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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549

Form 10-K

ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2010oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                                  to


Commission file number: 001-34892

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

Delaware(State or other jurisdiction of
incorporation or organization)

27-2377517(I.R.S. Employer
Identification No.)424 Lewis Hargett Circle, Suite 250
Lexington, KY(Address of principal executive offices)

40503(Zip Code)


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

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

Title of each class

Name of each exchange on which registeredCommon Units representing Limited Partner Interests

New York Stock Exchange


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

None

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

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

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

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

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

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a
smaller reporting company)

Smaller reporting company o


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

As of June 30, 2010, the last business day of the registrant's most recently completed second fiscal quarter, the registrant's equity was not listed on any
domestic exchange or over-the-counter market. The registrant's common units began trading on the New York Stock Exchange on September 30, 2010. As of March 14,
2011, the registrant had 12,406,760 common units and 12,397,000 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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



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TABLE OF CONTENTS



PART IItem 1.

Business

1Item 1A.

Risk Factors

24Item 1B.

Unresolved Staff Comments

52Item 2.

Properties

52Item 3.

Legal Proceedings

56Item 4.

(Removed and Reserved)

56PART IIItem 5.

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

57Item 6.

Selected Financial Data

61Item 7.

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

65Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

92Item 8.

Financial Statements and Supplementary Data

92Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

92Item 9A.

Controls and Procedures

92Item 9B.

Other Information

93PART IIIItem 10.

Directors, Executive Officers and Corporate Governance

94Item 11.

Executive Compensation

100Item 12.

Security Ownership of Certain Beneficial Owners and Management

115Item 13.

Certain Relationships and Related Transactions, and Director Independence

116Item 14.

Principal Accounting Fees and Services

119PART IVItem 15.

Exhibits, Financial Statement Schedules

120FINANCIAL STATEMENTSIndex to Financial Statements

F-1


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GLOSSARY OF KEY TERMS

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

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

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

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

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

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

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

EIA:Energy Information Administration.

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

GAAP:Generally accepted accounting principles in the United States.

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

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

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

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

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

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

metallurgical coal:The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality
depends on four important
criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which
affect coke oven safety. Metallurgical coal typically has a particularly high Btu but low ash and sulfur content.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This report contains "forward-looking statements". Statements included in this report that are not historical facts, that address
activities, events or developments that we expect or anticipate will or may occur in the future, including things such as our plans, strategies, prospects and expectations concerning our business,
operating results, financial condition and similar matters, are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including "may," "believe,"
"expect," "anticipate," "estimate," "continue" or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected
future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is
subject to numerous risks and uncertainties, many of which are beyond our control or our ability to predict. Therefore, actual outcomes and results could materially differ from what is expressed,
implied or forecast in these statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:



Readers
are cautioned not to place undue reliance on forward-looking statements. The forward-looking statements speak only as of the date made, and we undertake no obligation to publicly
update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I

Unless the context clearly indicates otherwise, references in this report to "Rhino Predecessor," "we," "our,"
"us" or similar terms when used in a historical context refer to Rhino Energy LLC and its subsidiaries, which were contributed to Rhino Resource Partners LP in connection with its
initial public offering, which was completed on October 5, 2010 (the "IPO"). When used in the present tense or prospectively, those terms refer to Rhino Resource Partners LP and its
subsidiaries. References to our "general partner" refer to Rhino GP LLC, the general partner of Rhino Resource Partners LP.

Item 1.    Business.

We are a growth-oriented Delaware limited partnership formed to control and operate coal properties and related assets. We produce,
process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam-powered generators. Customers for
our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process.

We
have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of
December 31, 2010, we controlled an estimated 309.0 million tons of proven and probable coal reserves, consisting of an estimated 297.0 million tons of steam coal and an estimated
12.0 million tons of metallurgical coal. In addition, as of December 31, 2010, we controlled an estimated 271.8 million tons of non-reserve coal deposits. As of
December 31, 2010, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and for which we serve as manager, controlled an estimated 22.2 million tons of
proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and
an estimated 34.3 million tons of non-reserve coal deposits. As of December 31, 2010, we operated ten mines, including five underground and five surface mines, located in
Kentucky, Ohio and West Virginia. In addition, our joint venture operates one underground mine in West Virginia. During 2010, we operated one underground mine in Colorado, but we temporarily idled
this mine at year end due to the expiration of our sole customer contract at this location. We are currently planning to restart production at this location in late 2011. Additionally, we began
production and customer shipments in January 2011 at one underground mine located in Emery and Carbon Counties in Utah that we had acquired out of bankruptcy in August of 2010. The number of mines
that we operate may vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of
experienced labor. Excluding results from the joint venture, for the year ended December 31, 2010, we produced approximately 4.0 million tons of coal, purchased approximately
0.3 million tons of coal and sold approximately 4.3 million tons of coal. Additionally, the joint venture produced and sold approximately 0.3 million tons of premium
mid-vol metallurgical coal for the year ended December 31, 2010.

Our
principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our diverse asset base in order to maintain, and, over
time, increase our quarterly cash distributions. In addition, we intend to expand our operations through strategic acquisitions, including the acquisition of stable, cash generating
non-coal natural resource assets. We believe that such assets would allow us to grow our cash available for distribution and enhance stability of our cash flow by, for example, serving as
a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel, steel products and other commodities consumed in the mining process.

History

Our predecessor was formed in April 2003 by Wexford Capital LP ("Wexford Capital", and together with its affiliates and
principals, "Wexford"). Wexford Capital is an SEC registered investment advisor which was formed in 1994 and manages a series of investment funds and has over $6.0 billion of assets under
management. Since the formation of our predecessor, we have significantly grown our

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coal
reserves. Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $223.3 million, including our acquisition in August 2010 of
certain mining assets of C.W. Mining Company out of bankruptcy. The assets acquired in August 2010 are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve
coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. Through these acquisitions and coal lease transactions, we
have substantially increased our proven and probable coal reserves and non-reserve coal deposits. In addition, we have successfully grown our production through internal development
projects.

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

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

Coal Operations

Mining Operations

As of December 31, 2010, we operated four mining complexes located in Central Appalachia (Tug River, Rob Fork, Deane and
Rhino Eastern (owned by the joint venture with an affiliate of Patriot Coal Corporation, or "Patriot")) and two mining complexes located in Northern Appalachia (Hopedale and Sands Hill). During 2010,
we operated one mine located in the Western Bituminous region in Colorado (McClane Canyon). The McClane Canyon mine was temporarily idled at year end due to the expiration of our sole customer
contract at this location. With production
temporarily idled, we are in the process of building and permitting a rail loadout at this location and we are currently planning to restart production at the McClane Canyon mine in late 2011. In
August 2010, we completed the acquisition of certain mining assets of C.W. Mining Company out of bankruptcy. The assets acquired are located in Emery and Carbon Counties, Utah and include coal
reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We began production
from these assets at one underground mine in January 2011.

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

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

GRAPHIC

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

The
following table summarizes our and the joint venture's mining complexes and production by region as of December 31, 2010:

Number and
Type of Active Mines(2)Tons Produced
for the
Year Ended
December 31,
2010(3)Region

Preparation
Plants and
Loadouts

Transportation
to Customers(1)

Company
Operated
Mines

Contractor
Operated
Mines

Total
Mines(in million tons)Central AppalachiaTug River Complex (KY, WV)

Jamboree(4)

Truck, Barge, Rail (NS)


1S





1S


0.2Rob Fork Complex (KY)

Rob Fork

Truck, Barge, Rail (CSX)


2U, 2S





2U, 2S


1.3Deane Complex (KY)

Rapid Loader

Rail (CSX)


1U


1U


2U


0.4Northern AppalachiaHopedale Complex (OH)

Nelms

Truck, Rail (OHC, WLE)


1U





1U


1.4Sands Hill Complex (OH)

Sands Hill(5)

Truck, Barge


2S





2S


0.6Illinois BasinTaylorville Field (IL)

n/a

Rail (NS)











Western BituminousCastle Valley Complex (UT)(6)

Truck loadout

Truck











McClane Canyon Mine (CO)(6)

n/a

Truck











0.2Total






4U,5S


1U


5U,5S


4.0Central AppalachiaRhino Eastern Complex (WV)(7)

Rocklick

Truck, Rail (NS, CSX)


1U





1U


0.3


(1)NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE =
Wheeling & Lake Erie Railroad.(2)Numbers
indicate the number of active mines. U = underground; S = surface.(3)Total
production based on actual amounts and not rounded amounts shown in this table.(4)Includes
only a loadout facility.(5)Includes
only a preparation plant.(6)The
Castle Valley mine began production in early 2011, while the McClane Canyon mine was temporarily idled as of December 31, 2010.(7)Owned
by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the production. The
Rocklick preparation plant is owned and operated by our joint venture partner with whom the joint venture has a transloading agreement for use of the facility.


Central Appalachia.As of December 31, 2010, we operated four mining complexes located in Central Appalachia consisting of
five active
underground mines, four of which are company-operated and one that is contractor-operated. In addition, we operated three company-operated surface mines. For the year ended December 31, 2010,
the mines at our Tug River, Rob Fork and Deane mining complexes produced an aggregate of approximately 1.2 million tons of steam coal and an estimated 0.7 million tons of metallurgical
coal, and the underground mine at the Rhino Eastern mining complex, owned by the joint venture in which we have a 51% membership interest and for which we serve as manager, produced approximately
0.3 million tons of metallurgical coal.

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Tug River Mining Complex.Our Tug River mining complex consists of property in Kentucky and West Virginia that borders the Tug River.
Our Tug River
mining complex produces coal from one company-operated surface mine. Coal production from this mine is delivered by truck to the Jamboree loadout for blending and loading or to the Rob Fork facilities
for processing, blending and loading. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit train loadout with batch weighing equipment. The Jamboree loadout is used
primarily to process surface mined coal which is sold as steam coal to electric utilities. This mining complex produced approximately 0.2 million tons of steam coal for the year ended
December 31, 2010.

Rob Fork Mining Complex.Our Rob Fork mining complex is located in eastern Kentucky and currently produces coal from two
company-operated surface
mines and two company-operated underground mines. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable
of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with
washed coals to meet a wide variety of customers' needs. The Rob Fork mining complex produced approximately 0.6 million tons of steam coal and 0.7 million tons of metallurgical coal for
the year ended December 31, 2010.

Deane Mining Complex.Our Deane mining complex is located in eastern Kentucky and produces steam
coal from one company-operated underground mine and one contractor-operated underground mine. The infrastructure consists of a preparation plant utilizing heavy media circuitry capable of cleaning
coarse and fine coal size fractions, as well as a unit train loadout facility with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in approximately four hours. The
facility has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers' needs. The Deane complex produced approximately
0.4 million tons of steam coal for the year ended December 31, 2010.

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

The
Rhino Eastern mining complex produces premium metallurgical coal from one company-operated underground mine. The joint venture acquired the Rhino Eastern complex in May 2008 and
commenced production in August 2008. Raw coal is trucked from the mine to a facility owned by our joint venture partner to be sized, washed and shipped by truck or via one of two rail loadouts,
located on the CSX Railroad and the Norfolk Southern Railroad. The Rhino Eastern mining complex produced approximately 0.3 million tons of premium mid-vol metallurgical coal for the
year ended December 31, 2010.

Northern Appalachia.We operate two mining complexes located in Northern Appalachia consisting of one company-operated
underground mine and two
company-operated surface mines. For the year ended December 31, 2010, these mines produced an aggregate of approximately 2.0 million tons of steam coal.

Hopedale Mining Complex.The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles
northeast of
Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad in Cadiz, Ohio and
then shipped by train or truck to the customer. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 1.4 million
tons of steam coal for the year ended December 31, 2010.

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Sands Hill Mining Complex.We operate two surface mines at our Sands Hill mining complex, located near Hamden, Ohio. In 2009, we
completed
construction of a river-front barge and dock facility on the Ohio River. The infrastructure also includes a preparation plant. The Sands Hill mining complex produced approximately 0.6 million
tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2010.

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

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

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

Castle Valley Mining Complex.In August 2010, we completed the acquisition of certain mining assets of C.W. Mining Company out of
bankruptcy. The
assets acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt
conveyor system, a loading facility and support
facilities. In January 2011, we began production from these assets at one underground mine. The coal we produce and sell from these mining assets is sold as steam coal in the Western Bituminous
region.

Other Non-Mining Operations

In addition to our mining operations, we operate several subsidiaries which provide auxiliary services for our coal mining operations.
Rhino Trucking provides our Kentucky coal operations with dependable, safe coal hauling to our preparation plants and loadout facilities and our southeastern Ohio coal operations with reliable
transportation to our customers where rail is not available. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining
reclamation. We have been able to efficiently supply internally the majority of these services, which were previously outsourced. Through Rhino Services, we plan and monitor each phase of our mining
projects as well as the post-mining reclamation efforts. We also perform the majority of our drilling and blasting activities at our company-operated surface mines in-house
rather than contracting to a third party. Our Triad Roof Support Systems subsidiary manufactures roof control products used in underground coal mining.

Other Natural Resource Assets

Incidental to our coal mining process, we mine limestone from reserves located at our Sands Hill mining complex and sell it as
aggregate to various construction companies and road builders that are located in close proximity to the mining complex when market conditions are favorable. We believe that

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our
production of limestone provides us with an additional source of revenues at low incremental capital cost.

Customers

General

Our primary customers for our steam coal are electric utilities, and the metallurgical coal we produce is sold primarily to domestic
and international steel producers. Excluding results from the joint venture, for the year ended December 31, 2010, approximately 84% of our coal sales tons consisted of steam coal and
approximately 16% consisted of metallurgical coal. For the year ended December 31, 2010, 100% of the joint venture's coal sales tons consisted of metallurgical coal. For the year ended
December 31, 2010, excluding results from the joint venture, approximately 74% of our coal sales tons that we produced were sold to electric utilities. In addition, for the year ended
December 31, 2010, excluding results from the joint venture, approximately 3% of our total coal sales tons were sold through the OTC market, a portion of which were ultimately supplied to
electric utilities. The majority of our electric utility customers purchase coal for terms of one to three years, but we also supply coal on a spot basis for some of our customers. Excluding the
results from the joint venture, for the year ended December 31, 2010, we derived approximately 82.5% of our total coal revenues from sales to our ten largest customers, with affiliates of our
top three customers accounting for approximately 43.0% of our coal revenues for that period: Indiana Harbor Coke Company, L.P., a subsidiary of Sunoco, Inc. (17.7%); GenOn
Energy, Inc. (fka Mirant Corporation) (12.9%); and American Electric Power Company, Inc. (12.4%). Additionally, pursuant to the terms of a coal purchase agreement entered into under the
joint venture agreement, we sell 100% of the joint venture's production to an affiliate of our joint venture partner, Patriot, which controls the amount and terms of sales of the coal produced from
the joint venture. Incidental to our coal mining process, we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to our
Sands Hill mining complex.

Coal Supply Contracts

For the years ended December 31, 2010 and 2009, approximately 96% and 99%, respectively, of our aggregate coal tons sold were
sold through supply contracts. We expect to continue selling a significant portion of our coal under supply contracts.

Quality
and volumes for the coal are stipulated in coal supply contracts, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply
contracts contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to
meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Some of our contracts specify approved locations from which coal
may be sourced. Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining
conditions, mine closures, or serious transportation problems that affect us or unanticipated plant outages that may affect the buyers.

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

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Transportation

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

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

Suppliers

Principal supplies used in our business include diesel fuel, explosives, maintenance and repair parts and services, roof control and
support items, tires, conveyance structures, ventilation supplies and lubricants. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and
construction.

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

Competition

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

The
most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and the reliability of supply. Demand for coal and the prices that
we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and international consumers. These coal consumption patterns are
influenced by factors beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government
regulation, technological developments and the location, availability, quality and price of competing sources of fuel such as natural gas, oil and nuclear, and alternative energy sources such as
hydroelectric power.

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Regulation and Laws

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



In
addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand
for our coal. The possibility exists that new laws or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a significant impact on our mining operations or
our customers' ability to use coal.

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

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

Mining Permits and Approvals

Numerous governmental permits or approvals are required for coal mining operations. When we apply for these permits and approvals, we
are often required to assess the effect or impact that any proposed production of coal may have upon the environment. The permit application requirements

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

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

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

Mine Health and Safety Laws

Stringent safety and health standards have been in effect since the adoption of the Coal Mine Health and Safety Act of 1969. The
Federal Mine Safety and Health Act of 1977 (the "Mine Act"), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards and imposed comprehensive
safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The
Mine Safety and Health
Administration ("MSHA") monitors compliance with these laws and regulations. In addition, the states where we operate also have state programs for mine safety and health regulation and enforcement.
Federal and state safety and health regulations affecting the coal industry are complex, rigorous and comprehensive, and have a significant effect on our operating costs.

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

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

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

Our
non-fatal days lost incidence rate was 39.3% below the industry average for the year ended December 31, 2010. Non-fatal days lost incidence rate is an
industry standard used to describe occupational injuries that result in loss of one or more days from an employee's scheduled work. Our non-fatal days lost time incidence rate for all
operations for the year ended December 31, 2010 was 1.53 as compared to the national average of 2.52 through the nine months ended September 30, 2010, as reported by MSHA.

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

In
2006, the Mine Improvement and New Emergency Response Act of 2006, or MINER Act, was enacted. The MINER Act significantly amended the Mine Act, requiring improvements in mine safety
practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities.
Since passage of the MINER Act, enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the
severity of enforcement actions and related penalties. Various states also have enacted their own new laws and regulations addressing many of these same subjects. MSHA continues to interpret and
implement various provisions of the MINER Act, along with introducing new proposed regulations and standards. Among these new proposed regulations is MSHA's proposed rule titled "Lowering Miner's
Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors." The rule, which is currently in the public hearing and comment phase, would require a 50% reduction in the
allowable respirable coal mine dust exposure limits and require each operation to significantly increase the number of respirable coal mine dust samples taken. The rule would also increase oversight
by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine. MSHA also introduced an Emergency Temporary Standard in 2010
that required the application and continued maintenance of a significantly increased amount of rock dust throughout underground coal mines.

Mining
accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have
resulted in

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increased
scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these
states and the federal government have included increased sanctions for non-compliance. Other states have proposed or passed similar bills, resolutions or regulations addressing mine
safety practices. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, are likely to result in more stringent enforcement and possibly the passage of new
laws and regulations.

Following
the April 5, 2010 Upper Big Branch mine incident, public scrutiny of large mining operations has increased among government officials as well as regulatory agencies. On
April 14, 2010, U.S.
Representative George Miller publicly released a list of mining operations which would have faced "pattern of violation" sanctions were it not for contested notices of violation. This list included
our Mine 28 in Pike County, Kentucky. After additional inspections on April 20, 2010, MSHA issued various citations related to Mine 28. Although we took steps to immediately abate certain of
these citations, we may incur various penalties or sanctions.

From
time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order to address a compliance requirement or because of an
accident. For instance, MSHA issues orders pursuant to Section 103(k) that, among other things, call for operations in the area of the mine at issue to suspend operations until compliance is
restored. Likewise, if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance leading to the accident has been resolved.
During the fiscal year ended December 31, 2010 (as in earlier years), we received such orders from government agencies and have experienced accidents within our mines requiring the suspension
or shutdown of operations in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances that caused such an accident were
being addressed, other areas of the mine could and did remain operational. These circumstances did not require us to suspend operations on a mine-wide level or otherwise entail material
financial or operational consequences for us. We cannot assure you that any suspension of operations at any one of our locations that may occur in the future will not have material financial or
operational consequences for us.

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

On
November 19, 2010, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and serves as manager, received an MSHA notification of a potential
pattern of violations under Section 104(e) of the Mine Act for Rhino Eastern's Eagle #1 Mine located in Bolt, West Virginia, based on MSHA's initial screening of compliance records for the
twelve months ended August 31, 2010 and of accident and employment records for the twelve months ended June 30, 2010. On December 7, 2010, we submitted a Corrective Action Plan to
MSHA and this plan became effective on December 31, 2010.

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

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

Implementing
and complying with these state and federal safety laws and regulations could adversely affect our results of operations and financial position. Some safety measures may
decrease our production rates or cause us not to pursue certain reserves due to safety concerns, adversely affecting our revenues. For instance, we incurred approximately $3.1 million for the
eighteen months ended June 30, 2010 in capital expenditures to comply with the requirements of the MINER Act. We project capital expenditures of approximately $2.8 million on compliance
with mine safety laws over the next five years. These figures are subject to change, however, as new requirements come into effect.

Black Lung Laws

Under federal black lung benefits laws, businesses that conduct current mining operations must make payments of black lung benefits to
coal miners with black lung disease and to some survivors of a miner who dies from this disease. To help fund these benefits, a tax is levied on production of $1.10 per ton for underground-mined coal
and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of
miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, some claims
for which coal operators had previously been responsible will be obligations of the government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from
January 1, 1996, to the earlier of January 1, 2014, or the
date on which the government trust becomes solvent. In 2010, we recorded approximately $3.5 million of expense related to this excise tax.

On
March 23, 2010, President Obama signed into law health care reform legislation, known as the Affordable Health Choices Act, which includes significant changes to the federal
black lung program. Among other things, these changes include provisions, retroactive to 2005, which would (1) provide an automatic survivor benefit paid upon the death of a miner with an
awarded black lung claim, without requiring proof that the death was due to pneumoconiosis and (2) establish a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more
years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program.

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

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Workers' Compensation

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

Surface Mining Control and Reclamation Act

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

SMCRA
and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires that
we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the
performance of these reclamation obligations. Mine operators can also be responsible for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to
certain structures occurring on the surface as a result of mine subsidence, a consequence of long-wall mining and possibly other mining operations. In addition, the Abandoned Mine Lands
Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed prior to SMCRA's adoption in 1977. The maximum tax is 31.5 cents
per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. As of December 31, 2010, we had accrued approximately $35.7 million for the estimated costs of reclamation
and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund
reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

After
the application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for a SMCRA
mine permit application to take over two years to prepare and review, depending on the size and complexity of the mine, and another two years or even longer for the permit to be issued. The
variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities' discretion in the handling of comments and
objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of judicial challenges related to the specific
permit or another related company's permit.

Federal
laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers
(i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by
SMCRA. This condition is often referred to as being "permit blocked" under the federal Applicant Violator Systems, or AVS. Thus, non-compliance with SMCRA can provide the bases to deny the
issuance of new mining permits

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or
modifications of existing mining permits, although we know of no basis by which we would be (and we are not now) permit-blocked.

In
addition, on November 30, 2009, the Office of Surface Mining Reclamation and Enforcement ("OSM") published an advanced notice of proposed rulemaking to revise the "stream
buffer zone rule," or SBZ Rule, that prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality. OSM intends to propose a series of Stream Protection
Rules in 2011 and will finalize those rules in 2012. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and
costs associated with obtaining permits, prohibitions or restrictions relating to mining activities near streams, and additional enforcement actions. In addition, Congress has proposed, and may in the
future propose, legislation to restrict the placement of mining material in streams. The requirements of the revised SBZ Rule or future legislation, when adopted, will likely be stricter than the
prior SBZ Rule to further protect streams from the impact of surface mining, and may adversely affect our business and operations.

Surety Bonds

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

As
of December 31, 2010, we had approximately $76.1 million in surety bonds outstanding to secure the performance of our reclamation obligations.

Air Emissions

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

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which
could have a material adverse effect on our business, financial condition and results of operations.

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

EPA
has promulgated rules, referred to as the "NOx SIP Call," that require coal-fired power plants in 21 eastern states and Washington D.C. to make substantial reductions in
nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. As a result of the
program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices. Installation of additional emission control
measures will make it more costly to operate coal-fired power plants, potentially making coal a less attractive fuel.

Additionally,
in March 2005, EPA issued the final Clean Air Interstate Rule, or CAIR, which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states
and Washington, D.C. CAIR required those states to achieve the required emission reductions by requiring power plants to either participate in an EPA-administered
"cap-and-trade" program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the
caps under CAIR may have required many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal
capability required by the rule could have resulted in decreased demand for lower sulfur coal, which may have potentially driven down prices for lower sulfur coal. On July 11, 2008, the United
States Court of Appeals for the D.C. Circuit vacated CAIR. The EPA subsequently filed a petition for rehearing or, in the alternative, for a remand of the case without vacatur. On December 23,
2008, the Court issued an opinion to remand without vacating CAIR. Therefore, CAIR will remain in effect while the EPA conducts rulemaking to modify CAIR to comply with the Court's July 2008 opinion.
The Court declined to impose a schedule by which the EPA must complete the rulemaking, but reminded the EPA that the Court does "...not intend to grant an indefinite stay of the effectiveness of this
Court's decision." The EPA is considering its options on how to proceed.

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

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

The
EPA has adopted new, more stringent national air quality standards, or NAAQS, for ozone and fine particulate matter. As a result, some states will be required to amend their existing
SIPs to attain and maintain compliance with the new air quality standards. For example, in December 2004, the EPA designated specific areas in the United States as in "non-attainment" with
the new NAAQS for fine particulate matter. In March 2007, the EPA published final rules addressing how states would implement plans to bring applicable non-attainment regions into
compliance with the new air quality standard. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our mining operations and customers
could be affected when the standards are implemented by the applicable states.

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

On
June 3, 2010, EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur
dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Attainment designations will be made pursuant to the modified standards by June 2012.
States with non-attainment areas will have until 2014 to submit SIP revisions which must meet the modified standard by August 1, 2017; for all other areas, states will be required
to submit "maintenance" SIPs by 2013. EPA also plans to address the secondary sulfur dioxide standard, which is currently under review. As a result, coal-fired power plants, which are the
largest end users of our coal, may be required to install additional emissions control equipment or take other steps to lower sulfur emissions.

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

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

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Carbon Dioxide Emissions

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

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

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



All
of these regulations are subject to legal challenges. Finally, in December 2010, the EPA issued its plan to update pollution standards for fossil fuel power plants and petroleum
refineries. The EPA has stated that it intends to propose standards for power plants in July 2011 and for refineries in December 2011 and will issue final standards in May 2012 and November 2012,
respectively. This new standard along with the current EPA's GHG regulations could adversely affect the demand for coal.

Many
states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of
greenhouse gases by certain facilities, including coal-fired electric generating facilities. For example, in December 2005,

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seven
northeastern states signed the Regional Greenhouse Gas Initiative agreement, or RGGI, calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power
plants in the participating states. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program
began in September 2008. Since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.

Following
the RGGI model, seven Western states and four Canadian provinces launched the Western Regional Climate Action Initiative to identify, evaluate and implement collective and
cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. Similarly in 2007, six Midwestern states and one Canadian province signed the Midwestern Greenhouse Gas
Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. The Final Model Rule, released in April 2010, calls for a 20% reduction below 2005 emissions levels by 2020 and
additional reductions to 80% below 2005 emissions levels by 2050, and implementation of a cap and trade program.

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

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

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

Clean Water Act

The Federal Clean Water Act, or the CWA, and similar state and local laws and regulations affect coal mining operations by imposing
restrictions on the discharge of pollutants, including dredged or fill material, into waters of the United States. The CWA establishes in-stream water quality and treatment standards for
wastewater discharges through Section 402 National Pollutant Discharge Elimination System, or NPDES, permits. Regular monitoring, as well as compliance with reporting requirements and
performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to
discharge dredged or fill materials into waters of the United States. Our surface coal mining and preparation plant operations typically require such permits to authorize activities such as the
creation of slurry ponds, stream impoundments, and valley fills. The EPA issues permits for the discharge of pollutants into navigable waters while the U.S. Army Corps of Engineers, or the Corps,
issues dredge and fill permits under Section 404 of the CWA. Although the CWA has long authorized EPA to review 404 permits issued by the Corps, EPA has only recently begun reviewing 404
permits issued by the Corps for coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to
various initiatives launched by EPA regarding these permits.

For
instance, even though the State of West Virginia has been delegated the authority to issue permits for coal mines in that state, the EPA is taking a more active role in its review of
NPDES permit applications for coal mining operations in Appalachia. EPA has stated that it plans to review all applications for NPDES permits. Indeed, interim final guidance issued by the EPA on
April 1, 2010,
encourages EPA Regions 3, 4 and 5 to (1) object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA,
and (2) exercise a greater degree of oversight with regard to state issued general Section 404 permits.

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

Not
only is EPA reviewing new permits before they are issued, EPA has recently exercised its "veto" power on January 14, 2011 to withdraw or restrict the use of previously issued
permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action is the first time
that such power was exercised with regard to a previously permitted coal mining project. More frequent use of the EPA's Section 404 "veto" power as well as the increased risk of application of
this power to previously permitted projects could create uncertainly with regard to our lessees' continued use of their current permits, as well as impose additional time and cost burdens on future
operations, potentially adversely affecting our coal royalties revenues.

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

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

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

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

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

Under
the CWA, states also must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state's

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antidegradation
regulations must prohibit the diminution of water quality in these streams absent an analysis of alternatives to the discharge and a demonstration of the socio-economic necessity for
the discharge. Several environmental groups and individuals have challenged West Virginia's antidegradation policy. In general, waters discharged from coal mines to high quality streams in West
Virginia will be required to meet or exceed new "high quality" standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits in
West Virginia, and could adversely affect our coal production. Several other environmental groups have also challenged the EPA's approval of Kentucky's antidegradation policy, including its
alternative antidegradation implementation methodology for permits associated with coal mining discharges, which recognizes that those discharges are subject to comparable regulation under SMCRA and
Section 404 of the CWA. The EPA has launched a rulemaking to revise its water quality standards regulations. The elimination of the alternative implementation methodology for coal mining
discharges or other provisions of Kentucky's antidegradation rules could mean that our operations in Kentucky would be required to comply with more complex and costly antidegradation procedures and
cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits in Kentucky, and thereby adversely affect our coal production.

Hazardous Substances and Wastes

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

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

On
June 21, 2010, EPA released a proposed rule to regulate the disposal of certain coal combustion by-products, or CCB. The proposed rule sets forth two proposed
avenues for the regulation of CCB under RCRA. The first option calls for regulation of CCB under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste
management and disposal. The second option utilizes Subtitle D, which gives EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen
suits. The proposal leaves intact the Bevill exemption for beneficial uses of CCB. If CCB is not classified as hazardous waste, it is not anticipated that regulation of CCB will have any material
effect on the amount of coal used by electricity generators. However, if CCB were re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide
specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers' operating costs and potentially reduce their
ability to purchase coal. In addition, contamination caused by the past disposal of CCB, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws
and potentially reduce the demand for coal.

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

National Environmental Policy Act

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

Endangered Species Act

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

Use of Explosives

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

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

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

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Other Environmental and Mine Safety Laws

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

Employees

To carry out our operations, our general partner and our subsidiaries employed 897 full-time employees as of
December 31, 2010. None of the employees are subject to collective bargaining agreements. We believe that we have good relations with these employees and since our inception we have had no
history of work stoppages or union organizing campaigns.

Available Information

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

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

Item 1A.    Risk Factors.

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

Risks Inherent in Our Business

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

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.445 per unit, or $1.78
per unit per year, which will require us to have available cash of approximately $11.3 million per quarter, or $45.0 million per year, based on the number of common and subordinated
units outstanding as of December 31, 2010 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the

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amount
of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:



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

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



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Any
adverse change in these factors could result in weaker demand and lower prices for our products. In addition, the recent global economic downturn, coupled with the global financial
and credit market disruptions, has had an impact on the coal industry generally and may continue to do so. The demand for electricity may remain at low levels or further decline if economic conditions
remain weak. If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years. Recent low prices for natural gas,
which is a substitute for coal generated power, may also lead to continued decreased coal consumption by electricity-generating utilities. A substantial or extended decline in the prices we receive
for our coal supply contracts could materially and adversely affect our results of operations.

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

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

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

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

The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including
laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of
materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining and the effects that mining has on groundwater quality
and availability. The costs, liabilities and requirements associated with these laws and regulations are significant and time-consuming and may delay

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commencement
or continuation of our operations. Moreover, the possibility exists that new laws or regulations (or new judicial interpretations or enforcement policies of existing laws and regulations)
could materially affect our mining operations, results of operations and cash available for distribution to our unitholders, either through direct impacts such as those regulating our existing mining
operations, or indirect impacts such as those that discourage or limit our customers' use of coal. Although we believe that we are in substantial compliance with existing laws and regulations, we may,
in the future, experience violations that would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. The enforcement of laws and regulations governing
the coal mining industry has increased substantially. As a result, the consequences for any noncompliance may become more significant in the future.

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

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

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

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



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Subsequent
to passage of the MINER Act, various coal producing states, including West Virginia, Ohio and Kentucky, have enacted legislation addressing issues such as mine safety and
accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Also, additional federal and state
legislation that further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has been considered in light of recent fatal mine
accidents. Further workplace accidents are likely to also result in more stringent enforcement and possibly the passage of new laws and regulations.

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

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

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

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

On
November 19, 2010, Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and serves as manager, received an MSHA notification of a potential
pattern of violations under Section 104(e) of the Mine Act for Rhino Eastern's Eagle #1 Mine located in Bolt, West Virginia, based on MSHA's initial screening of compliance records for the
twelve months ended August 31, 2010 and of accident and employment records for the twelve months ended June 30, 2010.

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

As
a result of these and future inspections and alleged violations and potential violations, we could be subject to material fines, penalties or sanctions. Mine 28, as well as any of our
other mines, could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our
business, results of operations and cash available for distribution.

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

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

Individual
or general permits under Section 404 of the CWA are required to discharge dredged or fill material into waters of the United States. Our surface coal mining operations
typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. The Corps is authorized to issue "nationwide" permits for specific
categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. We may no
longer seek general permits under NWP 21 because on June 17, 2010, the Corps suspended the use of NWP 21, but NWP 21 authorizations already granted remain in effect.

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

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

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

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

These
risks include:



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital
expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve
replacement costs or refurbishment or replacement of mine equipment. Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus is $18 to $22 million
for 2011. This amount is based on our current estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity, which we
believe to be reasonable. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. The amount of our estimated maintenance capital
expenditures may be more than our actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution
to unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once
a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates
will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please read "Risks Inherent in an Investment in
UsCost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount
and timing of such reimbursements will be determined by our general partner."

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

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides,
mercury and other compounds emitted into the air from electric power plants and other consumers of our coal. These laws and regulations can require significant emission control expenditures, and
various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content,
which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. Accordingly, these laws and regulations may affect
demand and prices for our higher sulfur coal. Please read "Part I, Item 1. BusinessRegulation and Laws."

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

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

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

The
permitting of new coal-fired power plants has also been contested by state regulators and environmental organizations for concerns related to greenhouse gas emissions
from the new plants. In addition, several permits issued to new coal-fired power plants without limits on greenhouse gas emissions have been appealed to EPA's Environmental Appeals Board.

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

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

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



We
maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety
bonds for mine reclamation. Due to current economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain
existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing
surety bond contracts. As of December 31, 2010, we had $76.1 million in reclamation surety bonds, secured by $29.7 million in letters of credit outstanding under our credit
agreement. Our credit agreement provides for a $200 million working capital revolving credit facility, of which up to $50.0 million may be used for letters of credit. If we do not
maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our

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mining
operations. For more information, please read "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and
Capital ResourcesCredit Agreement." If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash
available for distribution to our unitholders could be adversely affected.

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

We sell a material portion of our coal under supply contracts. As of December 31, 2010 we had sales commitments for
approximately 73% of our estimated coal production (including purchased coal to supplement our production and excluding results from the joint venture) for the year ending December 31, 2011.
When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of these committed tons, under the terms of the supply contracts, we will ship 51%
in 2011, 30% in 2012, and 19% in 2013. We derived approximately 82.5% of our total revenues from coal sales (excluding results from the joint venture) to our ten largest customers for the year ended
December 31, 2010, with affiliates of our top three customers accounting for approximately 43.0% of our coal revenues during that period.

In
the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms.
Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, and those customers may not continue to purchase coal
from us under long-term coal supply contracts or may significantly reduce their purchases of coal from us. In addition, interruption in the purchases by or operations of our principal
customers could significantly affect our results of operations and cash available for distribution. Unscheduled maintenance outages at our customers' power plants and unseasonably moderate weather are
examples
of conditions that might cause our customers to reduce their purchases. Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate
their purchases. The amount and terms of sales of coal produced from our Rhino Eastern mining complex are controlled by an affiliate of Patriot pursuant to the joint venture agreement. We cannot
guarantee that Patriot will be successful in obtaining coal supply contracts at favorable prices, if at all, which could have a material adverse effect on our results of operations and cash available
for distribution to our unitholders. For additional information relating to these contracts, please read "Part I, Item 1. BusinessCustomersCoal Supply
Contracts."

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

Excluding results from the joint venture, steam coal accounted for approximately 84% of our coal sales volume for the year ended
December 31, 2010. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal
consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of
competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A
decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, low natural gas prices have led, in some instances, to decreased coal
consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for
coal could decrease and the price of

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coal
could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing
financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal
consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to
our unitholders.

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

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

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

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

We at times use contractors to operate certain of our mines. For the year ended December 31, 2010, approximately 8% of our total
coal production was from contractor-operated mines. Disruption in our supply of coal produced by these contractors could temporarily impair our ability to fill our customers' orders or require us to
pay higher prices in order to obtain the required coal from other sources. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers and
other factors beyond our control could affect the availability, pricing and quality of coal produced by our contractors. Any increase in the prices we pay for contractor-produced coal could increase
our costs and therefore adversely affect our results of operations and cash available for distribution to our unitholders.

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

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

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mining
operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur
liability for such mining. Our sponsor, Wexford Capital, will not indemnify us for losses attributable to title defects in the properties that we own or lease.

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

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

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

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

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

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

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

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

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

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



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Increases
in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, 2010
our current portion of long-term debt that will be funded from cash flows from operating activities during 2011 was approximately $2.9 million. Our ability to service our
indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and
other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing
distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional
equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

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

The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our
ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our credit agreement restricts our ability to:



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:



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

Risks Inherent in an Investment in Us

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

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



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

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

In order to comply with U.S. laws with respect to the ownership of interests in mineral leases on federal lands, we have adopted
certain requirements regarding those investors who own our common units. As used in this report, an eligible citizen means a person or entity qualified to hold an interest in mineral leases on federal
lands. As of the date hereof, an eligible citizen must be: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or
(3) an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does
not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the
avoidance of doubt,

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onshore
mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the
United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an eligible citizen run the risk of having their units redeemed by us at the lower of
their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

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

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

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

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

In
addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the
extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be
unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our credit agreement on our ability to issue additional units, including units
ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may
impact the available cash that we have to distribute to our unitholders.

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

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



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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

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standards
set forth in subclauses (3) and (4) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by
or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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

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

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

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

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

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

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initial
target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have
otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.

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

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

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

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general
partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The
vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Currently, Wexford
owns an aggregate of approximately 84% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of
the subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the
common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment
finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the
business.

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

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

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

If at any time our general partner and its affiliates own more than 90% of the common units, our general partner will have the right,
but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater
of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and
(2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first
mailed. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding common units, the ownership threshold to exercise the limited call rights will be
reduced to 80%. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders
may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon
exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our
general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements
of the Securities Exchange Act of 1934, or the Exchange Act. Currently, Wexford owns an aggregate of approximately 84% of our common and subordinated units. At the end of the subordination period,
assuming no additional issuances of units (other than upon the conversion of the subordinated units and no transfer by Weford of its units), Wexford will own approximately 84% of our common units.

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

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



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

As of December 31, 2010, we had 12,406,760 common units and 12,397,000 subordinated units outstanding. All of the subordinated
units will convert into common units on a one-for-one basis at the end of the subordination period. All of the common units issued to Wexford in connection with our IPO are
subject to a 180-day lock-up agreement with the underwriters, the period of which may be extended under certain circumstances. Each of the lock-up agreements with
the underwriters may be waived in the discretion of certain of the underwriters. Sales by Wexford or other large holders of a

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substantial
number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our
ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to Wexford. Under our agreement, our general partner and its affiliates
have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

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

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

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

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

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

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions
requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public
common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units
held by Wexford) after the subordination period has ended. Currently, Wexford owns approximately 69% of the outstanding common units and 99% of our outstanding subordinated units.

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

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

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the
liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the
partnership are not counted for purposes of determining whether a distribution is permitted.

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

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

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

We cannot provide absolute assurance as to our ability to establish and maintain effective internal controls in accordance with applicable federal securities laws and
regulations, and we may incur significant costs in our efforts.

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

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

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

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

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

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

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

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

Tax Risks

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

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a
partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.

Despite
the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S.
federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business or a change in current law could cause us to be treated as a
corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If
we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of
35%, and would likely pay state and local income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or
credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a
corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common
units.

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

Current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subjecting us
to entity-level taxation. Specifically, the present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative,
legislative or judicial interpretation at any time. For example, at the federal level, legislation recently has been considered that would have eliminated partnership tax treatment for certain
publicly traded partnerships. Although such legislation would not have applied to

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us
as proposed, it could be reintroduced and amended prior to enactment in a manner that does apply to us. Any modification to the federal income tax laws and interpretations thereof may or may not be
applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our
common units.

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

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

Our
partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, the
minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any
other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or
court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the
market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs
will reduce our cash available for distribution.

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

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

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between
the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the
amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in
those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income
due to potential recapture items, including depletion and depreciation

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recapture.
In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash
you receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and
non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable
tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a
non-U.S. person, you should consult a tax advisor before investing in our common units.

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

Due to a number of factors, including our inability to match transferors and transferees of common units, we have adopted depreciation
and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits
available to you. It also could affect the
timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction, for U.S. federal income tax purposes, between transferors and transferees of our units each month based upon the
ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of
items of income, gain, loss and deduction among our unitholders.

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

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

Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of
the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss
from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and
any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain
recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from
borrowing their units.

We will adopt certain valuation methodologies, for U.S. federal income tax purposes, that may result in a shift of income, gain, loss and deduction between our general
partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and
allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our
assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our
valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser
portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets,
and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

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

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

We will be considered to have technically terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more
of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether a technical tax termination has occurred, a sale or exchange of 50% or more of the
total interests in our capital and profits could occur if, for example, Rhino Energy Holdings LLC, which currently owns approximately 84% of the total interests in our capital and profits,
sells or exchanges a majority of the interests it owns in us within a period of twelve months. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will
be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all
unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation
deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may
also result in more

51

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than
twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for
federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties
if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests
and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the
termination occurs.

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

Among the changes contained in President Obama's Budget Proposal, or the Budget Proposal, for Fiscal Year 2011 is the elimination of
certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would (1) eliminate current deductions and 60-month amortization
for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal
capital gains treatment of coal and lignite royalties, and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other
disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income
tax laws could eliminate certain tax deductions that are currently available with respect
to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

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

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes,
unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or control property now or in the future, even if they
do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various
jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in a number of states, most of which also impose an income tax on
corporations and other entities. In addition, many of these states also impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct
business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns.

Item 1B.    Unresolved Staff Comments

None.

Item 2.    Properties.

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

Coal Reserves and Non-Reserve Coal Deposits

We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and
analyzed by our staff. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances

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in
mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the
reserves, updated geologic models and mining recovery data, coal reserves recently acquired and estimated costs of production and sales prices. Changes in mining methods may increase or decrease the
recovery basis for a coal seam as will plant processing efficiency tests. We maintain reserve and non-reserve coal deposit information in secure computerized databases, as well as in hard
copy. The ability to update and/or modify the estimates of our coal reserves and non-reserve coal deposits is restricted to a few individuals and the modifications are documented.

Periodically,
we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent
engineering firm of our and the joint venture's coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc., as of
March 31, 2010, and covered all of the coal reserves and non-reserve coal deposits that we and the joint venture controlled as of such date. The coal reserve and
non-reserve coal deposit estimates for the Castle Valley mining complex in Utah were audited by Norwest Corporation in October 2010. While we intend to continue to periodically retain
outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward, our estimates as of December 31, 2010
were prepared by our staff of geologists and engineers.

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

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Coal Reserves

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

Proven and Probable Reserves(1)Region

Total(3)

Proven

Probable

Assigned

Unassigned

Owned

Leased

Steam(2)

Metallurgical(2)(in million tons)Central AppalachiaTug River Complex (KY, WV)


34.4


27.8


6.7


30.4


4.0


4.8


29.6


28.6


5.8Rob Fork Complex (KY)


25.4


21.8


3.6


25.4





8.3


17.1


19.2


6.2Deane Complex (KY)


40.5


23.9


16.6


8.0


32.5


40.0


0.5


40.5


Total Central Appalachia(3)


100.3


73.5


26.8


63.8


36.5


53.1


47.2


88.3


12.0Northern AppalachiaHopedale Complex (OH)


17.5


11.7


5.8


12.1


5.4


9.5


8.0


17.5


Sands Hill Complex (OH)


8.3


8.0


0.3


8.3





1.7


6.6


8.3


Leesville Field (OH)


26.8


7.8


19.0





26.8


26.8





26.8


Springdale Field (PA)


13.8


8.8


5.0





13.8


13.8





13.8


Total Northern Appalachia(3)


66.4


36.3


30.1


20.4


46.0


51.8


14.6


66.4


Illinois BasinTaylorville Field (IL)


109.5


38.8


70.7





109.5





109.5


109.5


Western BituminousCastle Valley Complex (UT)


26.7


15.7


11.0


26.7








26.7


26.7


McClane Canyon Mine (CO)


6.2


4.2


2.0


6.2





0.2


6.0


6.2


Total Western Bituminous(3)


32.9


19.9


13.0


32.9





0.2


32.7


32.9


Total(3)


309.0


168.4


140.6


117.0


192.0


105.1


203.9


297.0


12.0Percentage of total(3)





54.5
%

45.5
%

37.9
%

62.1
%

34.0
%

66.0
%

96.1
%

3.9
%Central AppalachiaRhino Eastern Complex (WV)(4)


22.2


13.5


8.7


22.2








22.2





22.2Percentage of total(3)





60.8
%

39.2
%

100
%







100
%




100
%


(1)Represents
recoverable tons.(2)For
purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality
and characteristics to be able to be used in the steel making process. All other coal reserves are defined as steam coal. However, some of the reserves in the metallurgical category can also be used
as steam coal.(3)Totals
and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.(4)Owned
by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the reserves.


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

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

As Received Basis(1)

Proven and Probable Coal Reserves(2)(3)Sulfur ContentRegion

% Ash

% Sulfur

Btu/lb.

S02/mm Btu

Total

<1%

1 - 1.5%

>1.5%

Unknown(in million tons)Central AppalachiaTug River Complex (KY, WV)


10.40
%

1.21
%

12,944


1.86


34.4


21.9


6.4


5.0


1.1Rob Fork Complex (KY)


6.17
%

1.15
%

13,371


1.72


25.4


15.6


5.9


2.3


1.6Deane Complex (KY)


5.37
%

0.91
%

13,446


1.36


40.5


21.0


11.7


1.0


6.8Total Central Appalachia(3)


7.42
%

1.08
%

13,241


1.64


100.3


58.5


23.9


8.3


9.5Northern AppalachiaHopedale Complex (OH)


6.72
%

2.33
%

12,989


3.59


17.5








17.5


Sands Hill Complex (OH)


9.14
%

2.49
%

10,552


4.73


8.3








8.3


Leesville Field (OH)


6.21
%

2.21
%

13,152


3.36


26.8








26.8


Springdale Field (PA)


6.63
%

1.72
%

13,443


2.55


13.8








13.8


Total Northern Appalachia(3)


6.77
%

2.17
%

12,873


3.37


66.4








66.4


Illinois BasinTaylorville Field (IL)


8.47
%

3.85
%

12,085


6.38


109.5








109.5


Western BituminousCastle Valley Complex (UT)


11.10
%

0.72
%

12,219


1.19


26.7


26.5


0.2





McClane Canyon Mine (CO)


11.62
%

0.59
%

11,675


1.01


6.2


6.2








Total Western Bituminous(3)


11.20
%

0.70
%

12,116


1.15


32.9


32.7


0.2





Total(3)


8.08
%

2.30
%

12,611


3.64


309.0


91.2


24.1


184.2


9.5Percentage of total(3)

















29.5
%

7.8
%

59.6
%

3.1
%Central AppalachiaRhino Eastern Complex (WV)(4)


4.54
%

0.64
%

14,000


0.92


22.2


22.2











(1)As
received represents an analysis of a sample as received at a laboratory.(2)Represents
recoverable tons.(3)Totals
and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.(4)Owned
by a joint venture in which we have a 51% membership interest and for which we serve as manager. Amounts shown include 100% of the reserves.


55

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Non-Reserve Coal Deposits

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

Non-Reserve Coal DepositsTotal TonsTotal TonsRegion

Owned

Leased(in million tons)Central Appalachia


29.2


11.7


17.5Northern Appalachia


39.2


28.2


11.0Illinois Basin


28.6





28.6Western Bituminous


174.8





174.8Total


271.8


39.9


231.9Percentage of total





14.7
%

85.3
%Rhino Eastern (Central Appalachia)(1)


34.3





34.3


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


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

Office Facilities

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

Item 3.    Legal Proceedings

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

Item 4.    (Removed and Reserved).

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PART II

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

Our Limited Partnership Interests

Our common units began trading on the NYSE under the symbol "RNO" on September 30, 2010. On March 14, 2011, the closing
market price for our common units was $24.75 per unit. The following table sets forth the range of the daily high and low sales prices and cash distribution per common unit for the periods indicated:

Price Range(1)Cash
Distribution(2)High

LowYear ended December 31, 2010Fourth Quarter

$
24.86

$
21.10





(1)The
range of the daily high and low sales prices is for the period September 30, 2010 through December 31, 2010.(2)The
distribution of $0.4208 per common unit corresponds to the minimum quarterly distribution of $0.445 per unit prorated for the portion of the quarter
after October 5, 2010, the closing date of our IPO. An accrual was not made for this distribution as of December 31, 2010 because the distribution was announced on January 24,
2011 and was paid on February 14, 2011 to all unitholders of record as of the close of business on February 1, 2011.


As
of March 14, 2011, we had outstanding 12,406,760 common units, 12,397,000 subordinated units, a 2% general partner interest and incentive distribution rights, or IDRs. As of
March 14, 2011, Rhino Energy Holdings LLC owned approximately 68.9% of our outstanding common units and 98.6% of our subordinated units. Our general partner currently owns a 2.0% general
partner interest in us and all of our IDRs.

As
of March 14, 2011, there were 10 holders of record of our common units. The number of record holders does not include holders of shares in "street names" or persons,
partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Cash Distribution Policy

We will make a minimum quarterly distribution of $0.445 per common unit (or $1.78 per common unit on an annualized basis) to the extent
we have sufficient available cash. Available cash is generally defined as cash from operations after establishment by our general partner of cash reserves to provide for the conduct of our business,
to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to unitholders for any one or more of the next four quarters, and payment of costs
and expenses, including reimbursement of expenses to our general partner and its affiliates. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform
services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner
may establish or the amount of expenses for which our general partner and its affiliates may be reimbursed. Available cash may also include, if our general partner so determines, all or any portion of
the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. We

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

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



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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:

Marginal Percentage
Interest in DistributionsTotal Quarterly Distribution Target Amount

Unitholders

General PartnerAbove $0.51175 up to $0.55625


85.0
%

15.0
%Above $0.55625 up to $0.6675


75.0
%

25.0
%Above $0.6675


50.0
%

50.0
%


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

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

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

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

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

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



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

We
used the net proceeds from the IPO, and a related capital contribution by our general partner of approximately $10.4 million, to repay approximately $69.4 million of
outstanding indebtedness under our credit facility and to reimburse affiliates of our sponsor, Wexford Capital, for approximately $9.3 million of capital expenditures incurred with respect to
the assets contributed to us in connection with the IPO. Affiliates of Raymond James & Associates, Inc. and RBC Capital Markets are lenders under our credit facility and received their
pro rata portion of the net proceeds from the IPO and the related capital contribution by our general partner through the repayment of borrowings they had extended under the credit agreement.

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Item 6.    Selected Financial Data.

The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived
from our consolidated financial statements. On October 5, 2010, we closed our IPO of 3,730,600 common units. In conjunction with the IPO, on September 29, 2010 Wexford became obligated
to contribute their membership interests in Rhino Energy LLC to us. For ease of reference, we present the historical results of Rhino Energy LLC as our historical results which also
includes the portion of fiscal year 2010 results prior to the IPO that contributed to the total 2010 figures presented below as a total for us. The selected historical consolidated financial data
presented as of March 31, 2006 and December 31, 2006, 2007 and 2008 and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended
December 31, 2007 are derived from the audited historical consolidated financial statements of Rhino Energy LLC that are not included in this report. The selected historical consolidated
financial data presented as of December 31, 2009 and 2010 and for the years ended December 31, 2008, 2009 and 2010 are derived from the audited historical consolidated financial
statements of Rhino Energy LLC that are included elsewhere in this report. Effective April 1, 2006, Rhino Energy LLC changed its fiscal year end from March 31 to
December 31.

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

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

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

For the Year Ended December 31,

Nine Months
Ended
December 31,
2006

Year
Ended
March 31,
2006(in thousands, except per unit and per ton data)

2010

2009

2008

2007Statement of Operations Data:Total revenues

$
305,647

$
419,790

$
438,924

$
403,452

$
300,839

$
363,960Costs and Expenses:Cost of operations (exclusive of depreciation, depletion and amortization)


220,756


336,335


364,912


318,405


241,185


291,208Freight and handling costs


2,634


3,991


10,223


4,021


2,768


6,343Depreciation, depletion and amortization


34,108


36,279


36,428


30,750


28,471


13,744Selling, general and administrative (exclusive of depreciation, depletion and amortization)


16,449


16,754


19,042


15,370


18,573


17,129Asset impairment loss


652














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


(10,716
)

1,710


451


(944
)

746


(377
)Total costs and expenses


263,883


395,069


431,056


367,602


291,743


328,047Income from operations


41,764


24,721


7,868


35,850


9,096


35,913Interest and other income (expense):Interest expense


(5,338
)

(6,222
)

(5,500
)

(5,579
)

(6,498
)

(4,976
)Interest income


24


70


148


317


312


412Equity in net income (loss) of unconsolidated affiliate


4,699


893


(1,587
)







Othernet














272


491Total interest and other expense


(615
)

(5,259
)

(6,939
)

(5,262
)

(5,914
)

(4,073
)Income before income tax expense


41,149


19,462


929


30,588


3,182


31,840Income tax expense (benefit)











(126
)

125


178Net income

$
41,149

$
19,462

$
929

$
30,714

$
3,057

$
31,661Basic and diluted net income per limited partner common unit

$
0.22Weighted average number of limited partner common units outstanding:Basic


12,400Diluted


12,413Balance Sheet Data:Cash and cash equivalents

$
76

$
687

$
1,937

$
3,583

$
380

$
1,489Property and equipment, net


282,577


270,680


282,863


211,657


197,056


180,267Total assets


358,645


339,984


352,536


275,992


248,195


246,759Total liabilities


111,028


201,583


234,225


158,152


153,307


154,028Total debtshort term and long term


36,528


122,138


138,027


83,954


88,571


87,764Partners' capital/Members' equity

$
247,617

$
138,401

$
118,311

$
117,841

$
94,887

$
92,731Other Operating Data(1):Tons of coal sold


4,306


6,699


7,977


8,159


6,223


7,900Tons of coal produced/purchased


4,312


6,732


8,017


8,024


6,182


7,950Coal revenues per ton(2)

$
67.32

$
59.98

$
51.25

$
48.30

$
47.31

$
44.48Cost of operations per ton(3)

$
51.27

$
50.21

$
45.75

$
39.02

$
38.28

$
36.89Other Financial Data:Net cash provided by operating activities

$
55,001

$
41,495

$
57,211

$
52,493

$
36,860

$
32,892Net cash used in investing activities


(37,644
)

(27,344
)

(106,638
)

(28,098
)

(28,828
)

(34,613
)Net cash (used in) provided by financing activities


(17,968
)

(15,401
)

47,781


(21,192
)

(9,141
)

(1,887
)EBITDA


80,595


61,964


42,858


66,917


38,151


50,560Capital expenditures(4)

$
41,250

$
29,657

$
92,741

$
32,773

$
42,393

$
66,373


(1)In
May 2008, we entered into a joint venture with an affiliate of Patriot that acquired the Rhino Eastern mining complex, which commenced production in
August 2008. We have a 51% membership interest in, and serve as manager for, the joint venture. The operating data do not include data with respect to the Rhino Eastern mining complex. The joint
venture produced and sold approximately 0.3 million tons and approximately 0.2 million tons of premium mid-vol metallurgical coal for the years ended December 31, 2010
and 2009, respectively.(2)Coal
revenues per ton represent total coal revenues derived from the sale of coal from all business segments, divided by total tons of coal sold for all
segments.


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(3)Cost
of operations per ton represents the cost of operations (exclusive of depreciation, depletion and amortization) from all business segments divided by
total tons of coal sold for all segments.(4)The
following table presents a reconciliation of total capital expenditures to net cash used for capital expenditures on a historical basis for each of the
periods indicated:


For the Year Ended December 31,

Nine Months
Ended
December 31,
2006Year Ended
March 31,
20062010

2009

2008

2007(in thousands)Reconciliation of total capital expenditures to net cash used for capital expenditures:Additions to property, plant and equipment

$
26,248

$
27,836

$
78,076

$
14,599

$
32,701

$
31,485Acquisitions of coal companies and coal properties


15,002





14,665


18,174





5,000Acquisition of roof bolt manufacturing company





1,821











Plus:

$
41,250

$
29,657

$
92,741

$
32,773

$
32,701

$
36,485Additions to property, plant and equipment financed through long-term borrowings














9,692


29,888Total capital expenditures


41,250

$
29,657

$
92,741

$
32,773

$
42,393

$
66,373




Non-GAAP Financial Measure

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



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

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

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

For the Year Ended December 31,

Nine Months
Ended
December 31,
2006Year Ended
March 31,
2006(in thousands)

2010

2009

2008

2007Reconciliation of EBITDA to net income:Net income

$
41,149

$
19,462

$
929

$
30,714

$
3,057

$
31,661Plus:Depreciation, depletion and amortization


34,108


36,279


36,428


30,750


28,471


13,744Interest expense


5,338


6,222


5,501


5,579


6,498


4,976Income tax expense














125


178Less:Income tax benefit











126





EBITDA(a)

$
80,595

$
61,964

$
42,858

$
66,917

$
38,151

$
50,560Reconciliation of EBITDA to net cash provided by (used in) operating activities:Net cash provided by (used in) operating activities

$
55,001

$
41,495

$
57,211

$
52,493

$
36,860

$
32,892Plus:Increase in net operating assets


10,260


17,190





10,553


893


16,447Decrease in provision for doubtful accounts











175


283


Gain on sale of assets











944





377Gain on acquisition


10,789














Gain on retirement of advance royalties











115





237Interest expense


5,338


6,222


5,501


5,579


6,498


4,976Income tax expense














125


178Settlement of litigation





1,773











Equity in net income of unconsolidated affiliate


4,699


893











Less:Decrease in net operating assets








10,440








Accretion on interest-free debt


206


200


569


360


255


321Amortization of advance royalties


865


215


471


700


1,099


2,187Amortization of debt issuance costs


844














Increase in provision for doubtful accounts





19











354Equity-based compensation


291














Loss on sale of assets


73


1,710


451





746


Loss on asset impairments


652














Loss on retirement of advance royalties


396


712


45





2,995


Income tax benefit











126





Accretion on asset retirement obligations


2,165


2,753


2,709


1,757


1,412


1,686Equity in net loss of unconsolidated affiliate








1,587








Payment of abandoned public offering expenses(b)








3,582








EBITDA(a)

$
80,595

$
61,964

$
42,858

$
66,917

$
38,151

$
50,560


(a)Totals
may not foot due to rounding.(b)In
2008, we attempted an initial public offering, which was not consummated. We recorded the related deferred costs as an SG&A expense in August of that
year.


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Table of Contents

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

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

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

Overview

We are a growth-oriented Delaware limited partnership formed to control and operate coal properties and related assets. We produce,
process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam-powered generators. Customers for
our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process.

We
have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of
December 31, 2010, we controlled an estimated 309.0 million tons of proven and probable coal reserves, consisting of an estimated 297.0 million tons of steam coal and an estimated
12.0 million tons of metallurgical coal. In addition, as of December 31, 2010, we controlled an estimated 271.8 million tons of non-reserve coal deposits. As of
December 31, 2010, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 22.2 million tons of
proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and
an estimated 34.3 million tons of non-reserve coal deposits. Our and the joint venture's proven and probable coal reserves and non-reserve coal deposits were the same in
all material respects as of December 31, 2009. As of December 31, 2010, we operated ten mines, including five underground and five surface mines, located in Kentucky, Ohio and West
Virginia. In addition, our joint venture operates one underground mine in West Virginia. During 2010, we operated one underground mine in Colorado, but we temporarily idled this mine at year end due
to the expiration of our sole customer contract at this location. We are currently planning to restart production at this location in late 2011. Additionally, we began production and customer
shipments in January 2011 at one underground mine located in Emery and Carbon Counties in Utah that we acquired out of bankruptcy in August of 2010. The number of mines that we operate may vary from
time to time depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

Our
principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our diverse asset base in order to maintain, and, over
time, increase our quarterly cash distributions. In addition, we intend to expand our operations through strategic acquisitions, including the acquisition of stable, cash generating
non-coal natural resource assets. We believe that such assets would allow us to grow our cash available for distribution and enhance stability of our cash flow by, for example, serving as
a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel, steel products and other commodities consumed in the mining process.

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Table of Contents

For
the year ended December 31, 2010, we generated revenues of approximately $305.6 million and net income of approximately $41.1 million. Excluding results from the
joint venture, for the year ended December 31, 2010, we produced approximately 4.0 million tons of coal, purchased approximately 0.3 million tons of coal and sold approximately
4.3 million tons of coal, approximately 96% of which were pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.3 million tons of premium
mid-vol metallurgical coal for the year ended December 31, 2010.

Recent Developments



On October 5, 2010, we completed our IPO, in which we sold an aggregate of 3,730,600 common units to the public at a price of
$20.50 per common unit. Net proceeds from the offering were approximately $67.6 million, after deducting underwriting discounts and estimated offering expenses of $8.9 million. We used
the net proceeds from this offering, and a related capital contribution by our general partner of approximately $10.4 million, to repay approximately $69.4 million of outstanding
indebtedness under our credit facility and to reimburse Wexford for capital expenditures incurred with respect to the assets contributed to us in connection with the offering.

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



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



In August 2010, we acquired certain mining assets of C.W. Mining Company out of bankruptcy (the "Castle Valley Acquisition") for cash
consideration of approximately $15.0 million. The assets acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground
mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We began production from these assets at one underground mine in early 2011 and expect
the type of coal produced will be steam coal. As of a result of this acquisition being completed under a distressed bankruptcy sale, we recognized a $10.8 million gain during 2010 in accordance
with accounting principles generally accepted in the United States of America, which positively impacted our 2010 net income.

Factors That Impact Our Business

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

On
a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation, (2) the availability and
prices of competing

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electricity-generation
fuels, (3) our ability to secure or acquire high-quality coal reserves and (4) our ability to find buyers for coal under favorable supply contracts.

We
have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of December 31, 2010, we had commitments under supply
contracts to deliver annually scheduled base quantities of 3.7 million, 2.2 million and 1.4 million tons of coal to 16 customers in 2011, 5 customers in 2012, and 3 customers in
2013, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

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

Results of Operations



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



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

EBITDA.The discussion of our results of operations below includes references to, and analysis of, our segments' EBITDA results.
EBITDA represents
net income before deducting interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used by management primarily as a measure of our segments' operating performance.
EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in
accordance with GAAP. Because not all

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companies
calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read "Reconciliation of EBITDA to Net Income by
Segment" for reconciliations of EBITDA to net income for each of the periods indicated.

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

Cost of Operations Per Ton.Cost of operations per ton sold represents the cost of operations (exclusive of depreciation,
depletion and amortization)
divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency of operations.

Summary

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and
operational data for years ended December 31, 2010, 2009 and 2008:

Year Ended December 31,2010

2009

2008(in millions)Statement of Operations Data:Total revenues

$
305.6

$
419.8

$
438.9Costs and expenses:Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)


220.8


336.3


364.9Freight and handling costs


2.6


4.0


10.2Depreciation, depletion and amortization


34.1


36.3


36.4Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)


16.4


16.8


19.0Asset impairment loss


0.7





(Gain) loss on sale/acquisition of assets


(10.7
)

1.7


0.5Income from operations


41.7


24.7


7.9Interest and other income (expense):Interest expense


(5.3
)

(6.2
)

(5.5
)Interest income





0.1


0.1Equity in net income (loss) of unconsolidated affiliate


4.7


0.9


(1.6
)Total interest and other income (expense)


(0.6
)

(5.2
)

(7.0
)Income tax benefit








Net income

$
41.1

$
19.5

$
0.9Other Financial DataEBITDA

$
80.6

$
62.0

$
42.9




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

For
the year ended December 31, 2010, our total revenues decreased to $305.6 million from $419.8 million for the year ended December 31, 2009. We sold
4.3 million tons of coal for the year

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

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

Despite
the decrease in the volume of tons sold, both net income and EBITDA increased for the year ended December 31, 2010 from the year ended December 31, 2009. Net income
increased to $41.1 million for year ended December 31, 2010 from $19.5 million for the year ended December 31, 2009. EBITDA increased to $80.6 million for the year
ended December 31, 2010, from $62.0 million for the year ended December 31, 2009. The increases in net income and EBITDA were primarily due to increased revenue on a per ton basis
and a reduction in the amount of coal purchased offset by higher costs of operations in our Central Appalachia segment. Net income and EBITDA in 2010 also benefited by a $10.8 million gain
recognized on the Castle Valley Acquisition discussed earlier.

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

Segment

Year Ended
December 31, 2010

Year Ended
December 31, 2009

Increase
(Decrease)
Tons

%*(in millions, except %)Central Appalachia


2.2


4.2


(2.0
)

(49.5
)%Northern Appalachia


1.9


2.2


(0.3
)

(10.0
)%Rhino Western


0.2


0.3


(0.1
)

(23.6
)%Total*


4.3


6.7


(2.4
)

(35.7
)%


*Calculated
percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts presented in this table.Excludes
tons sold by the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.


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

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

Increase/(Decrease)Year ended
December 31, 2010

Year ended
December 31, 2009Segment

$

%*(in millions, except per ton data and %)Central AppalachiaCoal revenues

$
194.9

$
295.1

$
(100.2
)

(34.0
)%Freight and handling revenues











n/aOther revenues


0.7


2.6


(1.9
)

(72.0
)%Total revenues

$
195.6

$
297.7

$
(102.1
)

(34.3
)%Coal revenues per ton*

$
90.30

$
69.10

$
21.20


30.7
%Northern AppalachiaCoal revenues

$
86.2

$
95.5

$
(9.3
)

(9.7
)%Freight and handling revenues


4.2


5.0


(0.8
)

(17.4
)%Other revenues


5.0


6.2


(1.2
)

(19.1
)%Total revenues

$
95.4

$
106.7

$
(11.3
)

(10.6
)%Coal revenues per ton*

$
44.30

$
44.12

$
0.18


0.4
%Rhino WesternCoal revenues

$
8.8

$
11.2

$
(2.4
)

(21.2
)%Freight and handling revenues











n/aOther revenues











12.3
%Total revenues

$
8.8

$
11.2

$
(2.4
)

(21.1
)%Coal revenues per ton*

$
43.67

$
42.35

$
1.32


3.1
%OtherCoal revenues


n/a


n/a


n/a


n/aFreight and handling revenues


n/a


n/a


n/a


n/aOther revenues

$
5.8

$
4.2

$
1.6


40.7
%Total revenues

$
5.8

$
4.2

$
1.6


40.7
%Coal revenues per ton*


n/a


n/a


n/a


n/aTotalCoal revenues

$
289.9

$
401.8

$
(111.9
)

(27.8
)%Freight and handling revenues


4.2


5.0


(0.8
)

(17.4
)%Other revenues


11.5


13.0


(1.5
)

(10.8
)%Total revenues

$
305.6

$
419.8

$
(114.2
)

(27.2
)%Coal revenues per ton*

$
67.32

$
59.98

$
7.34


12.2
%


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


Our
total revenues for the year ended December 31, 2010 decreased by $114.2 million, or 27.2%, to $305.6 million from $419.8 million for the year ended
December 31, 2009. The decrease in total revenues was due to the strategic decision to sell only tons that provided an acceptable margin as discussed earlier. Coal revenues per ton were $67.32
for the year ended December 31, 2010, an increase of $7.34, or 12.2%, from $59.98 per ton for the year ended December 31, 2009. This increase in coal revenues per ton was primarily the
result of the sale of a higher percentage of metallurgical coal being sold and higher contracted prices for the steam coal.

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

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

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

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

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Costs and Expenses.The following table presents costs and expenses (including the cost of purchased coal) and cost of
operations per ton by
reportable segment for the years ended December 31, 2010 and 2009:

Increase/(Decrease)Year ended
December 31, 2010

Year ended
December 31, 2009Segment

$

%*(in millions, except per ton data and %)Central AppalachiaCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
133.5

$
249.1

$
(115.6
)

(46.4
)%Freight and handling costs











n/aDepreciation, depletion and amortization


20.1


23.9


(3.8
)

(15.9
)%Selling, general and administrative


15.3


15.5


(0.2
)

(1.0
)%Cost of operations per ton*

$
61.87

$
58.32

$
3.55


6.1
%Northern AppalachiaCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
65.1

$
71.5

$
(6.4
)

(9.0
)%Freight and handling costs


3.1


4.0


(0.9
)

(22.0
)%Depreciation, depletion and amortization


9.3


7.9


1.5


18.9
%Selling, general and administrative


0.3


0.4


(0.1
)

(10.9
)%Cost of operations per ton*

$
33.43

$
33.04

$
0.39


1.2
%Rhino WesternCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
6.9

$
6.2

$
0.7


10.9
%Freight and handling costs











n/aDepreciation, depletion and amortization


0.6


0.7


(0.1
)

(18.1
)%Selling, general and administrative


0.1


0.1





20.9
%Cost of operations per ton*

$
34.20

$
23.56

$
10.63


45.1
%OtherCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
15.3

$
9.5

$
5.8


60.1
%Freight and handling costs


(0.5
)




(0.5
)

n/aDepreciation, depletion and amortization


4.1


3.8


0.3


7.0
%Selling, general and administrative


0.7


0.8


(0.1
)

(15.0
)%Cost of operations per ton**


n/a


n/a


n/a


n/aTotalCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
220.8

$
336.3

$
(115.5
)

(34.4
)%Freight and handling costs


2.6


4.0


(1.4
)

(34.0
)%Depreciation, depletion and amortization


34.1


36.3


(2.2
)

(6.0
)%Selling, general and administrative


16.4


16.8


(0.4
)

(1.8
)%Cost of operations per ton*

$
51.27

$
50.21

$
1.06


2.1
%


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


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


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

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

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

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

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

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

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

For
the year ended December 31, 2010, our depreciation cost was $26.8 million as compared to $29.3 million for the year ended December 31, 2009. The decrease
in depreciation cost in 2010 was primarily due to the disposal and idling of assets at certain less profitable surface mining operations.

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

For
the year ended December 31, 2010, our amortization cost was $5.5 million as compared to $4.7 million for the year ended December 31, 2009. This increase
is primarily attributable to the acceleration of amortization for both mine development costs and asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative.Selling, general and administrative, or SG&A, expense for the year ended December 31, 2010
was
$16.4 million as compared to $16.8 million for the year ended December 31, 2009. This decrease in SG&A expense was primarily due to a gain recognized on a litigation settlement,
partially offset by an increase in expenditures for legal fees associated with the Castle Valley acquisition and other professional fees.

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

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

Segment

Year ended
December 31, 2010

Year ended
December 31, 2009

Increase
(Decrease)(in millions)Central Appalachia

$
20.6

$
0.6

$
20.0Northern Appalachia


10.1


17.6


(7.5
)Eastern Met*


4.7


0.9


3.8Rhino Western


11.2


3.3


7.9Other


(5.5
)

(2.9
)

(2.6
)Total

$
41.1

$
19.5

$
21.6


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


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

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

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

Segment

Year ended
December 31, 2010

Year ended
December 31, 2009

Increase
(Decrease)(in millions)Central Appalachia

$
43.0

$
28.0

$
15.0Northern Appalachia


21.4


27.3


(5.9
)Eastern Met*


4.7


0.9


3.8Rhino Western


12.0


4.2


7.8Other


(0.5
)

1.6


(2.1
)Total

$
80.6

$
62.0

$
18.6


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


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



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

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

Segment

Year Ended
December 31, 2009

Year Ended
December 31, 2008

Increase
(Decrease)
Tons

%*(in millions, except %)Central Appalachia


4.2


5.5


(1.3
)

(22.0
)%Northern Appalachia


2.2


2.2





(2.7
)%Rhino Western


0.3


0.3





(5.3
)%Total*


6.7


8.0


(1.3
)

(16.0
)%


*Percentages
are calculated based on actual amounts and not the rounded amounts presented in this table.Excludes
tons sold by the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.


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

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

Increase/
(Decrease)Year ended
December 31, 2009

Year ended
December 31, 2008Segment

$

%*(in millions, except per ton data and %)Central AppalachiaCoal revenues

$
295.1

$
310.6

$
(15.5
)

(5.0
)%Freight and handling revenues





0.8


(0.8
)

(100.0
)%Other revenues


2.6


5.1


(2.5
)

(49.1
)%Total revenues

$
297.7

$
316.5

$
(18.8
)

(5.9
)%Coal revenues per ton*

$
69.10

$
56.74

$
12.36


21.8
%Northern AppalachiaCoal revenues

$
95.5

$
89.9

$
5.6


6.1
%Freight and handling revenues


5.0


7.1


(2.1
)

(29.3
)%Other revenues


6.2


11.4


(5.2
)

(45.0
)%Total revenues

$
106.7

$
108.4

$
(1.7
)

(1.6
)%Coal revenues per ton*

$
44.12

$
40.44

$
3.68


9.1
%Rhino WesternCoal revenues

$
11.2

$
8.3

$
2.9


34.9
%Freight and handling revenues





2.3


(2.3
)

(100.0
)%Other revenues











(11.0
)%Total revenues

$
11.2

$
10.6

$
0.6


5.5
%Coal revenues per ton*

$
42.35

$
29.74

$
12.61


42.4
%OtherCoal revenues

$


$


$



n/aFreight and handling revenues











n/aOther revenues


4.2


3.4


0.8


21.0
%Total revenues

$
4.2

$
3.4

$
0.8


21.0
%Coal revenues per ton*


n/a


n/a


n/a


n/aTotalCoal revenues

$
401.8

$
408.8

$
(7.0
)

(1.7
)%Freight and handling revenues


5.0


10.2


(5.2
)

(50.5
)%Other revenues


13.0


19.9


(6.9
)

(34.8
)%Total revenues

$
419.8

$
438.9

$
(19.1
)

(4.4
)%Coal revenues per ton*

$
59.98

$
51.25

$
8.73


17.0
%


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


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

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

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

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

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

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

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Costs and Expenses.The following table presents costs and expenses (including the cost of purchased coal) and cost of operations
per ton by
reportable segment for the years ended December 31, 2009 and 2008:

Increase/
(Decrease)Year ended
December 31, 2009

Year ended
December 31, 2008Segment

$

%*(in millions, except per ton data and %)Central AppalachiaCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
249.1

$
272.8

$
(23.7
)

(8.7
)%Freight and handling costs





0.7


(0.7
)

(100.0
)%Depreciation, depletion and amortization


23.9


24.9


(1.0
)

(4.1
)%Selling, general and administrative


15.5


14.4


1.1


7.6
%Cost of operations per ton*

$
58.32

$
49.84

$
8.48


17.0
%Northern AppalachiaCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
71.5

$
76.6

$
(5.1
)

(6.7
)%Freight and handling costs


4.0


7.2


(3.2
)

(44.7
)%Depreciation, depletion and amortization


7.8


8.1


(0.3
)

(2.8
)%Selling, general and administrative


0.4


0.4





10.9
%Cost of operations per ton*

$
33.04

$
34.45

$
(1.40
)

(4.1
)%Rhino WesternCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
6.2

$
6.1

$
0.1


2.6
%Freight and handling costs





2.3


(2.3
)

(100.0
)%Depreciation, depletion and amortization


0.7


0.7





(2.3
)%Selling, general and administrative


0.1


0.1





19.5
%Cost of operations per ton*

$
23.56

$
21.76

$
1.80


8.3
%OtherCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
9.5

$
9.4

$
0.1


1.4
%Freight and handling costs











n/aDepreciation, depletion and amortization


3.9


2.7


1.1


41.5
%Selling, general and administrative


0.8


4.2


(3.4
)

(81.0
)%Cost of operations per ton**


n/a


n/a


n/a


n/aTotalCost of operations (exclusive of depreciation, depletion and amortization shown separately below)

$
336.3

$
364.9

$
(28.6
)

(7.8
)%Freight and handling costs


4.0


10.2


(6.2
)

(61.0
)%Depreciation, depletion and amortization


36.3


36.4


(0.2
)

(0.4
)%Selling, general and administrative


16.8


19.1


(2.3
)

(12.0
)%Cost of operations per ton*

$
50.21

$
45.75

$
4.46


9.8
%


*Percentages
and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.**Cost
of operations presented for our Other category includes costs of our ancillary businesses. The activities performed by these ancillary businesses do not
directly relate to coal production. As a result, per ton measurements are not presented for this category.


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

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

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

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

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

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

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

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

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

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

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

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

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

Segment

Year ended
December 31, 2009

Year ended
December 31, 2008

Increase
(Decrease)(in millions)Central Appalachia

$
0.6

$
(3.5
)
$
4.1Northern Appalachia


17.6


10.9


6.7Eastern Met*


0.9


(1.6
)

2.5Rhino Western


3.3


0.7


2.6Other


(2.9
)

(5.6
)

2.7Total

$
19.5

$
0.9

$
18.6


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


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

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

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

Segment

Year ended
December 31, 2009

Year ended
December 31, 2008

Increase
(Decrease)(in millions)Central Appalachia

$
28.0

$
24.9

$
3.1Northern Appalachia


27.3


20.4


6.9Eastern Met*


0.9


(1.6
)

2.5Rhino Western


4.2


1.7


2.5Other


1.6


(2.5
)

4.1Total

$
62.0

$
42.9

$
19.1


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


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



EBITDA represents net income before interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used by
management primarily as a measure of each of our segments' operating performance. Because not all companies calculate EBITDA identically, our calculation may not be comparable to similarly titled
measures of other companies. EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or
liquidity presented in accordance with GAAP. The following tables present reconciliations of EBITDA to net income for each of the periods indicated.

Year ended December 31, 2010

Central
Appalachia

Northern
Appalachia

Eastern
Met*

Rhino
Western

Other

Total**(in millions)Net income

$
20.6

$
10.1

$
4.7

$
11.2

$
(5.5
)
$
41.1Plus:Depreciation, depletion and amortization


20.1


9.3





0.6


4.1


34.1Interest expense


2.3


2.0





0.2


0.9


5.3EBITDA**

$
43.0

$
21.4

$
4.7

$
12.0

$
(0.5
)
$
80.6


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Year ended December 31, 2009

Central
Appalachia

Northern
Appalachia

Eastern
Met*

Rhino
Western

Other

Total**(in millions)Net income

$
0.6

$
17.6

$
0.9

$
3.3

$
(2.9
)
$
19.5Plus:Depreciation, depletion and amortization


23.9


7.9





0.7


3.8


36.3Interest expense


3.5


1.8





0.2


0.7


6.2EBITDA**

$
28.0

$
27.3

$
0.9

$
4.2

$
1.6

$
62.0




Year ended December 31, 2008

Central
Appalachia

Northern
Appalachia

Eastern
Met*

Rhino
Western

Other

Total**(in millions)Net income

$
(3.5
)
$
10.9

$
(1.6
)
$
0.7

$
(5.6
)
$
0.9Plus:Depreciation, depletion and amortization


24.9


8.1





0.7


2.7


36.4Interest expense


3.5


1.4





0.3


0.4


5.5EBITDA**

$
24.9

$
20.4

$
(1.6
)
$
1.7

$
(2.5
)
$
42.9


*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.EBITDA
is calculated based on actual amounts and not the rounded amounts presented in this table.**Totals
may not foot due to rounding


Liquidity and Capital Resources



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

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

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



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

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

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

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



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

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

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



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

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

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

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

Off-Balance Sheet Arrangements

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

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

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

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Contractual Obligations

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

Payments Due by PeriodTotal

Less than
1 Year

1 - 3 Years

4 - 5 Years

More than
5 Years(in thousands)Long-term debt obligations (including interest)(1)

$
36,528

$
2,651

$
30,311

$
1,275

$
2,291Asset retirement obligations


35,328


4,350


10,000


10,000


10,978Operating lease obligations(2)


3,356


1,160


2,062


134


Diesel fuel obligations


10,506


10,506








Ammonia nitrate obligations


2,728


2,728








Advance royalties(3)


17,390


1,964


3,428


3,428


8,570Retiree medical obligations


7,001


160


677


1,154


5,010Total

$
112,837

$
23,519

$
46,478

$
15,991

$
26,849


(1)Assumes
a current LIBOR of 0.26% plus the applicable margin for all periods.(2)Some
of our surface mining equipment and a coal handling and loading facility are categorized as operating leases. These leases have maturity dates ranging
from one month to five years.(3)We
have obligations on various coal and land leases to prepay certain amounts which are recoupable in future years when mining occurs


Critical Accounting Policies and Estimates

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

Partnership Environment and Risk Factors

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

Investment in Joint Venture

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

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

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

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

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

Concentrations of Credit Risk

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

Property, Plant and Equipment

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

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

Asset Impairments

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

Asset Retirement Obligations

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

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

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

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

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

Workers' Compensation Benefits

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

Revenue Recognition

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

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

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

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

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

Derivative Financial Instruments

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

Income Taxes

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

Recent Accounting Pronouncements

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



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

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

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

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

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

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

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Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

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

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

Interest Rate Risk

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

Item 8.    Financial Statements and Supplementary Data.

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

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

None.

Item 9A.    Controls and Procedures.



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

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

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

Item 9B.    Other Information.

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

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

Management of Rhino Resource Partners LP

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

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

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

Executive Officers and Directors

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

Name

Age
(as of 12/31/2010)

Position With Our General PartnerMark D. Zand*


57

Chairman of the Board of DirectorsDavid G. Zatezalo


55

President, Chief Executive Officer and DirectorRichard A. Boone


56

Senior Vice President and Chief Financial OfficerChristopher N. Moravec


54

Executive Vice PresidentAndrew W. Cox


54

Vice President of SalesReford C. Hunt


37

Vice President of Technical ServicesJoseph R. Miller


35

Vice President, Secretary and General CounselJay L. Maymudes*


49

DirectorArthur H. Amron*


54

DirectorKenneth A. Rubin*


56

DirectorJoseph M. Jacobs*


57

DirectorMark L. Plaumann**


55

DirectorDouglas Lambert**


53

DirectorJames F. Tompkins**


62

Director


*Principal
of Wexford Capital.**Independent
director.


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Director Independence

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

Meetings; Committees of the Board of Directors

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



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



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

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

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

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

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

Code of Ethics

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

Section 16(a) Beneficial Ownership Reporting Compliance

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

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Item 11.    Executive Compensation

Compensation Discussion and Analysis

Introduction

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

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



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

Compensation Philosophy and Objectives

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



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

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

Compensation Setting Process

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

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

Elements of Compensation

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

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

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



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

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

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

Employment Agreements

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

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

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

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

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

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

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

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

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

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

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

Name and Principal Position

Salary

BonusDavid G. Zatezalo

$
480,000

0% to 150% of salaryPresident and Chief Executive OfficerRichard A. Boone

$
250,000

0% to 40% of salarySenior Vice President and Chief Financial OfficerChristopher N. Moravec

$
400,000

0% to 40% of salaryExecutive Vice PresidentAndrew W. Cox

$
210,000

0% to 40% of salaryVice President of SalesReford C. Hunt

$
175,000

0% to 40% of salaryVice President of Technical Services


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

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

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

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

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

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401(k) Plan

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

Other Benefits

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

Tax Deductibility of Compensation

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

Compensation Committee Report

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

Members
of the compensation committee:



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Summary Compensation Table

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

Name and Principal Position

Year

Salary ($)

Bonus
($)(1)

Stock
Awards
($)(2)

All Other
Compensation
($)(3)

Total ($)David G. Zatezalo


2010

$
480,000

$
602,100

$
1,500,006

$
22,364

$
2,604,470President and Chief Executive Officer


2009

$
325,000

$
195,000




$
22,280

$
542,280Richard A. Boone


2010

$
242,495

$
215,600

$
499,995

$
10,919

$
969,009Senior Vice President and Chief Financial Officer


2009

$
228,318

$
66,000




$
11,944

$
306,262Christopher N. Moravec


2010

$
365,846

$
469,508

$
149,999

$
10,107

$
995,460Executive Vice President(4)


2009

$
240,000

$
407,000




$
16,035

$
663,035Andrew W. Cox


2010

$
209,999

$
55,100

$
25,010

$
11,048

$
301,157Vice President of Sales


2009

$
210,000

$
65,000




$
11,169

$
286,169Reford C. Hunt


2010

$
175,001

$
160,900

$
25,010

$
12,895

$
373,806Vice President of Technical Services


2009

$
181,732

$
57,000




$
10,054

$
248,786


(1)Includes
the one-time cash bonuses received by certain of our named executive officers in connection with the consummation of our IPO in the
following amounts: (a) Mr. Zatezalo$250,000; (b) Mr. Boone$150,000; (c) Mr. Moravec$150,000; and
(d) Mr. Hunt$100,000. Also includes the annual discretionary bonuses earned by the named executive officers for fiscal 2010. Further, a portion of the bonus amount reported
for Mr. Moravec for fiscal 2010 represents (i) the guaranteed annual bonus of $200,000 provided pursuant to his amended and restated employment agreement effective March 31, 2010,
and (ii) the guaranteed annual term bonus that was paid in monthly installments during 2010 pursuant to Mr. Moravec's prior employment agreement at a rate of $29,166.67 through March
2010 (at an annual rate of $350,000 in effect during 2010).(2)The
amounts reported in the "Stock Awards" column reflect the aggregate grant date fair value of phantom unit awards granted under the LTIP in fiscal year
2010, computed in accordance with FASB ASC Topic 718. See Note 2 to our consolidated financial statements for fiscal 2010 for additional detail regarding assumptions underlying the value of
these equity awards.(3)Amounts
reflect, as applicable with respect to the named executive officers and as provided in the supplemental table below, the use of a company provided
automobile and employer contributions to the CAM Mining LLC 401(k) Plan and the Hopedale Mining LLC 401(k) Plan. The value of


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automobile
use is calculated as the monthly lease payment paid by us on behalf of the executive multiplied by the monthly percentage of personal use of the automobile by the executive.


Name

Automobile
Use

Employer Contribution
to the CAM Mining LLC 401(k) Plan

Employer Contribution
to the Hopedale 401(k) PlanDavid G. Zatezalo

$
314

$


$
22,050Richard A. Boone

$
1,119

$
9,800

$
Christopher N. Moravec

$
307

$
9,800

$
Andrew W. Cox

$
1,248

$
9,800

$
Reford C. Hunt

$
3,615

$
9,280

$



(4)Effective
March 31, 2010, Mr. Moravec's title was changed to Executive Vice President.


Grants of Plan-Based Awards

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

Name

Grant Date

Approval Date

All Other Stock
Awards: Number of
Shares of Stock or
Units (#)(1)

Grant Date Fair
Value of Stock
Awards ($)(2)David G. Zatezalo


10/05/2010


9/30/2010


73,171

$
1,500,006Richard A. Boone


10/05/2010


9/30/2010


24,390

$
499,995Christopher N. Moravec


10/05/2010


9/30/2010


7,317

$
149,999Andrew W. Cox


10/05/2010


9/30/2010


1,220

$
25,010Reford C. Hunt


10/05/2010


9/30/2010


1,220

$
25,010


(1)Reflects
the grant of phantom units under the LTIP made to the named executive officers in connection with the IPO.(2)Reflects
the grant date fair value of the phantom units awarded under the LTIP during fiscal year 2010, computed in accordance with FASB ASC Topic 718.


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

Employment Agreements

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

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

Phantom Unit Awards

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

Outstanding Equity Awards at Fiscal Year End

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

Stock AwardsName

Number of Shares or Units of
Stock That Have Not
Vested (#)(1)

Market Value of Shares or
Units of Stock That Have Not
Vested ($)(2)David G. Zatezalo


73,171

$
1,707,811Richard A. Boone


24,390

$
569,263Christopher N. Moravec


7,317

$
170,779Andrew W. Cox


1,220

$
28,475Reford C. Hunt


1,220

$
28,475


(1)The
vesting schedule applicable to these outstanding phantom units is described above under "Narrative Discussion of Summary Compensation Table and Grants
of Plan-Based Awards Table."(2)This
column represents the closing price of our common units on December 31, 2010, which is $23.34, multiplied by the number of phantom units
outstanding.


Option Exercises and Stock Vested

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

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Pension Benefits

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

Nonqualified Deferred Compensation Table

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

Potential Payments Upon Termination or Change in Control

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

Employment Agreements

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

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



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

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

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

LTIP Phantom Unit Awards

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

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

Quantification of Payments

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

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Table of Contents

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

Name

Change in Control

Termination
without
Cause

Death

Resignation
with Good
ReasonDavid ZatezaloCash Payment




$
480,000

$
720,000

$
480,000Accelerated Equity Vesting(1)

$
1,707,811

$
569,270

$
1,707,811

$
569,270Total

$
1,707,811

$
1,049,270

$
2,427,811

$
1,049,270Richard BooneCash Payment




$
250,000

$
100,000

$
250,000Accelerated Equity Vesting(1)

$
569,263

$
189,754

$
569,263

$
189,754Total

$
569,263

$
439,754

$
669,263

$
439,754Christopher MoravecCash Payment




$
200,000

$
160,000

$
200,000Accelerated Equity Vesting(1)

$
170,779

$
56,926

$
170,779

$
56,926Total

$
170,779

$
256,926

$
330,779

$
256,926Andrew CoxCash Payment




$
113,683
(2)




Accelerated Equity Vesting(1)

$
28,475

$
9,492

$
28,475

$
9,492Total

$
28,475

$
123,175

$
28,475

$
9,492Reford HuntCash Payment











Accelerated Equity Vesting(1)

$
28,475

$
9,492

$
28,475

$
9,492Total

$
28,475

$
9,492

$
28,475

$
9,492


(1)The
accelerated vesting of phantom units is based upon the closing price of our common units on December 31, 2010, which is $23.34, multiplied by the
number of phantom units that would vest upon the occurrence of the event indicated.(2)Includes
six months worth of family medical premiums equal to $8,683 for Mr. Cox.


Director Compensation

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

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

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

Name

Fees Earned or
Paid in Cash ($)(1)

Stock Awards
($)(2)

All Other
Compensation ($)

Total ($)Mark D. Zand(3)

$
7,500

$
25,010

$


$
32,510Arthur H. Amron(3)

$
5,000

$
25,010

$


$
30,010Joseph M. Jacobs(3)

$
5,000

$
25,010

$


$
30,010Douglas Lambert

$
10,000

$
25,010

$


$
35,010Jay L. Maymudes(3)

$
6,250

$
25,010

$


$
31,260Mark L. Plaumann

$
12,500

$
25,010

$


$
37,510Kenneth A. Rubin(3)

$
5,000

$
25,010

$


$
30,010James F. Tompkins

$
10,000

$
25,010

$


$
35,010


(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 "Stock Awards" column reflect the aggregate grant date fair value of the awards granted under the LTIP in fiscal 2010, computed
in accordance with FASB ASC Topic 718. See Note 2 to our consolidated financial statements for fiscal 2010 for additional detail regarding assumptions underlying the value of these
equity awards. As of December 31, 2010, each non-employee director held 915 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.


Compensation Practices as They Related to Risk Management

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

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

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



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

Name of Beneficial Owner

Common Units
Beneficially
Owned

Percentage of
Common Units
Beneficially
Owned

Subordinated
Units
Beneficially
Owned

Percentage of
Subordinated
Units
Beneficially
Owned

Percentage of
Common
and
Subordinated
Units
Beneficially
OwnedRhino Energy Holdings LLC(1)(2)(3)


8,547,696


68.9
%

12,227,198


98.6
%

83.8
%Charles E. Davidson(1)(2)(3)(4)


8,554,983


69.0
%

12,228,896


98.6
%

83.8
%Joseph M. Jacobs(1)(2)(3)(4)


8,554,983


69.0
%

12,228,896


98.6
%

83.8
%Wexford Capital LP(1)(2)(3)


8,553,796


69.0
%

12,227,198


98.6
%

83.8
%Wexford GP LLC(1)(2)(3)


8,553,796


69.0
%

12,227,198


98.6
%

83.8
%Mark D. Zand






%





%


%David G. Zatezalo






%





%


%Richard A. Boone






%





%


%Christopher N. Moravec






%





%


%Andrew W. Cox






%





%


%Reford C. Hunt






%





%


%Jay L. Maymudes






%





%


%Arthur H. Amron






%





%


%Kenneth A. Rubin






%





%


%Mark L. Plaumann(5)


1,220


*
%





%

*
%Douglas Lambert(5)


1,220


*
%





%

*
%James F. Tompkins(5)


1,220


*
%





%

*
%All executive officers and directors as a group (13 persons)


8,558,643


69.0
%

12,228,896


98.6
%

83.8
%


*represents
less than 1% of the total.(1)8,547,696
common units and 12,227,198 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 Energy Holdings LLC ("REH"). Wexford Capital serves as manager for REH and
as such may be deemed to share beneficial ownership of the units beneficially owned by REH, but disclaims such beneficial ownership to the extent such beneficial ownership exceeds its pecuniary
interests. Wexford GP LLC ("Wexford GP"), as the general partner of Wexford Capital, may be deemed to share beneficial ownership of the units beneficially owned by REH, but
disclaims such beneficial ownership to the extent such beneficial ownership exceeds its pecuniary interests. Messrs. Davidson and Jacobs, as the controlling persons of Wexford GP, may be
deemed to share beneficial ownership of any units


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beneficially
owned by REH for which Wexford Capital serves as manager, but disclaim such beneficial ownership to the extent such beneficial ownership exceeds their respective pecuniary interests. (2)An
aggregate 6,100 common units were granted to five Wexford Capital-affiliated directors of our general partner on behalf of and as agent for Wexford
Capital, subject to the terms and conditions set forth in the LTIP. Thus, such 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. Under the LTIP, 25% of the units vested upon the grant, 25% vested on January 3,
2011, and the remaining 50% vest ratably on April 1, 2011 and July 1, 2011.(3)The
address for this person or entity is 411 West Putnam Avenue, Greenwich, Connecticut 06830.(4)1,187
common and 1,698 subordinated units shown as beneficially owned by each of Messrs. Davidson and Jacobs reflect those units owned of record by a
company for which they serve as manager. Messrs. Davidson and Jacobs may be deemed to share beneficial ownership with respect to those units, but disclaim such beneficial ownership to the extent it
exceeds their respective pecuniary interests.(5)These
units were issued on October 5, 2010 pursuant to the LTIP. Under such plan, 25% of the units vested upon the grant, 25% vested on
January 3, 2011, and the remaining 50% vest ratably on April 1, 2011 and July 1, 2011.


Equity Compensation Plan Information

Plan Category

Number of units to be
issued upon
exercise/vesting of
outstanding options,
warrants and rights as of
December 31, 2010

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,
2010Equity compensation plans not approved by unitholders(1):Long-Term Incentive Plan


127,809

n/a


2,341,831


(1)Adopted
by the board of directors of our general partner in connection with our IPO.


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

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

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

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

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Distributions and Payments to Our General Partner and Its Affiliates

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



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

Agreements with Affiliates

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



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



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

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

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Table of Contents

Policies Relating to Conflicts of Interest

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

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

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



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

Director Independence

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

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Item 14.    Principal Accounting Fees and Services.

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

2010

2009Audit Fees(1)

$
1,080

$
220Tax Fees(2)


107


106Total

$
1,187

$
326


(1)Expenditures
classified as "Audit fees" above include those related to Deloitte and Touche LLP's audit of our consolidated financial statements and
work performed in connection with our IPO.(2)"Tax
fees" are related to general tax advisory services.


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

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PART IV

Item 15.    Exhibits, Financial Statement Schedules.

(a)(1)  Financial Statements

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

(2)       Financial Statement Schedules

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

(3)       Exhibits

EXHIBIT LIST

Exhibit
Number

Description3.1

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,
20103.2

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, 20104.1

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, 201010.1

Contribution, Assignment and Assumption Agreement, dated as of September 29, 2010, by and among Rhino GP LLC, Rhino Resource Partners LP, Rhino Energy LLC, Rhino Energy Holdings LLC, Artis
Investors LLC, Solitair LLC, Valentis Investors LLC, Taurus Investors LLC, Callidus Investors LLC, Wexford Spectrum Fund, L.P., Wexford Spectrum Fund Liquidating LLC, Wexford Offshore CAM Preferred Corp., Wexford
Offshore CAM Common Corp., Wexford Partners Investment Co. LLC, Peter Savitz and Wexford Capital LP, incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on
October 1, 201010.2

Equity Commitment Agreement, dated September 29, 2010, by and among Rhino GP LLC, CD Holding Company, LLC, Jacobs Holdings LLC, Robert H. Holtz, Mark D. Zand, Jay L. Maymudes, Arthur H. Amron,
Kenneth A. Rubin, Frederick B. Simon, Kitty Capital LLC, John V. Doyle and John C. Sites, Jr., incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1,
201010.3

Rhino Long-Term Incentive Plan incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 201010.4

Form of Long-Term Incentive Plan Grant AgreementPhantom Units with DERs, incorporated by reference to Exhibit 10.12 of Amendment No. 3 to the Registration Statement on Form S-1 (File
No. 333-166550) filed on July 23, 201010.5

Form of Long-Term Incentive Plan Grant AgreementUnit Awards and Restricted Units (Directors who are not Principals of Wexford), incorporated by reference to Exhibit 10.22 of Amendment No. 3 to the
Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010


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Exhibit
Number

Description10.6

Form of Long-Term Incentive Plan Grant AgreementUnit Awards and Restricted Units (Directors who are Principals of Wexford), incorporated by reference to Exhibit 10.23 of Amendment No. 3 to the Registration
Statement on Form S-1 (File No. 333-166550) filed on July 23, 201010.7

Credit Agreement by and among CAM Holdings LLC, the Guarantors Party Thereto, the Lenders Party Thereto, PNC Bank, National Association, as Administrative Agent, PNC National Markets LLC and National City Bank
as Joint Lead Arrangers, and Wachovia Bank, National Association, Royal Bank of Canada and Raymond James Bank, FSB, as Co-Documentations Agents dated as of August 30, 2006, incorporated by reference to Exhibit 10.1 of the initial filing of
the Registration Statement on Form S-1 (File No. 333-166550) filed on May 5, 201010.8

First Amendment to the Credit Agreement dated December 28, 2006 by and among CAM Holdings LLC, each of the Guarantors (as defined therein), the Lenders Party Thereto, and PNC Bank, National Association, as
administrative agent for the Lenders, incorporated by reference to Exhibit 10.2 of the initial filing of the Registration Statement on Form S-1 (File No. 333-166550) filed on May 5, 201010.9

Second Amendment to the Credit Agreement and Consent dated March 8, 2007 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as
defined therein), the Lenders Party Thereto, and PNC Bank, National Association, as administrative agent for the Lenders, incorporated by reference to Exhibit 10.3 of the initial filing of the Registration Statement on Form S-1 (File
No. 333-166550) filed on May 5, 201010.10

Third Amendment to the Credit Agreement dated February 29, 2008 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined
therein), the Lenders Party Thereto, and PNC Bank, National Association, as administrative agent for the Lenders, incorporated by reference to Exhibit 10.4 of the initial filing of the Registration Statement on Form S-1 (File
No. 333-166550) filed on May 5, 201010.11

Fourth Amendment to the Credit Agreement dated May 15, 2008 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined
therein), the Lenders Party Thereto, and PNC Bank, National Association, as administrative agent for the Lenders incorporated by reference to Exhibit 10.5 of the initial filing of the Registration Statement on Form S-1 (File
No. 333-166550) filed on May 5, 201010.12

Fifth Amendment to the Credit Agreement dated June 1, 2008 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined therein),
 the Lenders Party Thereto, and PNC Bank, National Association, as administrative agent for the Lenders, incorporated by reference to Exhibit 10.6 of the initial filing of the Registration Statement on Form S-1 (File No. 333-166550)
filed on May 5, 201010.13

Sixth Amendment to the Credit Agreement dated November 4, 2008 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined
therein), the Lenders Party Thereto, and PNC Bank, National Association, as administrative agent for the Lenders, incorporated by reference to Exhibit 10.7 of the initial filing of the Registration Statement on Form S-1 (File
No. 333-166550) filed on May 5, 2010


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Exhibit
Number

Description10.14

Seventh Amendment to the Credit Agreement dated March 31, 2009 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined
therein), the Lenders Party Thereto, and PNC Bank, National Association, as administrative agent for the Lenders, incorporated by reference to Exhibit 10.8 of the initial filing of the Registration Statement on Form S-1 (File
No. 333-166550) filed on May 5, 201010.15

Eighth Amendment to the Credit Agreement dated June 30, 2010 by and among Rhino Energy LLC, a Delaware limited liability company formerly known as CAM Holdings LLC, each of the Guarantors (as defined
therein), the Lenders Party Thereto, and PNC Bank, National Association, as administrative agent for the Lenders, incorporated by reference to Exhibit 10.8 of Amendment No. 2 to the Registration Statement on Form S-1 (File
No. 333-166550) filed on July 19, 201010.16

Employment Agreement of David G. Zatezalo dated March 31, 2010, incorporated by reference to Exhibit 10.13 of Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-166550) filed
on June 21, 201010.17

Employment Agreement of Richard A. Boone dated April 16, 2008, incorporated by reference to Exhibit 10.14 of Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-166550) filed
on June 21, 201010.18

Employment Agreement of Christopher N. Moravec dated March 31, 2010, incorporated by reference to Exhibit 10.15 of Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-166550)
filed on June 21, 201010.19

Employment Agreement of Andrew W. Cox dated January 2, 2007, incorporated by reference to Exhibit 10.16 of Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on
June 21, 201010.20

Employment Agreement of Reford C. Hunt dated September 1, 2006, incorporated by reference to Exhibit 10.17 of Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-166550) filed
on June 21, 201010.21

First Amendment to Employment Agreement of Reford C. Hunt dated October 31, 2006, incorporated by reference to Exhibit 10.18 of Amendment No. 1 to the Registration Statement on Form S-1 (File
No. 333-166550) filed on June 21, 201010.22

Second Amendment to Employment Agreement of Reford C. Hunt dated March 10, 2008, incorporated by reference to Exhibit 10.19 of Amendment No. 1 to the Registration Statement on Form S-1 (File
No. 333-166550) filed on June 21, 201010.23

Assignment Agreement and Amendment to Employment Agreement of Reford C. Hunt dated August 26, 2008, incorporated by reference to Exhibit 10.20 of Amendment No. 1 to the Registration Statement on
Form S-1 (File No. 333-166550) filed on June 21, 201010.24

Third Amendment to Employment Agreement of Reford C. Hunt dated April 26, 2010, incorporated by reference to Exhibit 10.21 of Amendment No. 1 to the Registration Statement on Form S-1 (File
No. 333-166550) filed on June 21, 201010.25
*
Amended and Restated Employment Agreement of Andrew W. Cox dated January 14, 201121.1
*
List of Subsidiaries of Rhino Resource Partners LP23.1
*
Consent of Deloitte & Touche LLP


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Exhibit
Number

Description31.1
*
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)99.1
*
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, 2010 and the three months ended December 31,
2010


*Filed
herewith.Management
contract or compensatory plan or arrangement required to be filed as an exhibit to this 10-K pursuant to Item 15(b).


123

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Table of Contents

SIGNATURES

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

RHINO RESOURCE PARTNERS LPBy: Rhino GP LLC, its general partnerBy:

/s/ DAVID G. ZATEZALO David G. Zatezalo President, Chief Executive Officer and Director


Date:
March 18, 2011

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

Signature

Title

Date/s/ DAVID G. ZATEZALO David G. Zatezalo

President, Chief Executive Officer and Director (Principal Executive Officer)

March 18, 2011/s/ RICHARD A. BOONE Richard A. Boone

Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

March 18, 2011/s/ MARK D. ZAND Mark D. Zand

Director

March 18, 2011/s/ ARTHUR A. AMRON Arthur A. Amron

Director

March 18, 2011/s/ JAY L. MAYMUDES Jay L. Maymudes

Director

March 18, 2011/s/ KENNETH L. RUBIN Kenneth L. Rubin

Director

March 18, 2011/s/ JOSEPH M. JACOBS Joseph M. Jacobs

Director

March 18, 2011


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Table of Contents

Signature

Title

Date/s/ MARK L. PLAUMANN Mark L. Plaumann

Director

March 18, 2011/s/ DOUGLAS LAMBERT Douglas Lambert

Director

March 18, 2011/s/ JAMES F. TOMPKINS James F. Tompins

Director

March 18, 2011


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Table of Contents

INDEX TO FINANCIAL STATEMENTS



RHINO RESOURCE PARTNERS LPReport of Independent Registered Public Accounting Firm


F-2Consolidated Statements of Financial Position as of December 31, 2010 and
2009


F-3Consolidated Statements of Operations and Comprehensive Income for the Years
Ended December 31, 2010, 2009, and 2008


F-4Consolidated Statements of Members' Equity/Partners' Capital for the Years Ended
December 31, 2010, 2009 and 2008


F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2010,
 2009 and 2008


F-6Notes to Consolidated Financial Statements


F-7


F-1

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

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

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

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

/s/DELOITTE & TOUCHE LLP

Cincinnati,
OH
March 18, 2011

F-2

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Table of Contents

RHINO RESOURCE PARTNERS LP        CONSOLIDATED STATEMENTS OF FINANCIAL POSITION        AS OF DECEMBER 31, 2010 AND 2009        (In thousands)

As of December 31,2010

2009ASSETSCURRENT ASSETS:Cash and cash equivalents

$
76

$
687Accounts receivable, net of allowance for doubtful accounts ($19 as of December 31, 2010 and 2009, respectively)


27,351


24,383Inventories


15,635


14,172Advance royalties, current portion


1,918


1,015Prepaid expenses and other


5,376


4,569Total current assets


50,356


44,826PROPERTY, PLANT AND EQUIPMENT:At cost, including coal properties, mine development and construction costs


442,112


398,904Less accumulated depreciation, depletion and amortization


(159,535
)

(128,224
)Net property, plant and equipment


282,577


270,680Advance royalties, net of current portion


2,935


3,558Investment in unconsolidated affiliate


18,749


17,186Goodwill


202


202Intangible assets, net


719


806Other non-current assets


3,107


2,726TOTAL

$
358,645

$
339,984LIABILITIES AND EQUITYCURRENT LIABILITIES:Accounts payable

$
15,493

$
13,851Accrued expenses and other


12,969


15,075Current portion of long-term debt


2,908


2,242Current portion of asset retirement obligations


4,350


5,427Current portion of postretirement benefits


160


95Total current liabilities


35,880


36,690NON-CURRENT LIABILITIESLong-term debt


33,620


119,896Asset retirement obligations


31,341


39,674Other non-current liabilities


3,706


208Postretirement benefits


6,481


5,115Total non-current liabilities


75,148


164,893Total liabilities


111,028


201,583COMMITMENTS AND CONTINGENCIES (NOTE 13)MEMBERS' EQUITY:Members' investment





22,907Retained earnings





114,016Accumulated other comprehensive income





1,478Total members' equity





138,401PARTNERS' CAPITAL:Limited Partners


236,582General Partner


10,410Accumulated other comprehensive income


625Total Partners' capital


247,617TOTAL

$
358,645

$
339,984


See notes to consolidated financial statements.

F-3

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Table of Contents

RHINO RESOURCE PARTNERS LP        CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME        FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
    (In thousands, except per unit data)

Year Ended December 31,2010

2009

2008REVENUES:Coal sales

$
289,885

$
401,752

$
408,817Freight and handling revenues


4,174


5,050


10,192Other revenues


11,588


12,988


19,915Total revenues


305,647


419,790


438,924COSTS AND EXPENSES:Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)


220,756


336,335


364,912Freight and handling costs


2,634


3,991


10,223Depreciation, depletion and amortization


34,108


36,279


36,428Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)


16,449


16,754


19,042Asset impairment loss


652





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


(10,716
)

1,710


451Total costs and expenses


263,883


395,069


431,056INCOME FROM OPERATIONS


41,764


24,721


7,868INTEREST AND OTHER INCOME (EXPENSE):Interest expense and other


(5,338
)

(6,222
)

(5,500
)Interest income and other


24


70


148Equity in net income (loss) of unconsolidated affiliate


4,699


893


(1,587
)Total interest and other income (expense)


(615
)

(5,259
)

(6,939
)INCOME BEFORE INCOME TAXES


41,149


19,462


929INCOME TAXES








NET INCOME


41,149


19,462


929Other comprehensive incomeAmortization of actuarial gain under ASC Topic 815


(853
)

543


346COMPREHENSIVE INCOME

$
40,296

$
20,005

$
1,275Net income attributable to PredecessorJan 1 to Oct 5, 2010

$
35,703Net income attributable to PartnershipOct 6 to Dec 31, 2010

$
5,446General Partner's interest in net income

$
109Common Unitholders' interest in net income

$
2,668Subordinated Unitholders' interest in net income

$
2,669Net income per limited partner unit, basic:Common units

$
0.22Subordinated units

$
0.22Net income per limited partner unit, diluted:Common units

$
0.22Subordinated units

$
0.22Weighted average number of limited partner units outstanding, basic:Common units


12,400Subordinated units


12,397Weighted average number of limited partner units outstanding, diluted:Common units


12,413Subordinated units


12,397


See notes to consolidated financial statements.

F-4

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Table of Contents

RHINO RESOURCE PARTNERS LP        CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY/PARTNERS' CAPITAL        FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008        (in thousands)

Members'
Investment

Retained
Earnings

Accumulated
Other
Comprehensive
Income/(loss)

Total Members'
EquityBALANCEJanuary 1, 2008

$
23,627

$
93,625

$
589

$
117,841Distribution to members


(805
)







(805
)Net income





929





929Change in actuarial gain under ASC Topic 815








346


346BALANCEDecember 31, 2008

$
22,822

$
94,554

$
935

$
118,311Members contribution


85








85Net income





19,462





19,462Change in actuarial gain under ASC Topic 815








543


543BALANCEDecember 31, 2009

$
22,907

$
114,016

$
1,478

$
138,401Net income prior to initial public offering





35,703





35,703Change in actuarial gain under ASC Topic 815








(113
)

(113
)Contribution to successor


(22,907
)

(149,719
)

(1,365
)

(173,991
)BALANCEOctober 5, 2010

$


$


$


$





Limited PartnerCommon

SubordinatedGeneral
Partner
Capital

Accumulated Other
Comprehensive
Income/(loss)

Total Partners'
CapitalUnits

Capital

Units

CapitalBALANCEOctober 5, 2010




$





$


$


$


$
Contribution from predecessor


9,153


73,320


12,397


99,306





1,365


173,991Initial public offering


3,244


62,012














62,012Initial general partner contribution














10,373





10,373Offering costs





(1,842
)




(1,842
)

(76
)




(3,760
)Net income after IPO





2,668





2,669


109





5,446Partners' contributions














4





4Equity-based compensation





241














241Issuance of units under LTIP


3


50














50Change in actuarial gain under ASC Topic 815

















(740
)

(740
)BALANCEDecember 31, 2010


12,400

$
136,449


12,397

$
100,133

$
10,410

$
625

$
247,617


See notes to consolidated financial statements.

F-5

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Table of Contents

RHINO RESOURCE PARTNERS LP        CONSOLIDATED STATEMENTS OF CASH FLOWS        FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008        (In
thousands)

Year Ended December 31,2010

2009

2008CASH FLOWS FROM OPERATING ACTIVITIES:Net income

$
41,149

$
19,462

$
929Adjustments to reconcile net income to net cash provided by operating activities:Depreciation, depletion and amortization


34,108


36,279


36,428Accretion on asset retirement obligations


2,165


2,753


2,709Accretion on interest-free debt


206


200


569Amortization of advance royalties


865


215


471Amortization of debt issuance costs


844





Provision for doubtful accounts





19


Equity in net (income) loss of unconsolidated affiliate


(4,699
)

(893
)

1,587(Gain) loss on retirement of advance royalties


396


712


45(Gain) loss on sale of assetsnet


73


1,710


450Loss on impairment of assets


652





(Gain) on acquisition of assets


(10,789
)




Equity-based compensation


291





Settlement of litigation





(1,773
)

Changes in assets and liabilities:Accounts receivable


(2,968
)

3,295


13,720Inventories


(1,463
)

(3,459
)

(3,104
)Advance royalties


(1,541
)

(1,027
)

(1,510
)Prepaid expenses and other assets


(1,624
)

924


(1,401
)Accounts payable


1,416


(5,272
)

4,658Accrued expenses and other liabilities


1,391


(963
)

1,812Asset retirement obligations


(6,049
)

(11,373
)

(817
)Postretirement benefits


578


686


665Net cash provided by operating activities


55,001


41,495


57,211CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant, and equipment


(26,248
)

(27,836
)

(78,076
)Proceeds from sales of property, plant, and equipment


95


905


3,044Principal payments received on notes receivable


1,142


3,448


2,060Cash advances from issuance of notes receivable


(765
)

(2,040
)

(1,785
)Changes in restricted cash


(3
)




664Investment in unconsolidated affiliate








(17,880
)Return of capital from unconsolidated affiliate


3,137





Acquisitions of coal companies and other properties


(15,002
)




(14,665
)Acquisition of roof bolt manufacturing company





(1,821
)

Net cash used in investing activities


(37,644
)

(27,344
)

(106,638
)CASH FLOWS FROM FINANCING ACTIVITIES:Borrowings on line of credit


116,070


166,450


194,100Repayments on line of credit


(201,600
)

(175,450
)

(140,100
)Proceeds from issuance of long-term debt


2,170


4,576


Payment of abandoned public offering expenses








(3,582
)Repayments on long-term debt


(2,455
)

(4,943
)

(5,697
)Payments on debt issuance costs


(782
)

(1,169
)

(1,085
)Proceeds from issuance of debt from related party





50


4,950Repayments on loan payable to related party





(5,000
)

Proceeds from issuance of common units, net of issuance costs


62,012





Partner contributions


10,377





Payment of offering costs


(3,760
)




Distributions to members








(805
)Contributions from members





85


Net cash (used in) provided by financing activities


(17,968
)

(15,401
)

47,781NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS


(611
)

(1,250
)

(1,646
)CASH AND CASH EQUIVALENTSBeginning of period


687


1,937


3,583CASH AND CASH EQUIVALENTSEnd of period

$
76

$
687

$
1,937


See notes to consolidated financial statements.

F-6

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Table of Contents

RHINO RESOURCE PARTNERS LP        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

1. ORGANIZATION AND BASIS OF PRESENTATION

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

Initial Public Offering

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

Acquisition of Coal Property

In August 2010, the Predecessor acquired certain assets for cash consideration of approximately $15.0 million from the Trustee
of the Federal Bankruptcy Court charged with the sale of the C.W. Mining Company assets. These assets are located in Emery and Carbon Counties, Utah. Prior to the purchase of the assets, the
Operating Company formed a new wholly owned subsidiary, Castle Valley Mining LLC ("Castle Valley"). Castle Valley in turn acquired the following assets and liabilities (of the former C.W.
Mining Company) from the Operating Company:



F-7

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

1. ORGANIZATION AND BASIS OF PRESENTATION (Continued)



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

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

(in thousands)Mining and other equipment & related facilities

$
8,689Asset retirement costs


933Coal properties


17,100Asset retirement obligation liability assumed


(933
)Net assets acquired


25,789Gain on bargain purchase


(10,789
)Total consideration

$
15,000


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

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

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

Acquisition of Manufacturing Company

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

F-8

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

1. ORGANIZATION AND BASIS OF PRESENTATION (Continued)

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

(in thousands)Inventory

$
21Property, plant and equipment


792Intangible assets


806Goodwill


202Assets acquired


1,821Total consideration

$
1,821


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

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

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

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

F-9

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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

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

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

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

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

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

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

F-10

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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

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

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

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

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

F-11

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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

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

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

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

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

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

F-12

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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

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

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

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

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

F-13

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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

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

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

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

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

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

F-14

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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



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

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

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

3. SUBSEQUENT EVENTS

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

F-15

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

3. SUBSEQUENT EVENTS (Continued)

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

In
February and March of 2011, the Partnership completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price
of approximately $3.0 million. The Partnership expects royalty revenues to be generated from these mineral rights in future periods. The Partnership has not completed its accounting analysis
for this acquisition.

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

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

December 31,2010

2009(in thousands)Notes receivable

$


$
377Other prepaid expenses


929


572Prepaid insurance


3,239


2,919Prepaid leases


82


53Supply inventory


956


480Deposits


170


168Total

$
5,376

$
4,569


5. PROPERTY, PLANT AND EQUIPMENT

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

December 31,Useful Lives

2010

2009(in thousands)Land and land improvements



$
25,748

$
21,413Mining and other equipment and related facilities

2 - 20 Years


218,886


203,726Mine development costs

1 - 15 Years


56,857


47,135Coal properties

1 - 15 Years


132,431


119,765Construction work in process




8,190


6,865Total




442,112


398,904Less accumulated depreciation, depletion and amortization




(159,535
)

(128,224
)Net



$
282,577

$
270,680


F-16

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

5. PROPERTY, PLANT AND EQUIPMENT (Continued)

Depreciation
expense for mining and other equipment and related facilities, depletion expense for coal properties, amortization expense for mine development costs, amortization expense
for intangible assets and amortization expense for asset retirement costs for the years ended December 31, 2010, 2009 and 2008 was as follows:

Year Ended December 31,2010

2009

2008(in thousands)Depreciation expense-mining and other equipment and related facilities

$
26,791

$
29,247

$
25,990Depletion expense for coal properties


1,807


2,315


3,954Amortization expense for mine development costs


2,138


2,875


4,315Amortization expense for intangible assets


87





Amortization expense for asset retirement costs

$
3,285

$
1,842

$
2,740


Long-Lived Asset Impairment

During the fourth quarter of 2010, the management of the Partnership made a strategic decision to dispose of certain assets of two of
its ancillary businesses. As of December 31, 2010, the management of the Partnership tested the assets related to these ancillary
businesses for recoverability by comparing expected undiscounted future cash flows to their carrying values. This analysis indicated a potential impairment existed for these specific assets. Since the
potential for impairment existed for these assets, the Partnership measured an impairment loss by determining the amount by which the carrying amount of the assets exceeded their fair value.
Additionally, the Partnership determined the specific assets of these ancillary businesses should be classified as held for sale since they were being actively marketed to third-party buyers as of
December 31, 2010 and the remaining requirements of the accounting literature on asset impairments had been met to qualify as being held for sale. The Partnership concluded the market approach
would be the best indicator of fair value as market participants would place bids for the specific assets that would reflect the assets highest and best use in the marketplace. The assets were written
down to their fair value, less costs to sell, at December 31, 2010 which resulted in a $0.7 million charge that is reflected on theAsset impairment
lossline of the Consolidated Statements of Operations and Comprehensive Income. This charge was reflected in the Other category for 2010 segment reporting purposes. The
carrying value of these assets at December 31, 2010 was $1.1 million and they are included inProperty, plant and equipmenton the
Consolidated Statements of Financial Position due to their immaterial amount. Based on the fair value determination that was developed from unobservable data and reflected the Partnership's
assumptions, these assets were determined to be a Level 3 fair value measurement. These assets are the only Level 3 fair value measurements for the Partnership for any periods presented
in this report.

6. GOODWILL AND INTANGIBLE ASSETS

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. The Partnership performs its impairment analysis as of August 31.

F-17

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

6. GOODWILL AND INTANGIBLE ASSETS (Continued)

Goodwill
as of December 31, 2010 and 2009 consisted of the following:

December 31,2010

2009(in thousands)$
202

$
202


Intangible
assets of the Partnership as of December 31, 2010 consisted of the following:

Intangible Asset

Gross
Carrying
Amount

Accumulated
Amortization

Net
Carrying
Amount(in thousands)Patent

$
728

$
79

$
649Developed Technology


78


8


70Total

$
806

$
87

$
719


Intangible
assets of the Predecessor as of December 31, 2009 consisted of the following:

Intangible Asset

Gross
Carrying
Amount

Accumulated
Amortization

Net
Carrying
Amount(in thousands)Patent

$
728

$


$
728Developed Technology


78





78Total

$
806

$


$
806


The
Partnership considers these intangible assets to have a useful life of seventeen years. The intangible assets are amortized over their useful life on a straight line basis.
Amortization for the year ended December 31, 2009 was not material.

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, 2010:

Patent

Developed
Technology

Total(in thousands)2011

$
43

$
5

$
482012


43


5


482013


43


5


482014


43


5


482015


43


5


48


F-18

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

7. OTHER NON-CURRENT ASSETS

Other non-current assets as of December 31, 2010 and 2009 consisted of the following:

December 31,2010

2009(in thousands)Deposits and other

$
840

$
321Debt issuance costsnet


2,211


2,272Deferred expenses


56


133Total

$
3,107

$
2,726


Debt
issuance costs were $4.3 million and $4.3 million as of December 31, 2010 and 2009, respectively. Accumulated amortization of debt issuance costs were
$2.1 million and $2.0 million as of December 31, 2010 and 2009, respectively.

8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of December 31, 2010 and 2009 consisted of the following:

December 31,2010

2009(in thousands)Payroll, bonus and vacation expense

$
3,570

$
3,668Non income taxes


3,020


3,641Royalty expenses


2,184


2,550Accrued interest


460


325Health claims


2,046


1,619Workers' compensation & pneumoconiosis


1,400


3,090Other


289


182Total

$
12,969

$
15,075


F-19

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

9. DEBT

Debt as of December 31, 2010 and 2009 consisted of the following:

December 31,2010

2009(in thousands)Senior secured credit facility with PNC Bank, N.A.

$
28,470

$
114,000Note payable to H&L Construction Co., Inc.


2,973


3,628Other notes payable


5,085


4,510Total


36,528


122,138Less current portion


(2,908
)

(2,242
)Long-term debt

$
33,620

$
119,896


Senior Secured Credit Facility with PNC Bank, N.A.The maximum availability under the credit facility by and among the Operating Company, the
guarantors (including the Partnership) and lenders which are parties thereto, and PNC Bank, N.A. as administrative agent is $200.0 million. Borrowings under the line of credit bear interest
which varies depending upon the grouping of the borrowings within the line of credit. At December 31, 2010, the Operating Company had borrowed $22.0 million at a variable interest rate
of LIBOR plus 3.00% (3.26% at December 31, 2010) and an additional $6.5 million under a revolving credit arrangement at a variable interest rate of PRIME plus 1.50% (4.75% at
December 31, 2010). In addition, the Operating Company had outstanding letters of credit of $32.6 million at a fixed interest rate of 3.00% at December 31, 2010. The credit
agreement is to expire in February 2013. At December 31, 2010, the Operating Company had not used $138.9 million of the borrowing availability. As part of the agreement, the Operating
Company is required to pay a
commitment fee of 0.5% on the unused portion of the borrowing availability. Borrowings on the line of credit are collateralized by all the unsecured assets of the Partnership.

The
revolving credit commitment 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, selling or assigning stock. The Partnership was in compliance with all restrictive
provisions as of December 31, 2010.

In
April 2009, the credit agreement was amended to revise certain restrictive provisions and extended the agreement expiration date to February 2013. The restrictive provisions of the
amended credit agreement were effective as of March 31, 2009.

In
June 2010, the credit agreement was further amended to revise certain restrictive provisions, allow for the equity transfer of the Predecessor to the Partnership in the event of a
successful IPO and provide for quarterly cash distributions of available cash, as that term is defined in the Partnership's limited partnership agreement. The IPO was completed on October 5,
2010 as described in Note 1, "Organization and Basis of Presentation".

Note payable to H&L Construction Co., Inc.The note payable to H&L Construction Co., Inc. was originally a
non-interest bearing note and the Partnership has recorded a discount for imputed interest at a rate of 5.0% on this note that is being amortized over the life of the note using the
effective

F-20

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

9. DEBT (Continued)

interest
method. In 2009, the note was renegotiated and is now an interest bearing note as of December 31, 2009. The note payable matures in January 2015. The note is secured by mineral rights
purchased by the Partnership from H&L Construction Co., Inc. with a carrying amount of $11.8 million and $12.4 million at December 31, 2010 and 2009, respectively.

Principal
payments on long-term debt due subsequent to December 31, 2010 are as follows:

in thousands2011

$
2,7872012


8802013


29,5972014


1,0212015


279Thereafter


2,291Total principal payments


36,855Less imputed interest on interest free notes payable


(327
)Total debt

$
36,528


10. ASSET RETIREMENT OBLIGATIONS

The changes in asset retirement obligations for the years ended December 31, 2010, 2009 and 2008 are as follows:

Year Ended December 31,2010

2009

2008(in thousands)Balance at beginning of period (including current portion)

$
45,101

$
55,760

$
36,387Accretion expense


2,165


2,753


2,709Adjustment resulting from addition of property


933





17,481Adjustment resulting from disposal of property





(2,039
)

Adjustments to the liability from annual recosting and other


(10,202
)

(6,596
)

1,410Liabilities settled


(2,306
)

(4,777
)

(2,227
)Balance at end of period


35,691


45,101


55,760Current portion of asset retirement obligation


4,350


5,427


7,721Long-term portion of asset retirement obligation

$
31,341

$
39,674

$
48,039


11. EMPLOYEE BENEFITS

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. The Partnership has no other postretirement plans.

F-21

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

11. EMPLOYEE BENEFITS (Continued)

Summaries
of the changes in benefit obligations and funded status of the plan as of the measurement dates of December 31, 2010, 2009 and 2008 are as follows:

Year Ended December 31,2010

2009

2008(in thousands)Benefit obligation at beginning of period

$
5,210

$
5,067

$
4,748Changes in benefit obligations:Service costs


455


442


454Interest cost


289


325


294Benefits paid


(15
)

(15
)

(67
)Actuarial loss/(gain)


702


(609
)

(362
)Benefit obligation at end of period

$
6,641

$
5,210

$
5,067Fair value of plan assets at end of period

$


$


$
Funded status

$
(6,641
)
$
(5,210
)
$
(5,067
)


The
classification of net amounts recognized for postretirement benefits as of December 31, 2010 and 2009 are as follows:

December 31,2010

2009(in thousands)Current liabilitypostretirement benefits

$
(160
)
$
(95
)Non-current liabilitypostretirement benefits


(6,481
)

(5,115
)Net amount recognized

$
(6,641
)
$
(5,210
)


The
amounts recognized in accumulated other comprehensive income for the years ended December 31, 2010, 2009 and 2008 are as follows:

Year Ended December 31,2010

2009

2008(in thousands)Balance at beginning of year

$
1,478

$
935

$
589Actuarial gain


(702
)

609


362Amortization of actuarial (gain)


(151
)

(66
)

(16
)Net actuarial gain

$
625

$
1,478

$
935




December 31,
2010

December 31,
2009Weighted Average assumptions used to determine benefit obligationsDiscount rate


4.75
%

5.60
%Expected return on plan assets


n/a


n/a


F-22

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

11. EMPLOYEE BENEFITS (Continued)



Year Ended
December 31,
2010

Year Ended
December 31,
2009

Year Ended
December 31,
2008Weighted Average assumptions used to determine periodic benefit costDiscount rate


5.60
%

6.50
%

6.25
%Expected return on plan assets


n/a


n/a


n/aRate of compensation increase


n/a


n/a


n/a


The
components of net periodic benefit cost for the years ended December 31, 2010, 2009 and 2008 are as follows:

Year Ended December 31,2010

2009

2008(in thousands)Service costs

$
455

$
442

$
454Interest cost


289


325


294Amortization of (gain)


(151
)

(66
)

(16
)Benefit cost

$
593

$
701

$
732


Amounts
expected to be amortized from accumulated other comprehensive income into net periodic benefit cost during the year ending December 31, 2011, are as follows:

(in thousands)Net actuarial gain

$



Expected
future benefit payments are as follows:

Period

(in thousands)2011

$
1602012


2842013


3932014


5052015


6492016 - 2020

$
5,010


For
measurement purposes, an 8.00% 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.

F-23

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

11. EMPLOYEE BENEFITS (Continued)

The expense and liability estimates can fluctuate by significant amounts based upon the assumptions used by the Partnership. As of December 31, 2010, a
one-percentage-point change in assumed health care cost trend rates would have the following effects:

One-Percentage
Point Increase

One-Percentage
Point Decrease(in thousands)Effect on total service and interest cost components

$
67

$
(56
)Effect on postretirement benefit obligation

$
603

$
(554
)


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, 2010, 2009 and 2008 was as follows:

Year Ended December 31,2010

2009

2008(in thousands)401(k) plan expense

$
1,798

$
2,326

$
1,998


12. EQUITY-BASED COMPENSATION

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 reserved for issuance under
the LTIP is 2,479,400.

As
of December 31, 2010, the General Partner granted phantom units to certain of the Partnership's employees and restricted units and unit awards to its directors. These grants
were made in connection with the IPO completed during October 2010 and discussed above in Note 1. Certain of

F-24

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

12. EQUITY-BASED COMPENSATION (Continued)

these
awards are subject to service-based vesting conditions and a summary of non-vested LTIP awards as of and for the year ended December 31, 2010 is as follows:

Common
Units

Weighted
Average Grant
Date Fair
Value
(per unit)(in thousands)Non-vested awards at December 31, 2009


Granted


138

$
20.50Vested


(3
)

20.50Forfeited





Non-vested awards at December 31, 2010


135

$
20.50


For
the year ended December 31, 2010, the Partnership recorded an expense of $0.3 million for the LTIP awards. The Partnership expects to settle the non-vested
LTIP awards by delivery of Partnership common units. All of the non-vested LTIP awards granted during 2010 included tandem distribution equivalent rights (or DERs), which are rights to
accrue quarterly cash distributions in an amount equal to the cash distribution the Partnership makes to unitholders during the vesting period. However, any accrued distributions will be forfeited if
the related awards fail to vest according to the relevant vesting conditions of the award.

For
the year ended December 31, 2010, the total fair value of the awards that vested was $0.1 million. As of December 31, 2010, the total unrecognized compensation
expense related to the non-vested LTIP awards that are expected to vest was $2.3 million. The expense is expected to be recognized over a weighted-average period of
2.7 years. As of December 31, 2010, the intrinsic value of the non-vested LTIP awards was $3.2 million.

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and ContingenciesAs of December 31, 2010, the Partnership had commitments under sales contracts to deliver annually
scheduled base quantities of 3.7 million, 2.2 million, and 1.4 million tons of coal to 16 customers in 2011, 5 customers in 2012, 3 customers in 2013, respectively. Some of the
contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Purchase CommitmentsAs of December 31, 2010, the Partnership had 4.0 million gallons remaining on a commitment to purchase diesel fuel
at fixed prices through December 2011 for $10.5 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

F-25

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

13. COMMITMENTS AND CONTINGENCIES (Continued)

contracts
and expense from OTC purchases for the years ended December 31, 2010, 2009 and 2008 was as follows:

Year Ended December 31,2010

2009

2008(in thousands)Purchased coal expense

$
5,373

$
10,525

$
27,042OTC expense

$
8,354

$
98,575

$
12,770


There
were no outstanding coal purchase commitments as of December 31, 2010.

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, 2010, 2009 and 2008 was as follows:

Year Ended December 31,2010

2009

2008(in thousands)Lease expense

$
5,212

$
8,151

$
8,319Royalty expense

$
11,656

$
12,866

$
20,899


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:

Years Ended December 31,

Royalties

Leases(in thousands)2011

$
1,964

$
1,1602012


1,714


1,1672013


1,714


8952014


1,714


892015


1,714


45Thereafter


8,570


Total minimum royalty and lease payments

$
17,390

$
3,356


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. The Partnership is not party to
any
pending litigation that is probable to have a material adverse effect on the financial condition, results of operations or cash flows of the Partnership.

F-26

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

13. COMMITMENTS AND CONTINGENCIES (Continued)

Management
of the Partnership is not aware of any significant legal 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 $32.6 million as of December 31, 2010. 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 $76.1 million as of December 31, 2010 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 9 for a more complete discussion of the Partnership's
debt obligations.

Wexford
Capital fully and unconditionally guarantees 49% of the Partnership's obligations under its outstanding surety bonds with third parties to secure reclamation and other
performance commitments.

Joint VenturePursuant to the joint venture agreement with Patriot, the Partnership is required to contribute additional capital to assist in
funding
the development and operations of the joint venture. During the year ended December 31, 2010, the Partnership did not make any capital contributions. The Partnership may be required to
contribute additional capital or make loans to the joint venture in subsequent periods.

14. EARNINGS PER UNIT ("EPU")

The following table presents a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the period ended December 31:

PartnershipPeriod from
October 6 to December 31, 2010(in thousands, except per unit data)

General
Partner

Common
Unitholders

Subordinated
UnitholdersNumerator:Interest in net income

$
109

$
2,668

$
2,669Denominator:Weighted average units used to compute basic EPU


n/a


12,400


12,397Effect of dilutive securitiesLTIP awards


n/a


13


Weighted average units used to compute diluted EPU


n/a


12,413


12,397Net income per limited partner unit, basic


n/a

$
0.22

$
0.22Net income per limited partner unit, diluted


n/a

$
0.22

$
0.22


F-27

---



Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

15. MAJOR CUSTOMERS

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

December 31
2010
Receivable
Balance

Year Ended
December 31,
2010 Sales

December 31
2009
Receivable
Balance

Year Ended
December 31,
2009 Sales

December 31
2008
Receivable
Balance

Year Ended
December 31,
2008 Sales(in thousands)Indiana Harbor Coke Company, L.P

$
1,539

$
51,277

$
2,260

$
47,478


n/a


n/aAmerican Electric Power Company, Inc.


1,584


36,003


6,563


97,006


6,173


97,647GenOn Energy, Inc. (fka Mirant Corporation)


1,440


37,420


n/a


n/a


n/a


n/aConstellation Energy Group, Inc.


n/a


n/a

$
1,702

$
67,167

$
3,804

$
56,589


16. FAIR VALUE OF FINANCIAL INSTRUMENTS

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 carrying value of the Partnership's debt instruments and notes receivable approximate fair value since effective rates for these
instruments are comparable to market at year-end.

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

Other
than the assets described in Note 5, the Partnership does not have any nonfinancial assets or nonfinancial liabilities measured at fair value.

F-28

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

17. RELATED PARTY AND AFFILIATE TRANSACTIONS

Related Party

Description

2010

2009

2008(in thousands)Wexford Capital LP

Expenses for legal, consulting, and advisory services

$
278

$
61

$
139Wexford Capital LP

Distributions








805Wexford Capital LP

Members contribution





85


Taurus Investors LLC

Note payable








4,950Rhino Eastern LLC

Equity in net income (loss) of unconsolidated affiliate


4,699


893


(1,587
)Rhino Eastern LLC

Distribution from unconsolidated affiliate


3,137





Rhino Eastern LLC

Notes receivable





377


1,785Rhino Eastern LLC

Receivables for legal, health claims and workers' compensation


686


161


128Rhino Eastern LLC

Interest receivable





1


16Rhino Eastern LLC

Investment in unconsolidated affiliate

$
18,749

$
17,186

$
16,293


From time to time, employees from Wexford Capital perform legal, consulting, and advisory services to the Partnership. The Partnership incurred
expenses of $0.3 million, $0.1 million and $0.1 million for the years ended December 31, 2010, 2009 and 2008, respectively, for legal, consulting, and advisory services
performed by Wexford Capital.

As
of December 31, 2009 and 2008, the Predecessor had a note receivable outstanding of $0.4 million and $1.8 million to Rhino Eastern, a joint venture between the
Partnership and Patriot. The note had a fixed interest rate of 10%. The note was fully repaid as of December 31, 2010.

From
time to time, the Partnership and Predecessor have allocated and paid expenses on behalf of the joint venture. During the years ended December 31, 2010, 2009 and 2008, the
Predecessor paid expenses for legal, health claims and workers' compensation of $0.7 million, $0.2 million and $0.1 million, respectively, on behalf of the joint venture.

18. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash payments for interest were $4.1 million, $5.4 million and $4.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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

On
October 5, 2010, in connection with the closing of the IPO, the owners of the Operating Company contributed their membership interests in the Operating Company to the
Partnership, and the Partnership issued 12,397,000 subordinated units representing limited partner interests in the Partnership and 9,153,000 common units to Rhino Energy Holdings LLC, an
affiliate of Wexford

F-29

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

18. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION (Continued)

Capital,
and issued incentive distribution rights to the General Partner. The Consolidated Statement of Cash Flows for the year ended December 31, 2010 is exclusive of the non-cash contribution
of the membership interests in the Operating Company to the Partnership of $174.0 million and is also exclusive of the Partnership's issuance of the subordinated and common units to Rhino Energy
Holdings LLC and the Partnership's issuance of incentive distribution rights to the General Partner.

The
Consolidated Statements of Cash Flows for the year ended December 31, 2010 is exclusive of $0.2 million of property, plant and equipment additions which are recorded in
accounts payable and
$0.3 million of non-cash expense recognized for unit awards granted by the General Partner to certain of its employees and to its directors.

In
September 2009 the Predecessor reached a settlement on the outstanding debt balance with H&L Construction Co., Inc. resulting in a non-cash debt reduction of
$1.8 million.

19. SEGMENT INFORMATION

The Partnership produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio, Colorado and Utah. The Partnership sells primarily to electric utilities in
the United States. For the year ended December 31, 2010, the Partnership has four reportable business segments: Central Appalachia (comprised of both surface and underground mines located in
Eastern Kentucky and Southern West Virginia), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Eastern Met (comprised solely of the joint venture with Patriot)
and Rhino Western (comprised of underground mines in Colorado and Utah). Additionally, the Partnership has an Other category that is comprised of the Partnership's ancillary businesses. Within the
Northern Appalachia reporting segment, the Partnership has aggregated two operating segments (representing its Sands Hill and Hopedale mining complexes) that have similar geography and similar
economic characteristics in terms of product sold, product quality and end customers. Within the Rhino Western reporting segment, the Partnership has aggregated two operating segments (representing
its Colorado mine and Utah mining complex) that have similar geography and similar economic characteristics in terms of product sold, product quality and end customers. 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.

In
periods prior to the year ended December 31, 2010, the Partnership had included its Colorado mine in the Other category since this operation did not meet the quantitative
thresholds requiring separate disclosure as a reportable segment. With the acquisition of the Utah mining complex in August 2010, the Partnership began to aggregate the Colorado mine and Utah mining
complex as one reportable segment as discussed above. For periods prior to the year ended December 31, 2010, the segment data
has been reclassified to present the results of the Colorado mine in the Rhino Western segment instead of the Other category.

F-30

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

19. SEGMENT INFORMATION (Continued)

The Partnership has historically accounted for the joint venture (formed in the year ended December 31, 2008) under the equity method. Under the equity method of accounting, the
Partnership has historically only presented limited information (net income). The Partnership considers this operation to comprise a separate operating segment and has presented additional operating
detail (with corresponding eliminations and adjustments to reflect its percentage of ownership) below. Since this equity method investment has met the significance test of ten percent of net income in
2010, 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, 2010 are as follows (Note: "DD&A" refers to depreciation, depletion and
amortization):

Eastern MetCentral
Appalachia

Northern
Appalachia

Rhino
Western

Complete
Basis

Equity
Method
Eliminations

Equity
Method
Presentation

Other

Total
Segments(in thousands)Total assets

$
195,619

$
53,244

$
60,975

$
42,645

$
(42,645
)
$


$
48,807

$
358,645Total revenues


195,584


95,431


8,839


40,094


(40,094
)




5,793


305,647DD&A


20,083


9,348


594


3,196


(3,196
)




4,083


34,108Interest expense


2,292


1,948


195


72


(72
)




903


5,338Net Income (loss)

$
20,611

$
10,098

$
11,214

$
8,946

$
(4,247
)
$
4,699

$
(5,473
)
$
41,149


Reportable
segment results of operations and financial position for the Predecessor for the year ended December 31, 2009 are as follows:

Eastern MetCentral
Appalachia

Northern
Appalachia

Rhino
Western

Complete
Basis

Equity
Method
Eliminations

Equity
Method
Presentation

Other

Total
Segments(in thousands)Total assets

$
207,870

$
55,565

$
24,755

$
42,428

$
(42,428
)
$


$
51,794

$
339,984Total revenues


297,724


106,741


11,209


28,820


(28,820
)




4,116


419,790DD&A


23,877


7,862


725


2,863


(2,863
)




3,815


36,279Interest expense


3,531


1,776


189


429


(429
)




726


6,222Net Income (loss)

$
561

$
17,638

$
3,306

$
1,751

$
(858
)
$
893

$
(2,936
)
$
19,462


F-31

---



Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

19. SEGMENT INFORMATION (Continued)

Reportable
segment results of operations and financial position for the Predecessor for the year ended December 31, 2008 are as follows:

Eastern MetCentral
Appalachia

Northern
Appalachia

Rhino
Western

Complete
Basis

Equity
Method
Eliminations

Equity
Method
Presentation

Other

Total
Segments(in thousands)Total assets

$
218,924

$
59,463

$
23,218

$
43,454

$
(43,454
)
$


$
50,931

$
352,536Total revenues


316,463


108,432


10,626


4


(4
)




3,403


438,924DD&A


24,906


8,085


742


509


(509
)




2,695


36,428Interest expense


3,520


1,431


162


31


(31
)




387


5,500Net Income (loss)

$
(3,488
)
$
10,933

$
733

$
(3,111
)
$
1,524

$
(1,587
)
$
(5,662
)
$
929


Additional
summarized financial information for the equity method investment as of and for the periods ended December 31, 2010, 2009 and 2008 is as follows:

2010

2009

2008(in thousands)Current assets

$
7,413

$
5,947


n/aNoncurrent assets


35,232


36,481


n/aCurrent liabilities


3,308


3,372


n/aNoncurrent liabilities


2,574


5,481


n/aTotal costs and expenses


31,103


25,981


3,646Income (loss) from operations

$
8,991

$
2,839

$
(3,642
)


20. QUARTERLY FINANCIAL DATA (UNAUDITED)

(in thousands, except per unit data)

First
Quarter

Second
Quarter

Third
Quarter*

Fourth
Quarter**2010:Revenues

$
66,603

$
78,428

$
85,229

$
75,387Income from operations


8,136


7,898


21,674


4,055Net income

$
6,544

$
7,142

$
21,808

$
5,656Basic and diluted net income per limited partner unit:Common units


n/a


n/a


n/a

$
0.22Subordinated units


n/a


n/a


n/a

$
0.22Weighted average number of limited partner units outstanding, basic:Common units


n/a


n/a


n/a


12,400Subordinated units


n/a


n/a


n/a


12,397Weighted average number of limited partner units outstanding, diluted:Common units


n/a


n/a


n/a


12,413Subordinated units


n/a


n/a


n/a


12,397


F-32

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Table of Contents

RHINO RESOURCE PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Continued)



First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter2009:Revenues

$
116,706

$
109,389

$
97,038

$
96,656Income from operations


3,101


7,351


7,374


6,895Net income

$
1,976

$
5,387

$
6,404

$
5,696Basic and diluted net income per limited partner unit


n/a


n/a


n/a


n/aWeighted average number of units outstandingbasic and diluted


n/a


n/a


n/a


n/a


*Note:
Third quarter 2010 income from operations and net income was impacted by a $10.8 million gain recognized on the acquisition of certain assets of
C.W. Mining Company out of bankruptcy in August 2010. The amount of this gain was not finalized until the fourth quarter of 2010, but is presented in the third quarter 2010 results in the table above
in accordance with prescribed accounting guidelines. See Note 1 for more details regarding the gain resulting from this acquisition.**Note:
Fourth quarter basic and diluted net income per limited partner unit is calculated on the portion of fourth quarter net income attributable to the
Partnership after the IPO was completed (October 6, 2010) through December 31, 2010. Refer to the Consolidated Statements of Operations and Comprehensive Income for the net income amount
attributable to this period.


F-33

---