid from issuance of notes receivable		—			(205	)		(11,945	)
Changes in restricted cash		—			1,079			3
Investment in unconsolidated affiliates		(10,096	)		(2,749	)		(2,114	)

Net cash provided by (used in) investing activities		116,741			(43,908	)		(58,404	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit		170,040			185,300			212,300
Repayments on line of credit		(282,630	)		(175,510	)		(192,050	)
Proceeds from issuance of long-term debt		—			—			2,973
Repayments on long-term debt		(1,024	)		(2,350	)		(2,994	)
Payments on debt issuance costs		(103	)		(980	)		—
Proceeds from issuance of common units, net of underwriting costs		—			14,788			—
Payment of offering costs		(2	)		(214	)		(7	)
Net settlement of withholding taxes on employee unit awards vesting		(44	)		(85	)		(145	)
General partner's contributions		6			330			13
Distributions to unitholders		(23,962	)		(29,139	)		(41,418	)

Net cash (used in) financing activities		(137,719	)		(7,860	)		(21,328	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		203			(38	)		12
CASH AND CASH EQUIVALENTS—Beginning of period		423			461			449

CASH AND CASH EQUIVALENTS—End of period	$	626		$	423		$	461

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

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 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 provide revenues to the Partnership.

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.

On September 13, 2013, the Partnership completed a public offering of 1,265,000 common units, representing limited partner interests in the Partnership, at a price of $12.30 per common unit. Of the common units issued, 165,000 units were issued in connection with the exercise of the underwriter's option to purchase additional units. Net proceeds from the offering were approximately $14.6 million, after deducting underwriting discounts and offering expenses of approximately $1.0 million. The Partnership used the net proceeds from this offering, and a related capital contribution by the General Partner of approximately $0.3 million, to repay approximately $14.9 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.

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.

Trade Receivables and Concentrations of Credit Risk. See Note 17 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.

During 2014, the Partnership recorded an accounts receivable allowance of approximately $0.7 million in relation to a customer that had entered bankruptcy proceedings. The Partnership recorded this allowance based upon its best estimate of the ultimate collectability of the accounts receivable balance through the bankruptcy proceedings of this customer.

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.

Notes Receivable. 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, KY area to a third party. 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 included the potential for additional payments of approximately $8.75 million dependent upon certain future contingencies. Rhino recorded the sale of the assets and transfer of liabilities in the third quarter of 2011, but did not record any of the potential $8.75 million consideration since this amount relied on future contingent conditions to be met before it could be recognized. In 2014, the third party entered negotiations with the Partnership regarding the payment of the $8.75 million consideration as the third party anticipated the contingencies would be met in the near future. The third party negotiated with the Partnership to accept a note receivable in lieu of immediate payment since the third party did not have the available funds to pay the $8.75 million consideration. The Partnership believes the collection of the $8.75 million is in doubt due to the necessity of the third party to request a note receivable and the belief that the third party will not be able to economically mine this property for an extended period due to the lack of certain mining permits. Based on the uncertainty of collection of the note receivable, the Partnership recorded a note receivable balance along with a corresponding allowance against the entire $8.75 million note receivable balance. The Partnership received approximately $0.25 million in payments in 2014 related to this note receivable and the balance at December 31, 2014 was $8.5 million, which remained fully reserved based on the factors discussed above.

Property, Plant and Equipment. Property, plant, and equipment, including coal properties, oil and natural gas 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.

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. During 2014, the Partnership recorded $45.3 million of asset impairment losses and related charges associated with multiple coal properties that are further described in Note 6. The asset impairment losses and related charges are recorded on the Asset impairment and related charges line of the Partnership's consolidated statements of operations and comprehensive income. The Partnership also recorded an impairment charge of $5.9 million during 2014 related to the Partnership's equity investment in the Rhino Eastern joint venture that is discussed further in Note 3. The impairment charge for the Rhino Eastern joint venture is recorded on the Equity in net (loss)/income of unconsolidated affiliates line of the Partnership's consolidated statements of operations and comprehensive income. During 2013, the Partnership recorded an impairment loss of $1.7 million related to its McClane Canyon mining complex in Colorado. See Note 6 for more information on this impairment loss. There were no impairment losses recorded during the year ended December 31, 2012.

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. In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility that reduced the borrowing capacity to $200 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, which was recorded as an addition to Debt issuance costs. In addition, the Partnership wrote-off approximately $1.1 million of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility. See Note 10 for further information on the amendment to the amended and restated senior secured credit facility.

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.

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. Each respective year includes a range of discount rates that are dependent upon the timing of the cash flows of the specific obligations. Changes in the asset retirement obligations for the year ended December 31, 2014 were calculated with discount rates that ranged from 1.6% to 5.3%. Changes in the Partnership's asset retirement obligations for the year ended December 31, 2013 were calculated with discount rates that ranged from 2.3% to 5.6%. 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%. The discount rates changed in each respective year due to changes in applicable market indicators that are used to arrive at an appropriate discount rate. 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 2014, 2013 and 2012.

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.

In addition, the Partnership's liability for traumatic workers' compensation injury claims is the estimated present value of current workers' compensation benefits, based on actuarial estimates. The actuarial estimates for the Partnership's workers' compensation liability are based on numerous assumptions including claim development patterns, mortality, medical costs and interest rates.

See Note 12 for more information on the Partnership's workers' compensation and black lung liabilities and expense.

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 royalty 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. On occasion, the Partnership uses diesel fuel contracts to manage the risk of fluctuations in the cost of diesel fuel. The Partnership's diesel fuel contracts meet the requirements 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. The Partnership had two diesel fuel contracts as of December 31, 2014 to purchase approximately 1.0 million gallons of diesel fuel at fixed prices through December 2015.

Investments in Joint Ventures. Investments in joint ventures are accounted for using the 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 accounted for the investment in Rhino Eastern and its results of operations under the equity method. The Partnership considered the operations of this entity to comprise a reporting

segment ("Eastern Met") and has provided additional detail related to this operation in Note 21, "Segment Information."

On December 31, 2014, the Partnership entered into an agreement with a wholly owned subsidiary of Patriot that effectively terminated the Rhino Eastern joint venture. This agreement officially closed in January 2015 and is described further in Note 3.

The Partnership determined it was not the primary beneficiary of the variable interest entity for the years ended December 31, 2014, 2013 and 2012 by performing 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 was not the primary beneficiary of Rhino Eastern primarily because of certain contractual arrangements by the joint venture with Patriot and the fact that the Rhino Eastern joint venture was managed by a committee of an equal number of representatives from Patriot and us. Mandatory pro rata additional contributions not to exceed $10 million in the aggregate could have been required of the joint venture partners which the Partnership would have been obligated to fund based upon its 51% ownership interest.

As of December 31, 2014 and 2013, the Partnership recorded its equity method investment of $13.2 million and $19.4 million, respectively, in the Rhino Eastern joint venture as a long-term asset. See Note 3 for a discussion of the impairment charge incurred on the Partnership's equity method investment as of December 31, 2014. During 2014 and 2013, the Partnership contributed additional capital based upon its ownership share to the Rhino Eastern joint venture in the amount of $4.8 million and $2.3 million, respectively. The Partnership did not contribute any additional capital during 2012. As disclosed in Note 19 "Related Party and Affiliate Transactions", during 2012, the Partnership provided loans to Rhino Eastern totaling approximately $11.9 million, which were fully repaid as of December 31, 2012.

In December 2012, the Partnership made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant 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. During 2014 and 2013, the Partnership contributed additional capital based upon its ownership share to the Muskie joint venture in the amount of $0.2 million and $0.5 million, respectively. As disclosed in Note 19 "Related Party and Affiliate Transactions", during 2013 the Partnership provided a loan to Muskie totaling approximately $0.2 million which was fully repaid in November 2014 in conjunction with the Partnership's contribution of its interest in Muskie to Mammoth Energy Partners LP ("Mammoth"), which is discussed below.

In November 2014, the Partnership contributed its investment interest in Muskie to Mammoth in return for a limited partner interest in Mammoth. Mammoth was formed to own various companies that provide services to companies who engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth's companies provide services that include completion and production services, contract land and directional drilling services and remote accommodation services. The non-cash transaction was a contribution of the Partnership's investment interest in the Muskie entity for an investment interest in Mammoth. Thus, the Partnership determined that the non-cash exchange of the Partnership's ownership interest in Muskie did not result in any gain or loss. Prior to the Partnership's contribution of Muskie to Mammoth, the Partnership recorded its

proportionate portion of operating losses for 2014 and 2013, approximately $0.1 million and $0.5 million, respectively, for Muskie. As of December 31, 2014, the Partnership has recorded its investment in Mammoth of $1.9 million as a long-term asset, which the Partnership has accounted for as a cost method investment based upon its ownership percentage. As of December 31, 2013, the Partnership had recorded its equity method investment of $1.8 million in the Muskie joint venture as a long-term asset. The Partnership has included its investment in Mammoth and its prior investment in Muskie in its Other category for segment reporting purposes. See Note 21 for information on the Partnership's reportable segments.

In September 2014, the Partnership made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC ("Sturgeon"), with affiliates of Wexford Capital and Gulfport. Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. The Partnership accounts for the investment in this joint venture and results of operations under the equity method based upon its ownership percentage. The Partnership recorded its proportionate portion of the operating income for this investment during 2014 of approximately $0.4 million. The Partnership has recorded its investment in Sturgeon on the Investment in unconsolidated affiliates line of the Partnership's consolidated statements of financial position. The Partnership has included its investment in Sturgeon in its Other category for segment reporting purposes.

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 15, "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 April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity" ("ASU 2014-08"). ASU 2014-08 changes the requirements for reporting discontinued operations in Accounting Standards Codification ("ASC") 205, Presentation of Financial Statements, by updating the criteria for determining which disposals can be presented as discontinued operations and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of discontinued operations. ASU 2014-08 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. The adoption of ASU 2014-08 on January 1, 2015 is not expected to have a material impact on the Partnership's financial statements.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"). ASU 2014-09 clarifies the principles for recognizing revenue and establishes a common revenue standard for U.S. financial reporting purposes. The guidance in ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). ASU 2014-09 supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific accounting guidance. Additionally, ASU 2014-09 supersedes some cost guidance included in ASC 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of ASC 360, Property, Plant, and Equipment, and intangible assets within the scope of ASC 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in ASU 2014-09. ASU 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application of ASU 2014-09 is not permitted. The Partnership is currently evaluating the requirements of this new accounting guidance.

On January 20, 2015, the Partnership announced a cash distribution of $0.05 per common unit, or $0.20 per unit on an annualized basis. This distribution was paid on February 13, 2015 to all common unit holders of record as of the close of business on January 30, 2015. No distributions were paid on the subordinated units. The Partnership's common units accrue arrearages every quarter when the distribution level is below the minimum level of $0.445 per unit, as outlined in the Partnership agreement. The Partnership's distributions for the quarters ended September 30, 2014 and December 31, 2014 were below the minimum level and the current amount of accumulated arrearages as of December 31, 2014 related to the common unit distribution is approximately $13.7 million.

In January 2015, the Partnership completed a Membership Transfer Agreement (the "Transfer Agreement") with an affiliate of Patriot that terminated the Rhino Eastern joint venture. Pursuant to the Transfer Agreement, Patriot sold and assigned its 49% membership interest in the Rhino Eastern joint venture to the Partnership and, in consideration of this transfer, Patriot received certain fixed assets, leased equipment and coal reserves associated with the mining area previously operated by the Rhino Eastern joint venture. Patriot also assumed substantially all of the active workforce related to the Eagle mining area that was previously employed by the Rhino Eastern joint venture. The Partnership retained approximately 34 million tons of coal reserves that are not related to the Eagle mining area as well as a prepaid advanced royalty balance of $6.3 million. As part of the closing of the Transfer Agreement, the Partnership and Patriot agreed to a dissolution payment based upon a final working capital adjustment calculation as defined in the Transfer Agreement. As of December 31, 2014, the Partnership recorded an impairment charge of approximately $5.9 million related to its investment in the Rhino Eastern joint venture based upon the fair value of the assets received and liabilities assumed in the dissolution of the joint venture compared to the Partnership's carrying amount of its investment in the joint venture.

The Partnership and an affiliate of Wexford Capital participated with Gulfport 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% interest in approximately 80,000 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 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 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 acres, or approximately 6,250 net acres. As of December 31, 2013, the Partnership had invested approximately $31.1 million for its pro rata interest in the Utica Shale portfolio of oil and gas leases, which consisted of a 5% interest in a total of approximately 152,300 gross acres, or approximately 7,615 net acres. In addition, per the joint operating agreement among the Partnership, Gulfport and an affiliate of Wexford Capital, the Partnership had funded its proportionate share of drilling costs to Gulfport for wells being drilled on the Partnership's acreage. As of December 31, 2013, the Partnership had funded approximately $23.3 million of drilling costs. The Partnership's investment in the Utica Shale oil and gas leases as well as the proportionate amount of funded drilling costs are recorded in Non-current assets held for sale in the unaudited condensed consolidated statements of financial position as of December 31, 2013. For the year ended December 31, 2013, the Partnership recorded revenue from its Utica Shale investment of approximately $5.6 million and recognized pre-tax profit of approximately $1.3 million, which is recorded in Income from discontinued operations in the consolidated statements of operations and comprehensive income.

In March 2014, the Partnership completed a purchase and sale agreement (the "Purchase Agreement") with Gulfport to sell the Partnership's oil and natural gas properties in the Utica Shale region for approximately $184.0 million (the "Purchase Price"). The Purchase Agreement was effective as of January 1, 2014 and the Purchase Price was adjusted for any unsettled expenditures made and/or proceeds received from the Partnership's portion of its Utica Shale properties prior to the effective date. At the closing of the Purchase Agreement, the Partnership was immediately due approximately $179.0 million, net of any adjustments described above, and the remaining approximately $5.0 million was scheduled to be paid within approximately 90 days of March 20, 2014, subject to ongoing legal title work related to specific properties. In December 2014, the Partnership settled the remaining $5.0 million due from Gulfport based upon net amounts payable from the Partnership to Gulfport prior to the effective date of the Purchase Agreement as well as amounts due the Partnership related to legal reviews of the properties subject to the Purchase Agreement and other unsettled items due to the Partnership prior to the effective date of the Purchase Agreement. The net effect of this settlement resulted in the Partnership paying Gulfport approximately $46,000 in December 2014. The Partnership recorded a gain of approximately $121.7 million during the year ended December 31, 2014 related to this sale, which is recorded in Income from discontinued operations in the consolidated statements of operations and comprehensive income. The gain from the Utica Shale transaction is included in the (Gain) on sale/disposal of assets—net line in the operating activities section of the Partnership's consolidated statements of cash flows. The proceeds from the Utica Shale transaction are included in

the Proceeds from sales of property, plant, and equipment line in the investing activities section of the Partnership's consolidated statements of cash flows.

In January 2014, the Partnership received approximately $8.4 million of net proceeds from the sale by Blackhawk Midstream LLC ("Blackhawk") of its equity interest in two entities, Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, to Summit Midstream Partners, LLC. As part of the joint operating agreement for the Utica Shale investment discussed above, the Partnership had the right to approximately 5% of the proceeds of the sale by Blackhawk. The Partnership recorded this $8.4 million in Income from discontinued operations in the consolidated statements of operations and comprehensive income. The gain from the Blackhawk transaction is included in the (Gain) on sale/disposal of assets—net line in the operating activities section of the Partnership's consolidated statements of cash flows. The proceeds from the Blackhawk transaction are included in the Proceeds from sales of property, plant, and equipment line in the investing activities section of the Partnership's consolidated statements of cash flows.

Prepaid expenses and other current assets as of December 31, 2014 and 2013 consisted of the following:

Property, plant and equipment, including coal properties and mine development and construction costs, as of December 31, 2014 and 2013 are summarized by major classification as follows:

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal and oil and natural gas 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, 2014, 2013 and 2012 was as follows:

Due to the prolonged weakness in the U.S. coal markets and the dim prospects for an upturn in the coal markets in the near term, in the fourth quarter of 2014, the Partnership performed a comprehensive review of its current coal mining operations as well as potential future development projects to ascertain any potential impairment losses. The Partnership's appointment of new executive management in the fourth quarter of 2014 and the Partnership's annual budgeting process in the fourth quarter of 2014 led to some changes in the Partnership's strategic views. The Partnership identified various properties, projects and operations that were potentially impaired based upon changes in its strategic plans, market conditions or other factors. The Partnership recorded approximately $45.3 million of asset impairment and related charges for the year ended December 31, 2014, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income. As discussed in Note 3, the Partnership also recorded an impairment charge of $5.9 million related to the Rhino Eastern joint venture that is recorded on the Equity in net (loss)/income of unconsolidated affiliates line of the consolidated statements of operations and comprehensive income. The major components that comprise this total asset impairment and related charges are described below.

The Partnership controls certain mineral rights and related surface land located eleven miles north of Loma , Colorado (referred to as the "Red Cliff" property). The Partnership had been working with the U.S. Bureau of Land Management ("BLM") agency since 2005 on an environmental impact statement report ("EIS report") that was required to be completed before the Partnership could move forward with the development and permitting of a mining project on the Red Cliff property. The Partnership capitalized the cost associated with the ongoing EIS report process as mine development costs, which had accumulated to approximately $11.2 million at December 31, 2014. In addition, the Partnership invested approximately $11.0 million to acquire land for the purpose of building a rail spur to the property and also purchased certain land tracts at a cost of approximately $5.0 million for the purpose of constructing a rail load-out facility. At December 31, 2014, the Partnership had a carrying amount of approximately $16.2 million for the purchased land and approximately $2.0 million for mineral rights associated with a lease of coal reserves with the BLM. These amounts are in addition to the $11.2 million of mine development cost discussed above. Additionally, the Partnership had $0.3 million of accrued liabilities in BLM refunds related to the Red Cliff EIS report. In summary, the Partnership had total carrying costs of approximately $29.1 million for the Red Cliff property at December 31, 2014 that was included in the Partnership's Rhino Western segment. In early 2010, the Partnership had a detailed mine development study performed for the Red Cliff property by an independent third party, which estimated the total cost to build out the project would be approximately $420 million once the EIS report was finalized.

on chapters three and four was ready to begin in November 2014. Chapters three and four of the EIS report involve the costlier portion of report project since this includes detailed studies of the impacts to air quality, wildlife, etc. Up to the fourth quarter of 2014, the Partnership had decided to continue with the EIS report despite the prolonged weakness in the coal markets. However, the decision was made by the Partnership's executive management to limit capital spending on all projects due to the weak coal market conditions that had adversely affected the Partnership's financial results during 2014. Thus, due to the lack of progress in getting the EIS report finalized, the amount of money spent on the project to date, the impending higher costs to be incurred on the next phase of the EIS report and the desire to limit capital spending on certain projects due to the ongoing weakness in the coal markets, the Partnership decided to suspend the EIS report process in November 2014. Based on the fact pattern described above, the Partnership determined at December 31, 2014 that it would not pursue the development of the Red Cliff property and the related assets would be abandoned or sold for current market value.

Since the Partnership reached a decision to abandon the potential development of the Red Cliff asset group at December 31, 2014, the Partnership evaluated the assets for impairment in accordance with applicable accounting guidelines. The Partnership determined that the mine development costs and mineral rights could not be sold to a third party, so the Partnership recorded an asset impairment loss of $13.2 million for the year ended December 31, 2014 for these assets, which represented the write down of the previous carrying value of these assets to zero. The land related to the Red Cliff project was recorded at fair value (based on a third party appraisal) less costs to sell for a total net fair value of approximately $6.9 million since the Partnership had committed to a plan to sell these assets, which resulted in an additional asset impairment charge of $9.3 million. In total, after netting the $0.3 million of BLM refunds that will not be repaid due to abandoning the EIS report process, the Partnership recorded asset impairment and related charges of $22.2 million related to its Red Cliff assets at December 31, 2014. The $6.9 million of land is recorded on the Non-current assets held for sale line of the Partnership's consolidated statements of financial position.

In June 2011, the Partnership acquired coal mineral rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million (referred to as the "Rich Mountain" property). These development stage properties were unpermitted and contained no infrastructure. The Partnership conducted a core drilling program on the Rich Mountain property after it was purchased and determined the property contained an estimated 8.2 million tons of proven and probable underground metallurgical coal reserves. The Partnership capitalized the cost associated with its core drilling as mine development costs and the total value in property, plant and equipment for the Rich Mountain property was $8.3 million at December 31, 2014. The Partnership included this property in its Other category for segment reporting purposes since it was undeveloped.

The ongoing deterioration in the metallurgical coal markets has resulted in weak demand and historically low prices for this quality of coal. In the fourth quarter of 2014, the Partnership reassessed its strategy for these mineral rights and determined that it was not economical to develop this small coal reserve given the cost of building the required infrastructure. Although the Partnership did not have an active marketing strategy for the Rich Mountain property, the Partnership contacted a third

party coal company with current operations in the general area of the Rich Mountain property to determine if there would be any interest in acquiring these mineral rights. Repeated attempts to obtain a non-binding price quote for the Rich Mountain mineral rights from this or other third parties resulted in no indicative bids being offered. Based on the factors discussed above, the Partnership determined at December 31, 2014 that it would not pursue the development of the Rich Mountain property and the related assets would be abandoned.

In accordance with applicable accounting guidelines, the Partnership reviewed its Rich Mountain assets as of December 31, 2014 for any impairment indicators that may have been present for this long-lived asset group. Since the Partnership reached a decision to abandon the potential development of this asset group, the Partnership recorded an asset impairment loss of $8.3 million for the year ended December 31, 2014, which represented the write down of the previous carrying value of this asset group to zero. The Partnership determined the Rich Mountain assets had zero value since the Partnership could not solicit any financial bid for the Rich Mountain assets and the Partnership does see any alternative uses of the mineral right assets in their current state to generate value.

The Partnership has a steam coal surface mine operation in eastern Kentucky (referred to as "Bevins Branch") in its Central Appalachia segment that was idled during mid-2014 as that location's contract with its single customer expired at that time. The Partnership actively attempted to market the coal from this operation to potential new customers and had maintained the mine so that production could resume in a relatively short time period whenever new customers could be secured. The Partnership had unsuccessfully been able to market the coal from this operation as the coal markets have been especially weak for coal from Central Appalachia and the lower quality of coal from the Bevins Branch operation proved especially difficult to market. As the Partnership found it difficult to market the quality of coal found at this mine in the current market place, the Partnership initiated negotiations in October 2014 with a third party for the potential sale of the Bevins Branch operation. At December 31, 2014, the Partnership received a letter of intent from the third party interested in the Bevins Branch operation to accept ownership of this operation, including its related reclamation obligations. The Partnership is finalizing the contractual agreement with this third party to assume the Bevins Branch operation. The contractual agreement has the third party assume the Bevins Branch operation where the only financial compensation the Partnership will receive is a future override royalty and the assumption of the reclamation obligations by the buyer. The closing of the transaction would also allow the Partnership to avoid the ongoing maintenance costs of this operation. The Partnership considered these events to warrant an impairment analysis for this operation as of December 31, 2014.

The Partnership reviewed the Bevins Branch operation as of December 31, 2014 in accordance with the accounting guidance for long-lived asset impairment. Since the Partnership received a letter of intent at December 31, 2014 to transfer this operation to a third party, the Partnership determined this asset group should be written down to an estimated fair value of approximately $2.4 million, which equates to the estimated fair value of the future royalty of approximately $0.2 million and the benefit to be recognized of transferring the reclamation obligations of approximately $2.2 million. Based on this analysis, the Partnership recorded total asset impairment and related charges of $8.3 million for the Bevins Branch operation for the year ended December 31, 2014. The total asset impairment and

related charges include approximately $1.7 million for the write-off of advanced royalty balances related to the Bevins Branch operation that the Partnership does not expect to recover in the future. The Partnership also recorded an $6.6 million write-down of mineral value and mine development costs to the estimated fair value of $2.4 million of the royalty asset and benefit from transferring the reclamation obligations. The Partnership has reported the remaining assets and any related liabilities as held for sale on its consolidated statements of financial position as of December 31, 2014.

As of December 31, 2014, the Partnership also performed a comprehensive review of its other mining operations, primarily in Central Appalachia since this region has experienced the most extensive downturn in the coal markets, to determine if any other assets might be potentially impaired. The Partnership's review resulted in an additional $6.5 million of asset impairment and related charges, with $3.2 million related to mineral rights, $1.8 million of mine development costs and $1.5 million of advanced royalties that the Partnership does not expect to recover. The majority of these additional charges, approximately $4.9 million, related to low quality steam coal operations in Central Appalachia that the Partnership determined were uneconomical to mine due to the ongoing downturn in the markets for this quality of coal. The remaining $1.5 million primarily related to advanced royalties that the Partnership does not expect to recover at its Central Appalachia operations, which were determined as part of the Partnership's strategic reviews that were conducted in the fourth quarter of 2014.

During the fourth quarter of 2013, the Partnership's management made a strategic decision to permanently close the mining operations at its McClane Canyon complex in Colorado. Since the McClane Canyon complex had been idled at the end of 2010, the Partnership had been actively marketing the coal from this complex to potential buyers, but had not been able to obtain suitable sales contracts. Due to the unfavorable long-term prospects for the coal market in the Colorado area and to avoid the ongoing costs that were being incurred to temporarily idle this complex, the Partnership's management made the decision to permanently close this operation at the end of 2013. While a portion of the equipment from this operation was relocated to other operating locations, the Partnership incurred an impairment charge of approximately $1.7 million during 2013 related to specific property, plant and equipment, which is included on the Asset impairment and related charges line of the Partnership's consolidated statements of operations and comprehensive income.

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 was subsequently required to pay an additional $3.0 million related to this acquisition after certain conditions were 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. 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 balance of $0.4 million was paid

in the fourth quarter of 2013 since the conditions requiring payment had been met. The remaining $1.0 million was paid in the third quarter of 2014 due to conditions that were met in the quarter requiring payment and this additional $1.0 million was recorded in Property, plant and equipment.

The coal leases and property are estimated to contain approximately 32.4 million tons of proven and probable coal reserves as of December 31, 2014 that are contiguous to the Green River. The property was initially 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 mid-2014, the Partnership completed the initial construction of a new underground mining operation on the purchased property, referred to as the Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. Production and sales from this new underground mine began in mid-2014.

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) on sale/disposal 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) on

sale/disposal 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) on sale/disposal of assets, net line of the Partnership's consolidated statements of operations and comprehensive income.

In March 2012, the Partnership completed a lease agreement with a third party for approximately 1,232 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 the approximately 1,232 acres. 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. 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 April 2013, the Partnership closed on an agreement with a third party to sell the 20% royalty interest on its owned 1,232 acres in the Utica Shale for approximately $10.5 million. The sale of the royalty interest resulted in a gain of approximately $10.5 million since the Partnership had no cost basis associated with the royalty interest. This gain is included on the (Gain) on sale/disposal of assets—net line of the Partnership's consolidated statements of operations and comprehensive income.

In September 2013, the Partnership closed on an agreement with a third party to sell the oil and natural gas mineral rights for approximately 57 acres the Partnership owns in the Utica Shale region in Harrison County, Ohio for approximately $0.6 million. The sale of this acreage resulted in a gain of approximately $0.6 million since the Partnership had no cost basis associated with this property. This

gain is included on the (Gain) on sale/disposal of assets—net line of the Partnership's consolidated statements of operations and comprehensive income.

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, 2014 consisted of the following:

Intangible assets of the Partnership as of December 31, 2013 consisted of the following:

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

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, 2014, 2013 and 2012 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, 2014:

Other non-current assets as of December 31, 2014 and 2013 consisted of the following:

Debt issuance costs were $9.1 million and $9.0 million as of December 31, 2014 and 2013, respectively. Accumulated amortization of debt issuance costs were $7.6 million and $5.5 million as of December 31, 2014 and 2013, respectively. In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility that reduced the borrowing capacity to $200 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, which was recorded as an addition to Debt issuance costs. In addition, the Partnership wrote-off approximately $1.1 million of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility. See Note 10 for further information on the amendment to the amended and restated senior secured credit facility.

As of December 31, 2014 and 2013, the non-current receivable balance of $14.2 million and $4.3 million, respectively, consisted of the amount due from the Partnership's workers' compensation and black lung insurance providers for potential claims that are the primary responsibility of the Partnership, but are covered under the Partnership's insurance policies. See Note 12 for a discussion of the $14.2 million and $4.3 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, 2014 and 2013 consisted of the following:

The $0.5 million and $2.6 million accrued for insured litigation claims as of December 31, 2014 and 2013, respectively, consists of probable and estimable litigation claims that are the primary obligation of the Partnership. The amount accrued for litigation claims decreased due to the settlement of various litigation claims during the year ended December 31, 2014. 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. This presentation has no impact on the Partnership's results of operations or cash flows.

Senior Secured Credit Facility with PNC Bank, N.A.—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 was $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 was available for letters of credit. As described below, in March 2014 the amended and restated credit facility was amended and the borrowing capacity under the facility was reduced to $200 million, with the amount available for letters of credit unchanged. 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, 2014. The amended and restated senior secured credit facility expires in July 2016.

In April 2013, the Partnership entered into an amendment of its 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 amendment provided for an increase in the maximum allowed investments in coal-related entities outside of the Partnership (i.e. joint ventures) under the amended and restated senior secured credit facility from $25 million to $40 million. The amendment also altered the maximum leverage ratio allowed under the amended and restated senior secured credit facility and also altered the pricing grid to include applicable interest rates for borrowings, letter of credit fees and commitment fees on unused borrowings based upon the new maximum leverage ratio. The amendment increased the maximum leverage ratio of the amended and restated senior secured credit facility to 3.75 from April 1, 2013 through March 31, 2015, then stepped the maximum leverage ratio down to its previous level of 3.0 after December 31, 2015. All other terms of the amended and restated senior secured credit facility were not affected by the amendment. As part of executing the amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $1.0 million to the lenders in April 2013, 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 (used in) financing activities in the Partnership's consolidated statements of cash flows.

In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. This second amendment permitted the Partnership to sell certain assets to Gulfport, as described in Note 4, which previously constituted a portion of the collateral under the amended and restated senior secured credit facility. This second amendment also reduces the borrowing capacity under the amended and restated senior secured credit facility to a maximum of $200 million and alters the maximum leverage ratio to 3.5 from January 1, 2014 through September 30, 2015. The maximum leverage ratio decreases to 3.25 from October 1, 2015 through December 31, 2015 and then decreases to 3.0 after December 31, 2015. In addition, the second amendment adjusts the maximum investments (other than by the Partnership) in hydrocarbons, hydrocarbon interests and assets and activities related to hydrocarbons, in each case, excluding coal, in an aggregate amount not

to exceed $50 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, 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 (used in) financing activities in the Partnership's consolidated statements of cash flows. In addition, the Partnership recorded a non-cash charge of approximately $1.1 million to write-off a portion of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility, which was recorded in Interest expense on the Partnership's consolidated statements of operations and comprehensive income.

At December 31, 2014, the Operating Company had borrowed $54.5 million at a variable interest rate of LIBOR plus 2.50% (2.66% at December 31, 2014). In addition, the Operating Company had outstanding letters of credit of $15.8 million at a fixed interest rate of 2.50% at December 31, 2014. Based upon a maximum borrowing capacity of 3.5 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $126.7 million of the borrowing availability at December 31, 2014.

For each the years ending December 31, 2014 and 2013, the Partnership capitalized interest costs of approximately $0.1 million, which was related to the construction of its Pennyrile mine in western Kentucky. The Partnership did not capitalize any interest costs during the year ended 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 recorded a discount for imputed interest at a rate of 5.0% on this note that was being amortized over the life of the note using the effective interest method. The note payable was fully repaid as of December 31, 2014.

Principal payments on long-term debt due subsequent to December 31, 2014 are as follows:

The changes in asset retirement obligations for the years ended December 31, 2014, 2013 and 2012 are as follows:

Certain of the Partnership's subsidiaries are liable under federal and state laws to pay workers' compensation and coal workers' 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.

The Partnership's black lung benefit liability is calculated using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation. The Partnership's actuarial calculations using the service cost method for its black lung benefit liability are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates. The Partnership's liability for traumatic workers' compensation injury claims is the estimated present value of current workers' compensation benefits, based on actuarial estimates. The Partnership's actuarial estimates for its workers' compensation liability are based on numerous assumptions including claim development patterns, mortality, medical costs and interest rates. The discount rate used to calculate the estimated present value of future obligations for black lung was 4.0% and 5.0%, respectively, for December 31, 2014 and 2013 and for workers' compensation was 2.0% at December 31, 2014 and 2013.

The black lung and workers' compensation expenses for the years ended December 31, 2014, 2013 and 2012 are as follows:

The changes in the black lung benefit liability for the years ended December 31, 2014, 2013 and 2012 are as follows:

The classification of the amounts recognized for the Partnership's workers' compensation and black lung benefits liability as of December 31, 2014 and 2013 are as follows:

The balance for insured black lung and workers' compensation claims as of December 31, 2014 and 2013 consisted of $14.2 million and $4.3 million, respectively, 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 increase in the 2014 balance compared to 2013 is primarily due to an expected increase in the frequency and success of entitlement claims for black lung exposure, which the Partnership believes is due to the Patient Protection and Affordable Care Act. 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 ASC Topic 210. This presentation has no impact on the Partnership's results of operations or cash flows.

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, 2014, 2013 and 2012 are as follows:

The classification of net amounts recognized for postretirement benefits as of December 31, 2014 and 2013 are as follows:

The amounts recognized in accumulated other comprehensive income for the years ended December 31, 2014, 2013 and 2012 are as follows:

The amounts reclassified from accumulated other comprehensive income to Cost of operations in the Partnership's consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 was $0.4 million, $0.1 million and $0.3 million, respectively.

The components of net periodic benefit cost for the years ended December 31, 2014, 2013 and 2012 are as follows:

Amounts expected to be amortized from accumulated other comprehensive income into net periodic benefit cost during the year ending December 31, 2015, are as follows:

For benefit obligation measurement purposes, a 7.10% 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 based upon the assumptions used by the Partnership. As of December 31, 2014, 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, 2014, 2013 and 2012 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, 2014, the General Partner had granted phantom units to certain employees and restricted units and unit awards to its directors. These grants consisted of annual restricted unit awards to directors and phantom unit awards with tandem distribution equivalent rights ("DERs") granted in the first quarters of 2014, 2013 and 2012 to certain employees in connection with the prior fiscal year's performance. The DERs consist of rights to accrue quarterly cash distributions in an amount equal to the cash distribution the Partnership makes to unitholders during the vesting period. These awards are subject to service based vesting conditions and any accrued distributions will be forfeited if the related awards fail to vest according to the relevant service based vesting conditions. The phantom units granted in the first quarters of 2014, 2013 and 2012 vest in equal annual installments over a three year period from the date of grant. A summary of non-vested LTIP awards as of and for the years ended December 31, 2014, 2013 and 2012 is as follows:

The Partnership accounts for its unit-based awards as liabilities with applicable mark-to-market adjustments at each reporting period because the Compensation Committee of the board of directors of the General Partner has historically elected to pay some of the awards in cash in lieu of issuing common units.

For the years ended December 31, 2014, 2013 and 2012, the Partnership recorded expense of approximately $0.3 million, approximately $0.7 million and approximately $0.9 million, respectively, for the LTIP awards. For the year ended December 31, 2014, the total fair value of the awards that vested was $0.4 million. As of December 31, 2014, the total unrecognized compensation expense related to the non-vested LTIP awards that are expected to vest was $0.5 million. The expense is expected to be recognized over a weighted-average period of 1.5 years. As of December 31, 2014, the intrinsic value of the non-vested LTIP awards was $0.1 million.

During the first quarter of 2015, certain employees received grants of phantom units with tandem DERs under the LTIP program. These awards were granted in connection with fiscal year 2014 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 $0.1 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, 2014, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

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, 2014, the Partnership had a commitment to purchase approximately 1.0 million gallons of diesel fuel at fixed prices from January 2015 through December 2015 for approximately $2.5 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, 2014, 2013 and 2012 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, 2014, 2013 and 2012 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 $15.8 million as of December 31, 2014. 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 $70.2 million as of December 31, 2014 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 Ventures—The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012. The Partnership did not make any capital contributions to the Timber Wolf joint venture during the year ended December 31, 2014.

The Partnership was required to contribute additional capital to the Muskie Proppant joint venture that was formed in the fourth quarter of 2012. During the years ended December 31, 2014 and 2013, the Partnership made capital contributions to the Muskie Proppant joint venture of approximately $0.2 million and $0.5 million, respectively, based upon its proportionate ownership percentage. In addition, during the year ended December 31, 2013, the Partnership provided a loan based upon its ownership share to Muskie in the amount of $0.2 million. The note was fully repaid in November 2014 in conjunction with the contribution of the Partnership's interests in Muskie to Mammoth. With the contribution of the Partnership's interest in Muskie to Mammoth in the fourth quarter of 2014, the Partnership does not have any further funding commitments to Mammoth.

The Partnership may contribute additional capital to the Sturgeon joint venture that was formed in the third quarter of 2014. The Partnership made an initial capital contribution of $5.0 million during the year ended December 31, 2014 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, 2014, 2013 and 2012:

Year ended December 31, 2014	General Partner			Common Unitholders			Subordinated Unitholders

	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net (loss) from continuing operations	$	(1,626	)	$	(45,705	)	$	(33,962	)
Net income from discontinued operations		2,607			73,271			54,464

Interest in net income	$	981		$	27,566		$	20,502
Denominator:
Weighted average units used to compute basic EPU		n/a			16,678			12,397
Effect of dilutive securities—LTIP awards		n/a			7			—

Weighted average units used to compute diluted EPU		n/a			16,685			12,397
Net (loss)/income per limited partner unit, basic:
Net (loss) per unit from continuing operations		n/a		$	(2.74	)	$	(2.74	)
Net income per unit from discontinued operations		n/a			4.39			4.39

Net income per limited partner unit, basic		n/a		$	1.65		$	1.65
Net (loss)/income per limited partner unit, diluted:
Net (loss) per unit from continuing operations		n/a		$	(2.74	)	$	(2.74	)
Net income per unit from discontinued operations		n/a			4.39			4.39

Net income per limited partner unit, diluted		n/a		$	1.65		$	1.65

Year ended December 31, 2013	General Partner		Common Unitholders		Subordinated Unitholders

	(in thousands, except per unit data)
Numerator:
Interest in net income:
Net income from continuing operations	$	162	$	4,448	$	3,501
Net income from discontinued operations		26		769		512

Interest in net income	$	188	$	5,217	$	4,013
Denominator:
Weighted average units used to compute basic EPU		n/a		15,751		12,397
Effect of dilutive securities—LTIP awards		n/a		9		—

Weighted average units used to compute diluted EPU		n/a		15,760		12,397
Net income per limited partner unit, basic:
Net income per unit from continuing operations		n/a	$	0.29	$	0.28
Net income per unit from discontinued operations		n/a		0.04		0.04

Net income per limited partner unit, basic		n/a	$	0.33	$	0.32
Net income per limited partner unit, diluted:
Net income per unit from continuing operations		n/a	$	0.29	$	0.28
Net income per unit from discontinued operations		n/a		0.04		0.04

Net income per limited partner unit, diluted		n/a	$	0.33	$	0.32

Year ended December 31, 2012	General Partner		Common Unitholders		Subordinated Unitholders

	(in thousands, except per unit data)
Numerator:
Interest in net income:
Net income from continuing operations	$	789	$	21,374	$	17,284
Net income from discontinued operations		1		48		39

Interest in net income	$	790	$	21,422	$	17,323
Denominator:
Weighted average units used to compute basic EPU		n/a		15,331		12,397
Effect of dilutive securities—LTIP awards		n/a		4		—

Weighted average units used to compute diluted EPU		n/a		15,335		12,397
Net income per limited partner unit, basic:
Net income per unit from continuing operations		n/a	$	1.39	$	1.39
Net income per unit from discontinued operations		n/a		0.01		0.01

Net income per limited partner unit, basic		n/a	$	1.40	$	1.40
Net income per limited partner unit, diluted:
Net income per unit from continuing operations		n/a	$	1.39	$	1.39
Net income per unit from discontinued operations		n/a		0.01		0.01

Net income per limited partner unit, diluted		n/a	$	1.40	$	1.40

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. There were no anti-dilutive units for the years ended December 31, 2014 and 2012. For the year ended December 31, 2013, approximately 12,000 LTIP granted phantom units were anti-dilutive.

The Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues or receivables (Note: customers with "n/a" had revenue or receivables below the 10% threshold in any period where this is indicated):

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, 2014. The fair value of the Partnership's senior secured credit facility is a Level 2 measurement.

For the year ended December 31, 2014, the Partnership had nonrecurring fair value measurements related to its assets and liabilities held for sale. These assets and liabilities are a result of the Partnership's impairment actions discussed in Note 6. The fair value of the assets and liabilities held for sale at December 31, 2014 were based upon the highest and best use of the respective nonfinancial assets and liabilities. The Partnership had approximately $6.9 million in land value related to its Red Cliff assets that were classified as held for sale at December 31, 2014. This land was valued using a market approach by a third party appraisal firm that determined the fair value of the asset based on sales of comparable property in the market along with other market factors such as competitive listings. The fair value of the Partnership's land held for sale at December 31, 2014 is a Level 2 measurement.

Additionally, the Partnership had approximately $2.4 million of assets and $2.2 million of liabilities held for sale at December 31, 2014 related to the Bevins Branch operation discussed in Note 6. The held for sale assets consisted of approximately $0.2 million of a future coal royalty income stream. The fair value of the future royalty income stream was determined by an income approach using a

discounted cash flow analysis with an appropriate discount rate. The fair value of the remaining $2.2 million of assets and liabilities held for sale related to the Bevins Branch operation was also determined by an income approach using a discounted cash flow analysis. The $2.2 million of assets and liabilities held for sale related to the reclamation obligation being transferred in the Bevins Branch transaction and the income approach used to determine the fair value was based on the Partnership's method to calculate its asset retirement obligations for reclamation, which is discussed in Note 2. The fair values of the Partnership's assets and liabilities held for sale at December 31, 2014 for the Bevins Branch operation are Level 3 measurements.

Related Party	Description	2014			2013			2012

		(in thousands)
Wexford Capital LP	Expenses for legal, consulting, and advisory services	$	131		$	149		$	213
Wexford Capital LP	Distributions paid		10,949			14,034			27,704
Wexford Capital LP	Partner's contribution		6			330			13
Rhino Eastern LLC	Equity in net (loss)/income of unconsolidated affiliate		(12,089	)		(4,268	)		6,014
Rhino Eastern LLC	Distributions from unconsolidated affiliate		—			—			2,958
Rhino Eastern LLC	Expenses for legal, health claims, workers' compensation and other expenses		4,610			4,666			6,175
Rhino Eastern LLC	Receivable for legal, health claims and workers' compensation and other expenses		223			999			559
Rhino Eastern LLC	Investment in unconsolidated affiliate		13,151			19,369			21,367
Timber Wolf Terminals LLC	Investment in unconsolidated affiliate		130			114			114
Muskie Proppant LLC	Investment in unconsolidated affiliate		—			1,761			1,743
Muskie Proppant LLC	Equity in net (loss) of unconsolidated affiliate		(63	)		(461	)		(257	)
Muskie Proppant LLC	Note receivable from unconsolidated affiliate		—			206			—
Mammoth Energy Partners LP	Investment in unconsolidated affiliate		1,933			—			—
Sturgeon Acquisitions LLC	Investment in unconsolidated affiliate		5,440			—			—
Sturgeon Acquisitions LLC	Equity in net income of unconsolidated affiliate		440			—			—

From time to time, employees from Wexford Capital perform legal, consulting, and advisory services to the Partnership. The Partnership incurred expenses of $0.1 million for the years ended December 31, 2014 and 2013 and $0.2 million for the year ended December 31, 2012 for legal, consulting, and advisory services performed by Wexford Capital.

For the year ended December 31, 2014, the $12.1 million equity in net loss of unconsolidated affiliate for Rhino Eastern includes the $5.9 million impairment charge for the joint venture that was discussed earlier.

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. The Partnership did not provide any loans to Rhino Eastern during 2014 or 2013.

From time to time, the Partnership has allocated and paid expenses on behalf of the Rhino Eastern joint venture. During the years ended December 31, 2014, 2013 and 2012, the Partnership paid expenses for legal, health claims and workers' compensation of $4.6 million, $4.7 million and $6.2 million, respectively, on behalf of Rhino Eastern that were subsequently billed and paid by Rhino Eastern to the Partnership.

Cash payments for interest were $4.0 million, $6.4 million and $6.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

The consolidated statement of cash flows for the year ended December 31, 2014 is exclusive of approximately $0.2 million of property, plant and equipment additions which are recorded in Accounts payable. The consolidated statements of cash flows for the year ended December 31, 2014 also excludes approximately $0.3 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, 2013 is exclusive of approximately $10.5 million of property, plant and equipment additions which are recorded in Accounts payable. The consolidated statements of cash flows for the year ended December 31, 2013 also excludes approximately $0.6 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, 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 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.

As of December 31, 2014, the Partnership has five reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western, Illinois Basin and Eastern Met. Additionally, the

Partnership has an Other category that includes its ancillary businesses. The Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which, as of December 31, 2014, together included one active underground mine, three active surface mines and four preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, the Central Appalachia segment includes the Partnership's Elk Horn coal leasing operations. The Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex and the Leesville field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of December 31, 2014. The Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2014. The Eastern Met segment included the Partnership's 51% equity interest in the results of operations of the Rhino Eastern joint venture, which owned the Rhino Eastern mining complex, located in West Virginia, and for which the Partnership served as manager. The Rhino Eastern joint venture was dissolved in January 2015. The 2014 financial results are shown since the joint venture owned, and the Partnership operated, this mining complex during the year. The Rhino Western segment includes the Partnership's underground mine in the Western Bituminous region at its Castle Valley mining complex in Utah. Beginning with 2014 year-end reporting, the Partnership has included a new reportable business segment, referred to as the Illinois Basin segment, which includes its new underground mine, preparation plant and river loadout facility at its Pennyrile mining complex located in western Kentucky, as well as its Taylorville field reserves located in central Illinois. The new Pennyrile mining complex began production and sales in mid-2014.

Beginning with 2013 year-end reporting, the Partnership initially included a reportable business segment for its oil and natural gas activities since the total assets for these operations met the quantitative threshold for separate segment reporting. The Oil and Natural Gas segment included the Partnership's Utica Shale activities, which were sold during the first quarter of 2014 as described in Note 4, as well as the Partnership's Cana Woodford activities, the Razorback drill pad construction operations and the Muskie joint venture to provide sand for fracking operations. Prior to 2013, the Partnership's oil and natural gas activities were included in its Other category for segment reporting purposes. Since the majority of the Partnership's oil and natural gas activities were in the Utica Shale and the Utica Shale financial results have been reclassified in discontinued operations due to their sale, the segment data for the Partnership's remaining oil and natural gas activities have been reclassified in the Other category for segment reporting purposes for all periods presented since they are not material for separate segment reporting.

The Partnership's Other category as reclassified is comprised of the Partnership's ancillary businesses and its remaining oil and natural gas activities. Held for sale assets are included in the applicable segment for reporting purposes. 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 segment expenditures for long lived assets, and accordingly such information is not provided to the Partnership's chief operating decision maker. The information provided in the following tables represents the primary measures used to assess segment performance by 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 considered this operation to comprise a separate operating segment prior to its dissolution in January 2015 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 or loss in 2014, 2013 and 2012, the Partnership has presented additional summarized financial information for this equity method investment below.

Reportable segment results of operations and financial position for the year ended December 31, 2014 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, 2013 are as follows:

Reportable segment results of operations and financial position for the year ended December 31, 2012 are as follows:

Additional summarized financial information for the equity method investment as of and for the periods ended December 31, 2014, 2013 and 2012 is as follows:

Additional information on the Partnership's revenue by product category for the periods ended December 31, 2014, 2013 and 2012 is as follows:

(in thousands, except per unit data)	First Quarter			Second Quarter			Third Quarter			Fourth Quarter(1)

2014:
Revenues	$	59,942		$	55,886		$	61,359		$	61,870
(Loss) from operations		(868	)		(4,445	)		(6,108	)		(52,726	)
Net (loss) from continuing operations		(4,966	)		(6,826	)		(8,864	)		(60,636	)
Income/(loss) from discontinued operations		130,511			(52	)		(43	)		(74	)

Net income/(loss)	$	125,545		$	(6,878	)	$	(8,907	)	$	(60,710	)
Basic and diluted net (loss)/income per limited partner unit:
Common units:
Net (loss) per unit from continuing operations	$	(0.17	)	$	(0.23	)	$	(0.30	)	$	(2.05	)
Net income per unit from discontinued operations		4.40			(0.00	)		(0.00	)		(0.00	)

Net income per common unit, basic and diluted	$	4.23		$	(0.23	)	$	(0.30	)	$	(2.05	)
Subordinated units:
Net (loss) per unit from continuing operations	$	(0.17	)	$	(0.23	)	$	(0.30	)	$	(2.05	)
Net income per unit from discontinued operations		4.40			(0.00	)		(0.00	)		(0.00	)

Net income per subordinated unit, basic and diluted	$	4.23		$	(0.23	)	$	(0.30	)	$	(2.05	)
Weighted average number of limited partner units outstanding, basic:
Common units		16,667			16,677			16,681			16,685
Subordinated units		12,397			12,397			12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units		16,673			16,677			16,681			16,685
Subordinated units		12,397			12,397			12,397			12,397

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

2013:
Revenues	$	74,467		$	65,613	$	69,501	$	62,684
Income from operations		2,955			9,546		5,070		2,959
Net (loss)/ income from continuing operations		(271	)		5,545		2,149		687
Income from discontinued operations		94			352		728		133

Net (loss)/income	$	(177	)	$	5,897	$	2,877	$	820
Basic and diluted net (loss)/income per limited partner unit:
Common units:
Net income per unit from continuing operations	$	(0.01	)	$	0.20	$	0.07	$	0.02
Net income per unit from discontinued operations		—			0.01		0.03		0.01

Net income per common unit, basic and diluted	$	(0.01	)	$	0.21	$	0.10	$	0.03
Subordinated units:
Net income per unit from continuing operations	$	(0.01	)	$	0.20	$	0.07	$	0.02
Net income per unit from discontinued operations		—			0.01		0.03		0.01

Net income per subordinated unit, basic and diluted	$	(0.01	)	$	0.21	$	0.10	$	0.03
Weighted average number of limited partner units outstanding, basic:
Common units		15,354			15,371		15,609		16,659
Subordinated units		12,397			12,397		12,397		12,397
Weighted average number of limited partner units outstanding, diluted:
Common units		15,354			15,379		15,621		16,672
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, 2014
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

	Price Range

	Price Range				Cash Distribution(1)
	High		Low		Cash Distribution(1)
Year ended December 31, 2014
Fourth Quarter	$	12.25	$	1.98	$	0.050
Third Quarter	$	14.65	$	11.38	$	0.050
Second Quarter	$	14.65	$	12.57	$	0.445
First Quarter	$	13.95	$	11.18	$	0.445
Year ended December 31, 2013
Fourth Quarter	$	13.49	$	9.81	$	0.445
Third Quarter	$	14.30	$	11.87	$	0.445
Second Quarter	$	14.83	$	12.77	$	0.445
First Quarter	$	17.04	$	12.82	$	0.445

	Non-Reserve Coal Deposits

			Total Tons
	Total Tons		Total Tons
Region	Total Tons		Owned			Leased
	(in million tons)
Central Appalachia		195.5		169.9			25.6
Northern Appalachia		31.2		26.8			4.4
Illinois Basin		33.7		—			33.7
Western Bituminous		29.6		—			29.6

Total		290.0		196.7			93.3



Percentage of total				67.83	%		32.17	%

	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, 2014

	(in thousands, except %)
Central Appalachia		1,261.6	1,507.7	(246.1	)	(16.3	)%
Northern Appalachia		1,015.5	1,225.0	(209.5	)	(17.1	)%
Rhino Western		1,066.7	940.2	126.5		13.5	%
Illinois Basin		213.5	—	213.5		n/a

Total*†		3,557.3	3,672.9	(115.6	)	(3.1	)%

(In thousands, except per ton data and %)	Year ended December 31, 2014		Year ended December 31, 2013

Met coal tons sold		337.0		597.9	(43.6	)%
Steam coal tons sold		924.6		909.8	1.6	%

Total tons sold†		1,261.6		1,507.7	(16.3	)%



Met coal revenue	$	26,058	$	53,721	(51.5	)%
Steam coal revenue	$	62,920	$	72,699	(13.5	)%

Total coal revenue†	$	88,978	$	126,420	(29.6	)%



Met coal revenues per ton	$	77.33	$	89.86	(13.9	)%
Steam coal revenues per ton	$	68.05	$	79.90	(14.8	)%

Total coal revenues per ton†	$	70.53	$	83.85	(15.9	)%



Met coal tons produced		333.3		570.5	(41.6	)%
Steam coal tons produced		928.9		958.7	(3.1	)%

Total tons produced†		1,262.2		1,529.2	(17.5	)%

(In thousands, except per ton data and %)	Year ended December 31, 2014			Year ended December 31, 2013

Eastern Met 100% Basis
Coal revenues	$	21,443		$	27,724		(22.7	)%
Total revenues	$	21,722		$	27,853		(22.0	)%
Coal revenues per ton*	$	97.76		$	111.27		(12.1	)%
Cost of operations	$	28,604		$	31,543		(9.3	)%
Cost of operations per ton*	$	130.41		$	126.60		3.0	%
Depreciation, depletion and amortization	$	1,860		$	1,949		(4.6	)%
Interest expense	$	81		$	17		391.1	%
Net income (loss)	$	(12,208	)	$	(8,369	)	(45.9	)%
Partnership's portion of net income (loss)**	$	(12,089	)	$	(4,268	)	(183.2	)%
Tons produced		212.5			205.4		3.5	%
Tons sold		219.3			249.2		(12.0	)%

(In thousands, except per ton data and %)	Year ended December 31, 2013		Year ended December 31, 2012

Met coal tons sold		597.9		467.8	27.8	%
Steam coal tons sold		909.8		1,288.3	(29.4	)%

Total tons sold†		1,507.7		1,756.1	(14.1	)%



Met coal revenue	$	53,721	$	59,511	(9.7	)%
Steam coal revenue	$	72,699	$	101,762	(28.6	)%

Total coal revenue†	$	126,420	$	161,273	(21.6	)%



Met coal revenues per ton	$	89.86	$	127.21	(29.4	)%
Steam coal revenues per ton	$	79.90	$	78.99	1.2	%

Total coal revenues per ton†	$	83.85	$	91.83	(8.7	)%



Met coal tons produced		570.5		468.3	21.8	%
Steam coal tons produced		958.7		1,336.2	(28.2	)%

Total tons produced†		1,529.2		1,804.5	(15.3	)%

	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)		57,432	$	210	$	54,915	$	532	$	1,775
Asset retirement obligations		32,133		1,431		5,632		3,168		21,902
Operating lease obligations(2)		4,417		1,538		2,686		193		—
Diesel fuel obligations		2,460		2,460		—		—		—
Advance royalties(3)		28,048		2,470		5,570		5,716		14,292
Retiree medical obligations		6,751		425		1,174		1,235		3,917

Total	$	131,241	$	8,534	$	69,977	$	10,844	$	41,886

Name		Position With Our General Partner

Mark D. Zand*	61	Chairman of the Board of Directors
Joseph E. Funk	54	President and Chief Executive Officer
Richard A. Boone	60	Executive Vice President and Chief Financial Officer
Reford C. Hunt	41	Senior Vice President of Business Development
Whitney C. Kegley	39	Vice President, Secretary and General Counsel
Brian T. Aug	43	Vice President of Sales
Arthur H. Amron*	58	Director
Kenneth A. Rubin*	60	Director
Joseph M. Jacobs*	61	Director
Mark L. Plaumann**	59	Director
Douglas Lambert**	57	Director
James F. Tompkins**	66	Director

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

Joseph E. Funk	$	872	$	10,400
Christopher I. Walton		2,584		10,400
Richard A. Boone		1,769		10,400
Reford C. Hunt		3,820		10,400
Whitney C. Kegley		—		8,880
Brian T. Aug		2,642		8,880

Name		Value of Units Granted ($)(1)

Joseph E. Funk	1,990	$	24,994
Christopher I. Walton	9,952		124,997
Richard A. Boone	3,583		45,002
Reford C. Hunt	1,354		17,006
Whitney C. Kegley	1,592		19,996
Brian T. Aug	876		11,003

	Unit Awards

Name	Number of Units That Have Not Vested (#)(1)		Market Value of Units That Have Not Vested ($)(2)
Joseph E. Funk		4,453	$	10,019
Christopher I. Walton		—		—
Richard A. Boone		7,350		16,538
Reford C. Hunt		3,155		7,099
Whitney C. Kegley		3,015		6,784
Brian T. Aug		876		1,971

	Unit Awards

Name	Number of Units Acquired Upon Vesting (#)		Value of Units Realized Upon Vesting ($)(1)
Joseph E. Funk		1,776	$	22,307
Christopher I. Walton		1,348	$	16,931
Richard A. Boone		2,391	$	30,031
Reford C. Hunt		1,135	$	14,256
Whitney C. Kegley		712	$	8,943
Brian T. Aug		—	$	—

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

Mark D. Zand(3)	$	30,000	$	25,002	$	—	$	55,002
Arthur H. Amron(3)	$	20,000	$	25,002	$	—	$	45,002
Joseph M. Jacobs(3)	$	20,000	$	25,002	$	—	$	45,002
Douglas Lambert(4)	$	40,000	$	25,002	$	—	$	65,002
Mark L. Plaumann(4)	$	50,000	$	25,002	$	—	$	75,002
Kenneth A. Rubin(3)	$	21,250	$	25,002	$	—	$	46,252
James F. Tompkins	$	40,000	$	25,002	$	—	$	65,002

Plan Category	Number of units to be issued upon exercise/vesting of outstanding options, warrants and rights as of December 31, 2014		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, 2014 (excluding units reflected in column (a))

	(a)		(b)			(c)
Equity compensation plans not approved by unitholders(1):
Long-Term Incentive Plan		40,248		n/a	(2)		2,263,284

	2014		2013

	(in thousands)
Audit fees(1)	$	782	$	724
Audit related fees		2		2
Tax fees(2)		8		8

Total	$	792	$	734

Exhibit Number			Description

	101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document


		RHINO RESOURCE PARTNERS LP
		By:		Rhino GP LLC, its general partner
		By:		/s/ JOSEPH E. FUNK Joseph E. Funk President and Chief Executive Officer

Signature	Title	Date


/s/ JOSEPH E. FUNK Joseph E. Funk	President and Chief Executive Officer (Principal Executive Officer)	March 11, 2015
/s/ RICHARD A. BOONE Richard A. Boone	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 11, 2015
/s/ MARK D. ZAND Mark D. Zand	Director	March 11, 2015
/s/ ARTHUR H. AMRON Arthur H. Amron	Director	March 11, 2015
/s/ KENNETH A. RUBIN Kenneth A. Rubin	Director	March 11, 2015
/s/ JOSEPH M. JACOBS Joseph M. Jacobs	Director	March 11, 2015

Signature	Title	Date


/s/ MARK L. PLAUMANN Mark L. Plaumann	Director	March 11, 2015
/s/ DOUGLAS LAMBERT Douglas Lambert	Director	March 11, 2015
/s/ JAMES F. TOMPKINS James F. Tompkins	Director	March 11, 2015


RHINO RESOURCE PARTNERS LP
Reports of Independent Registered Public Accounting Firms			F-2
Consolidated Statements of Financial Position as of December 31, 2014 and 2013			F-4
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013, and 2012			F-5
Consolidated Statements of Partners' Capital for the Years Ended December 31, 2014, 2013 and 2012			F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012			F-7
Notes to Consolidated Financial Statements			F-8

		December 31,

	Useful Lives	2014			2013
		(in thousands)
Land and land improvements		$	18,845		$	35,078
Mining and other equipment and related facilities	2 - 20 Years		336,951			302,114
Mine development costs	1 - 15 Years		79,536			73,344
Coal properties	1 - 15 Years		215,325			238,975
Oil and natural gas properties			8,093			8,093
Construction work in process			4,912			17,104

Total			663,662			674,708
Less accumulated depreciation, depletion and amortization			(280,225	)		(249,718	)

Net		$	383,437		$	424,990

Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount

	(in thousands)
Patent	$	728	$	250	$	478
Developed Technology		78		27		51
Trade Name		184		33		151
Customer List		470		83		387

Total	$	1,460	$	393	$	1,067

	Patent		Developed Technology		Trade Name		Customer List		Total

	(in thousands)
2015	$	43	$	5	$	9	$	23	$	80
2016		43		5		9		23		80
2017		43		5		9		23		80
2018		43		5		9		23		80
2019		43		5		9		23		80

	in thousands

2015	$	210
2016		54,675
2017		240
2018		257
2019		275
Thereafter		1,775

Total principal payments	$	57,432

	December 31,

	2014			2013
*Weighted Average assumptions used to determine benefit obligations:*
Discount rate		3.15	%		3.96	%
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	$	46	$	(42	)
Effect on postretirement benefit obligation	$	474	$	(441	)

	Common Units			Weighted Average Grant Date Fair Value (per unit)

	(in thousands)
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
Granted		49		$	13.50
Vested		(58	)	$	18.88
Forfeited		(3	)	$	16.62

Non-vested awards at December 31, 2013		55		$	14.63

Granted		46		$	12.32
Vested		(34	)	$	13.95
Forfeited		(16	)	$	13.01

Non-vested awards at December 31, 2014		51		$	13.50

	December 31, 2014 Receivable Balance		Year Ended December 31, 2014 Sales		December 31, 2013 Receivable Balance		Year Ended December 31, 2013 Sales		December 31, 2012 Receivable Balance		Year Ended December 31, 2012 Sales

	(in thousands)
NRG Energy Inc. (fka GenOn Energy, Inc.)	$	2,932	$	31,605	$	3,046	$	55,246	$	3,158	$	53,661
PPL Corporation		2,053		24,542		n/a		n/a		2,760		37,364
American Electric Power Company, Inc.		n/a		n/a		1,434		30,070		3,450		36,308
Indiana Harbor Coke Company, L.P.		n/a		n/a		n/a		n/a		6,597		40,133

	2014 (Unaudited)			2013			2012

	(in thousands)
Current assets	$	3,641		$	5,608		$	12,788
Noncurrent assets		38,459			39,183			39,805
Current liabilities		3,629			2,020			6,290
Noncurrent liabilities		3,202			4,794			4,496
Total costs and expenses		33,850			36,206			43,140
(Loss)/income from operations		(12,128	)		(8,353	)		12,081