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As filed with the Securities and Exchange Commission on September 10, 2008

Registration No. 333-150262

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

AMENDMENT NO. 6
TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Rhino Resources, Inc.
(Exact Name of Registrant as Specified in Its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)

1221
(Primary Standard Industrial
Classification Code Number)

56-2558621
(I.R.S. Employer
Identification Number)

424 Lewis Hargett Circle, Suite 250
Lexington, Kentucky 40503
(859) 389-6500
(Address, Including Zip Code, and Telephone Number, Including
Area Code, of Registrant's Principal Executive Offices)

Nicholas R. Glancy
424 Lewis Hargett Circle, Suite 250
Lexington, Kentucky 40503
(859) 389-6500
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:
		Charles E. Carpenter Vinson & Elkins L.L.P. 666 Fifth Avenue 26th Floor New York, New York 10103 (212) 237-0000

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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

Large accelerated filer o

Accelerated filer o

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

Smaller reporting company o

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted

Subject to Completion, Dated September 10, 2008

PROSPECTUS

Shares

Common Stock

This is our initial public offering. We are offering shares of common stock and the selling stockholder, Rhino Energy Holdings LLC, is offering shares of common stock. We will not receive any of the proceeds from the sale of the shares by the selling stockholder.

Prior to this offering, there has been no public market for our shares. We anticipate that the initial public offering price will be between $ and $ per share. We have been approved to list our common stock on The New York Stock Exchange under the symbol "RNO."

The selling stockholder has granted the underwriters the right to purchase up to an additional shares of common stock to cover over-allotments.

Investing in our common stock involves risks. See "Risk Factors" beginning on page 18.

$ PER SHARE

		Price to Public		Underwriting Discount and Commissions		Proceeds to Rhino Resources, Inc.		Proceeds to the Selling Stockholder
Per Share		$		$		$		$
Total		$		$		$		$

Delivery of the shares of common stock will be made on or about , 2008.

The Securities and Exchange Commission and state securities regulators have not approved or disapproved these securities, or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

, 2008

TABLE OF CONTENTS


Summary		1
Risk Factors		18
Use of Proceeds		34
Dividend Policy		35
Capitalization		36
Dilution		37
Selected Historical and Pro Forma Consolidated Financial and Operating Data		39
Management's Discussion and Analysis of Financial Condition and Results of Operations		44
The Coal Industry		85
Business		94
Management		126
Security Ownership of Certain Beneficial Owners, Management and the Selling Stockholder		138
Certain Relationships and Related Party Transactions		139
Description of Our Capital Stock		141
Shares Eligible For Future Sale		145
Certain U.S. Federal Tax Considerations For Non-U.S. Holders		147
Underwriting		151
Validity of Our Common Stock		155
Experts		155
Where You Can Find More Information		155
Forward-Looking Statements		157
Index to Financial Statements		F-1
Glossary of Terms		A-1

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of shares of our common stock means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common stock in any circumstances under which the offer or solicitation is unlawful.

Until , 2008 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements, before investing in our common stock. The information presented in this prospectus assumes that the underwriters' option to purchase additional shares is not exercised unless otherwise noted. You should read "Risk Factors" beginning on page 18 for information about important risks that you should consider before buying our common stock.

Market and industry data and certain other statistical data used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. In this prospectus, we refer to information regarding the coal industry in the United States and internationally from the U.S. Department of Energy's Energy Information Administration, the National Mining Association, Bloomberg L.P. and Platts Research and Consulting. These organizations are not affiliated with us.

References in this prospectus to "Rhino Resources, Inc.," "we," "our," "us" or like terms when used in a historical context refer to the business of our predecessor, Rhino Energy LLC and its subsidiaries, that is being contributed to Rhino Resources, Inc. in connection with this offering. When used in the present tense or prospectively, those terms refer to Rhino Resources, Inc. and its subsidiaries. Unless otherwise indicated, references to our proven and probable coal reserves, non-reserve coal deposits and projected coal production include 100% of the reserves and deposits owned by and production of Rhino Eastern LLC, a joint venture in which we own a 51% membership interest and for which we serve as the manager. We include a glossary of some of the terms used in this prospectus as Appendix A.

Rhino Resources, Inc.

We are a growth-oriented Delaware corporation formed to control and operate coal properties and related assets. We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. For the year ended December 31, 2007, we produced approximately 7.1 million tons of coal and sold approximately 8.2 million tons of coal. For the six months ended June 30, 2008, we produced approximately 4.0 million tons of coal and sold approximately 4.2 million tons of coal. As of October 31, 2007, we controlled approximately 222.3 million tons of proven and probable coal reserves and approximately 97.8 million tons of non-reserve coal deposits. We completed the acquisitions of the Sands Hill mining complex located in Northern Appalachia in December 2007 and the Deane mining complex located in Central Appalachia in February 2008. These acquisitions collectively added approximately 18.6 million tons of proven and probable coal reserves and approximately 4.1 million tons of non-reserve coal deposits. We expect to produce approximately 1.8 million tons of coal in 2009 from these mining complexes. In May 2008, we entered into a joint venture, in which we have a 51% membership interest and for which we serve as the manager, that acquired the Eagle mining complex and the Bolt field located in Central Appalachia. The joint venture controls approximately 21.1 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits. We expect that the Eagle mining complex will produce approximately 0.6 million tons of metallurgical coal in 2009. We produce high quality coal that is sold in both the steam and metallurgical coal markets. We market our steam coal primarily to electric utilities, the majority of which are rated investment grade. The metallurgical coal that we produce is sold for end use by domestic and international steel producers.

Since our predecessor's formation in 2003, we have significantly grown our asset base through acquisitions of both strategic assets and leasehold interests, as well as through internal development projects. Since April 2003, we have completed numerous asset acquisitions with a total purchase price of approximately $212.9 million. Through these acquisitions and other coal lease transactions, we have significantly increased our proven and probable coal reserves and non-reserve coal deposits. Our acquisition strategy is focused on assets with high quality coal characteristics that are strategically

located within strong and growing markets. We also base our acquisition decisions on the operating cost structure of a group of assets, targeting those assets for which we believe we can optimize margins or reduce costs.

In addition, we have successfully grown our production through internal development projects. For example, we invested approximately $19.0 million between 2004 and 2006 in the Hopedale mine located in Northern Appalachia to develop the approximately 17.1 million tons of proven and probable coal reserves at the mine. The Hopedale mine produced approximately 1.3 million tons of coal for the year ended December 31, 2007 and approximately 0.8 million tons of coal for the six months ended June 30, 2008. In 2007, we completed development of a new underground metallurgical coal mine at the Rob Fork mining complex located in Central Appalachia. The mine produced approximately 650,000 tons of coal for the year ended December 31, 2007 and approximately 383,000 tons of coal for the six months ended June 30, 2008. We also control or manage proven and probable coal reserves that are currently undeveloped of approximately (1) 102.4 million tons in the Taylorville field located in the Illinois Basin, (2) 16.7 million tons in the Leesville field located in Northern Appalachia, (3) 15.3 million tons in the Bolt field in Central Appalachia and (4) 13.8 million tons in the Springdale field located in Northern Appalachia. These reserves can be developed and produced over time as industry and regional conditions permit. We believe our existing asset base will continue to provide attractive internal growth projects.

For the year ended December 31, 2007, we generated revenues of approximately $403.5 million and net income of approximately $30.7 million. For the six months ended June 30, 2008, we generated revenues of approximately $223.0 million and net income of approximately $18.2 million. As of August 7, 2008, we had sales commitments for approximately 99%, 77% and 36% of our estimated coal production of approximately 8.6 million tons (including purchased coal to supplement our production), 8.7 million tons and 9.2 million tons for the years ending December 31, 2008, 2009 and 2010, respectively.

The following table summarizes our coal operations and reserves by region:

	Production for the		As of October 31, 2007(1)
Region	Year Ended December 31, 2007	Six Months Ended June 30, 2008	Proven & Probable Reserves	Average Heat Value	Average Sulfur Content	Type of Mines	Steam / Metallurgical Reserves	Transportation(2)
	(in million tons)		(in million tons)	(Btu/lb)	(%)		(in million tons)
Central Appalachia
Tug River Complex (KY, WV)	2.3	1.0	36.3	12,808	1.23	Underground and Surface	32.8/3.5	Truck, Barge, Rail (NS)
Rob Fork Complex (KY)	3.3	1.6	34.5	13,341	1.13	Underground and Surface	25.7/8.8	Truck, Barge, Rail (CSX)
Deane Complex (KY)(1)	n/a	0.2	7.2	13,196	1.55	Underground	7.2/—	Rail (CSX)
Eagle Complex (WV)(1)(3)	n/a	—	5.8	n/a	n/a	Underground	—/5.8	Truck, Rail (NS) (CSX)
Bolt Field (WV)(1)(3)	n/a	—	15.3	14,094	0.57	Underground	—/15.3	Rail (CSX)
Northern Appalachia
Hopedale Complex (OH)	1.3	0.8	17.1	13,026	2.18	Underground	17.1/—	Truck, Barge, Rail (OHC)
Sands Hill Complex (OH)(1)	<0.1	0.3	11.4	11,830	3.59	Surface	11.4/—	Truck, Barge
Leesville Field (OH)	—	—	16.7	13,152	2.21	Underground	16.7/—	Rail (OHC)
Springdale Field (PA)	—	—	13.8	13,443	1.72	Underground	13.8/—	Barge
Illinois Basin
Taylorville Field (IL)	—	—	102.4	12,084	3.83	Underground	102.4/—	Rail (NS)
Western Bituminous
McClane Canyon Mine (CO)	0.2	0.1	1.5	11,522	0.57	Underground	1.5/—	Truck

Total	7.1	4.0	262.0

(1): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, which is as of February 15, 2008; the Sands Hill mining complex is as of the acquisition date, December 14, 2007; and the Eagle mining complex is as of the acquisition date, May 13, 2008. Average heat value and average sulfur content for the Eagle mining complex are currently unavailable.
(2): NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad
(3): Owned by a joint venture in which we have a 51% membership interest and serve as the manager.

Business Strategies

Our primary business objective is to enhance stockholder value by continuing to execute the following strategies:

•: Maximize profitability. We intend to maximize profitability by focusing on (1) improving the efficiency of our operations, (2) maximizing our revenue, including by entering into short-term and longer-term sales commitments with third parties that have a strong credit profile and (3) managing our costs. We continually maintain our equipment and monitor our reserve plans to ensure we are prudently producing the maximum quantity of high quality coal from our mines. We have sales commitments for the majority of our estimated coal production for 2008 and 2009. We believe our short-term and longer-term sales commitments provide us with a reliable revenue base in the near term, while at the same time our uncommitted position enables us to sell coal in the current strong coal pricing market environment. We will also continue to manage our cost structure, which will include further vertical integration of substantially all of our trucking, reclamation, drilling and blasting activities.

•: Grow our business through internal development opportunities. A significant portion of our proven and probable coal reserves and our non-reserve coal deposits are located in the vicinity of our existing infrastructure. We believe that such proximity to our existing operations provides a number of opportunities to develop these reserves and non-reserve coal deposits without significant capital expenditures necessary to develop or expand our infrastructure. In addition, our existing base of proven and probable coal reserves includes development opportunities that will involve infrastructure development such as our joint venture's Bolt field in West Virginia (15.3 million tons in proven and probable coal reserves), our Leesville field in Ohio (16.7 million tons in proven and probable coal reserves), our Springdale field in Pennsylvania (13.8 million tons in proven and probable coal reserves) and our Taylorville field in Illinois (102.4 million tons in proven and probable coal reserves). We have and will continue to maintain an aggressive program of systematically exploring the development of our proven and probable coal reserves as well as our non-reserve coal deposits, including the acquisition of necessary mining rights, and to deploy capital necessary to develop these coal reserves and non-reserve coal deposits to take advantage of internal development opportunities.
•: Selectively expand our operations through strategic acquisitions. Since our predecessor's inception in April 2003, we have grown through a series of strategic acquisitions of mining operations, reserves and infrastructure. We will continue to pursue strategic and accretive acquisitions of such assets both within our existing areas of operations and in new geographic areas. We also intend to further leverage our infrastructure by acquiring coal properties in close proximity to our current operations to (1) extend the lives of our mines, (2) maximize the efficiencies of our coal processing and distribution infrastructure and (3) provide us opportunities for new mine development. In addition, we intend to evaluate selected stable, cash generating coal and non-coal natural resource assets that we have substantial experience in identifying, acquiring at attractive valuations and operating efficiently.
•: Focus on excellence in safety and environmental stewardship. We intend to maintain our recognized leadership in mining in a safe and prudent manner. For the year ended December 31, 2007, our nonfatal days lost incidence rate for our operations was 32.8% below the industry average. For the six months ended June 30, 2008, our nonfatal days lost incidence rate was 19.2% below the industry average. For the year ended December 31, 2007, our operations received 57.4% fewer violations per inspection day than the national average according to the MSHA. We will continue to implement safety measures that are designed to promote safe operating practices and to emphasize environmental stewardship to our employees. We believe our ability to minimize lost-time injuries and environmental violations will increase our operating efficiency which will directly improve our cost structure and financial performance and also bolster employee morale.

Competitive Strengths

We believe the following competitive strengths will enable us to execute our business strategies successfully:

•: We have significant internal expansion opportunities. We believe that our undeveloped proven and probable coal reserves and our non-reserve coal deposits will allow us to significantly expand production on a capital efficient basis through the utilization of our existing infrastructure, as some of these reserves and non-reserve coal deposits are located in close proximity to our existing operations. For example, in 2007 in an effort to supplement and enhance production at our Rob Fork mining complex, we completed development of a new underground metallurgical coal mine. Our investment of approximately $30.0 million included a conveyor belt to transfer coal from the mine portal directly to the preparation plant as well as an extensive entry system to access the main reserve body. The mine produced approximately 650,000 tons of coal for the

year ended December 31, 2007 and approximately 383,000 tons of coal for the six months ended June 30, 2008. We also control or manage proven and probable coal reserves that are currently undeveloped of approximately (1) 102.4 million tons in the Taylorville field located in the Illinois Basin, (2) 16.7 million tons in the Leesville field located in Northern Appalachia, (3) 15.3 million tons in the Bolt field and (4) 13.8 million tons in the Springdale field located in Northern Appalachia. These reserves can be developed and produced over time as industry and regional conditions permit.

•: We have a proven track record of successful acquisitions. Since our predecessor's inception in 2003, we have completed numerous asset acquisitions with a total purchase price of approximately $212.9 million. Through these acquisitions and other coal lease transactions we have significantly increased our proven and probable coal reserves and non-reserve coal deposits. The members of our senior management team have, on average, 24 years of coal industry and related
experience and have a demonstrated track record of acquiring, building and operating coal businesses profitably and safely throughout the United States. The acquisitions consummated by our management team have consisted of high quality coal reserves and union-free operations, with limited reclamation and legacy liabilities. We believe we have a disciplined acquisition strategy that is focused on acquiring selected assets at attractive valuations, while limiting to the extent possible the assumption of debt and reclamation and employee-related liabilities.
•: We have an attractive blend of short-term and longer-term sales contracts as well as uncommitted coal to sell on the spot market. As of August 7, 2008, we had sales commitments for approximately 99%, 77% and 36% of our estimated coal production of approximately 8.6 million tons (including purchased coal to supplement our production), 8.7 million tons and 9.2 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. We believe our short-term and longer-term sales commitments provide us with a reliable revenue base in the near term, while at the same time our uncommitted position enables us to sell coal in the current strong coal pricing market environment.
•: Our mining activities are strategically located. Our mining operations are located near many major power plants and on or near coal-hauling railroads in the eastern United States, including the CSX Rail, the NS Rail and the OHC Rail. Additionally, certain of our mines are located within economical trucking distance to the Big Sandy River and/or the Ohio River where coal can be transported by barge. Cost and availability of transportation are critical marketing factors because our customers generally pay the transportation costs for the delivery of coal, and these costs represent a significant portion of a customer's total cost of delivered coal. We believe the geographic location of our mines and the multiple transportation options available to us provide us with a transportation cost advantage compared to many of our competitors.
•: We offer a variety of high quality steam and metallurgical coal that meet our customers' needs. Our customers and end users, which include electric utilities in the United States and domestic and international steel producers, demand a variety of coal types and characteristics. The majority of our steam coal production in Central Appalachia also meets the specifications of both the OTC and NYMEX markets. In addition, the substantial planned increase in the number of electrical generating plants utilizing pollution control devices has created and we expect will continue to create an expanding market for the coal that we produce in Central and Northern Appalachia.
•: We have vertically integrated many of our operations to control operating costs. We have recently vertically integrated substantially all of our trucking, reclamation and drilling and blasting activities. The integration of these activities has lowered our cost and significantly lessened our dependence on certain third-party service providers. The vertical integration helps us to maintain our low cost structure and maximize profitability.

•: We have a strong credit profile. As a result of our prudent acquisition strategy and conservative financial management, we believe that our capital structure after this offering will provide us significant financial flexibility to pursue our strategic goals, including (1) pursuing acquisitions, (2) investing in our existing operations and (3) managing our operations through periods of difficult coal market conditions. We believe that compared to other publicly traded U.S. coal producers, we have relatively low levels of outstanding debt, legacy liabilities, reclamation liabilities and postretirement employee obligations. In addition, we sell a majority of our coal to a number of customers with an investment-grade credit rating.

Recent Coal Market Conditions and Trends

The coal sector, both globally and in the United States, has recently benefited from favorable market fundamentals. Currently, the global supply and demand balance for coal, as well as the overall increase in prices for commodities such as natural gas and crude oil, has created a strong price environment for coal. Coal prices in certain regions such as Central and Northern Appalachia are at the highest levels experienced in recent history. Certain recent developments, including developments in the eastern United States, that have created the current attractive coal market dynamics are summarized below:

•: Continued strong demand in the United States. Domestic demand for steam coal from the electricity generating sector, continues to be strong, driven principally by growth in electricity sales, which are expected to increase by 34% from 2007 to 2030, as estimated by the EIA;
•: Growing export market. Coal producers in the Appalachian region of the United States are benefiting from growing demand for coal in Europe, Asia and other foreign markets. Total U.S. coal exports increased by approximately 19% from 2006 to 2007, according to the EIA. In particular, exports to Europe and Brazil have increased 30% and 44%, respectively, through December 2007 as compared to the same period in 2006, as reported by the EIA;
•: Proximity of eastern U.S. coal market. Eastern U.S. coal producers are also positioned to capitalize on the current favorable export market given their geographical proximity. Eastern U.S. coal producers have access to multiple modes of transportation within the United States, but are also located close to the coast, which provides access to transoceanic shipments. The total cost to purchase and ship coal from the East Coast of the United States to Europe is currently competitive with other coal exporting regions, as freight rates from the Pacific coal supply regions have increased significantly in recent months. Shipping costs from the eastern United States to western Europe, as measured by the Panamax Coal Voyage Spot Rates from Hampton Roads (VA) to the ARA (Antwerp-Rotterdam-Amsterdam) 70,000t, have ranged between $18.56 and $43.23 per ton since 2007;
•: U.S. transportation logistics. Constraints in the U.S. transportation system continue to persist. In particular, rail bottlenecks and rail maintenance downtime in the western United States have limited the coal produced in those regions, such as the Powder River Basin, from being transported and sold in the eastern end use markets;
•: Decline in production and reserve levels. Coal production in the eastern United States continues to decline. Based on the EIA's reported data for 2007 and reported data for 2006, production in the Appalachian region decreased 4% from 391.2 million tons in 2006 to 377.1 million tons in 2007. Not only has production declined, but coal reserves also continue to decline in the eastern United States regions. According to the EIA, as of December 31, 2006, total coal reserves in the

Central Appalachia region are estimated to be 2,486 million tons, which is approximately 0.3% lower than the estimated 2,494 million tons at December 31, 2005; and

•: High prices for alternative energy sources. Coal continues to be the lowest cost source of energy relative to its substitutes. Spot prices as of June 30, 2008 for Henry Hub natural gas and New York Harbor No. 2 heating oil were $13.19 per million Btu and $3.90 per gallon or $28.15 per million Btu, respectively, as reported by Bloomberg L.P. and the EIA. On the other hand, Central Appalachian spot coal prices, as measured by Big Sandy Barge 12,500 Btu, <3.0 lb SO2 / MMBtu prices, reached $133.50 per ton on June 30, 2008, representing $5.34 per million Btu.

The coal sector has become increasingly global in nature, and as a result, events in certain regions of the world are impacting market dynamics across the globe, including in the eastern United States. Below is a list of certain developments around the world that are impacting the coal sector:

•: Demand for coal by emerging global economies, in particular China and India, continues to increase.
•: Traditional exporters of coal to Asia and other regions around the world are challenged to meet the growing demand for coal, which is creating export opportunities for other coal producers, particularly those located in the eastern United States.
•: The continued weakness of the U.S. dollar is also improving the competitiveness of U.S. exports.
•: Coal supply curtailment in Australia is causing Asian countries dependent on Australian coal to source coal from other places.

We expect near-term growth in U.S. coal consumption to be driven by greater utilization at existing coal-fired electricity generating plants, and we expect longer-term growth in U.S. coal consumption to be driven by the construction of new coal-fired plants. These factors, coupled with the declining coal reserves and production levels in the United States, particularly in the eastern United States, have contributed to the recent escalation in coal prices, particularly those in the eastern United States, and we expect these attractive sector fundamentals to continue into the future.

Summary of Risk Factors

An investment in our common stock involves risks. Those risks are described under the caption "Risk Factors" beginning on page 18 and include, among others:

•: A decline in coal prices could adversely affect our results of operations.
•: Our mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.
•: Our mining operations are subject to operating risks that are beyond our control and could adversely affect production levels and increase costs.
•: 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.
•: A shortage of skilled labor, together with rising labor costs in the mining industry, has increased and may further increase operating costs, which could adversely affect our results of operations.
•: Unexpected increases in raw material costs could adversely affect our results of operations.
•: We may be unable to obtain and/or renew permits necessary for our operations, which could prevent us from mining certain reserves.

•: Our sponsor, Wexford, may compete with us.
•: We will be controlled by Wexford as long as they own or control a majority of our common stock, and they may make decisions with which you disagree.
•: The New York Stock Exchange does not require a controlled company like us to comply with some of its listing requirements with respect to corporate governance requirements.
•: We will incur increased costs as a result of being a publicly traded corporation.

Transactions and Organizational Structure

Our sponsor is Wexford Capital LLC ("Wexford"), a Securities and Exchange Commission ("SEC") registered investment advisor with approximately $7.0 billion of assets under management. In connection with this offering, Rhino Energy Holdings LLC, an entity owned by certain investment funds managed by Wexford ("Wexford Funds"), and certain Wexford Funds will contribute 100% of the ownership interests in Rhino Energy LLC to us in exchange for an aggregate of shares of our common stock. The Wexford Funds will then contribute their shares of our common stock to Rhino Energy Holdings LLC in exchange for ownership interests in Rhino Energy Holdings LLC.

We will issue shares of our common stock, representing % of our outstanding common stock to the public in this offering. Rhino Energy Holdings LLC, as the selling stockholder, will sell shares of our common stock, representing % of our outstanding common stock, to the public in this offering.

In connection with the closing of this offering, we will issue approximately shares of restricted stock and shares of unrestricted stock to management under our long-term incentive plan.

After this offering, Rhino Energy Holdings LLC will own approximately % and the public will own approximately % of our outstanding common stock.

Certain of our directors are partners of Wexford (collectively, the "Wexford Partners"). Please read "Certain Relationships and Related Party Transactions" for additional information.

The following are simplified diagrams of our organizational structure before and after this offering.

Pre-Offering

(1): Each of the Wexford Funds is beneficially owned by Wexford. Please read "Security Ownership of Certain Beneficial Owners, Management and the Selling Stockholder" for more information on the beneficial ownership of Wexford.
(2): Certain of our directors are Wexford Partners. Please read "Certain Relationships and Related Party Transactions—Ownership Interests of Rhino Energy Holdings LLC, Wexford Funds and the Wexford Partners."
(3): Includes a joint venture in which Rhino Energy LLC indirectly owns a 51% membership interest.

Post-Offering⁽¹⁾

Shares issued and outstanding:
	Shares held by the public		%
	Shares held by Rhino Energy Holdings LLC		%
	Shares issued to management under our long-term incentive plan		%

		100.0	%

(1): The diagram does not include the shares of unrestricted stock or the shares of restricted stock to be held by management, which will be issued under our long-term incentive plan.
(2): Each of the Wexford Funds is beneficially owned by Wexford. Please read "Security Ownership of Certain Beneficial Owners, Management and the Selling Stockholder" for more information on the beneficial ownership of Wexford.
(3): Certain of our directors are Wexford Partners. Please read "Certain Relationships and Related Party Transactions—Ownership Interests of Rhino Energy Holdings LLC, Wexford Funds and the Wexford Partners."
(4): Includes a joint venture in which Rhino Energy LLC indirectly owns a 51% membership interest.

Principal Executive Offices

Our principal executive offices are located at 424 Lewis Hargett Circle, Suite 250, Lexington, Kentucky. Our phone number is (859) 389-6500. Our website will be located at http://www.rhinoresources.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

The Offering

Common stock offered by us		shares.
Common stock offered by the selling stockholder		shares.
		shares, if the underwriters exercise their option to purchase additional shares in full.
Total common stock offered to the public		shares.
		shares, if the underwriters exercise their option to purchase additional shares in full.
Common stock outstanding after this offering(1)		shares.
Use of proceeds		We estimate that the net proceeds to us from this offering (based on an assumed initial offering price of $ per share), after deducting the estimated underwriting discount and offering expenses payable by us, will be approximately $ million. We intend to use all of the net proceeds to repay outstanding indebtedness under our credit facility, a portion of which was used to finance the acquisitions of the Sands Hill and Deane mining complexes and our investment in the joint venture that acquired the Eagle mining complex and the Bolt field, leaving approximately $ million of outstanding indebtedness under our credit facility and approximately $ million of total indebtedness, on a pro forma basis as of June 30, 2008. Please read "Use of Proceeds" for more information.
		We will not receive any of the proceeds from the sale of shares by Rhino Energy Holdings LLC, including from any exercise of the underwriters' option to purchase additional shares. Certain of our directors are Wexford Partners and, accordingly, may indirectly receive proceeds received by Rhino Energy Holdings LLC from its sale of our common stock in this offering. Please read "Use of Proceeds," "Security Ownership of Certain Beneficial Owners, Management and the Selling Stockholder" and "Certain Relationships and Related Party Transactions" for more information.
Dividend policy		We expect to commence a policy of paying quarterly dividends, initially at an annual rate of between $ and $ per share, to the holders of our common stock. Please read "Dividend Policy" for more information.
New York Stock Exchange symbol		RNO

(1): The number of shares of our common stock outstanding after this offering includes unrestricted shares to be issued to management in connection with the closing of this offering but excludes (a) restricted shares to be issued to management in connection with the closing of this offering and (b) the number of shares equal to % of the outstanding common stock on the closing of this offering reserved for issuance under our long-term incentive plan. Please read "Management—Long-Term Incentive Plan."

Summary Historical and Pro Forma Consolidated Financial and Operating Data

The following table presents summary historical consolidated financial and operating data of our predecessor, Rhino Energy LLC, as of the dates and for the periods indicated. The summary historical consolidated financial data presented as of March 31, 2006 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are not included in this prospectus. The summary historical consolidated financial data presented as of December 31, 2006 and 2007 and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. The summary historical consolidated financial data presented as of June 30, 2008 and for the six months ended June 30, 2007 and 2008 is derived from the unaudited historical condensed consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. The summary historical consolidated financial data presented as of June 30, 2007 is derived from our predecessor's accounting records, which are unaudited. Effective April 1, 2006, Rhino Energy LLC changed its fiscal year end from March 31 to December 31.

The summary pro forma consolidated financial data presented for the year ended December 31, 2007 and as of and for the six months ended June 30, 2008 is derived from our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma consolidated financial statements give pro forma effect to:

•: the contribution by Rhino Energy Holdings LLC and certain Wexford Funds of 100% of the ownership interests in Rhino Energy LLC to us in exchange for an aggregate of shares of our common stock;
•: the issuance by us to the public of shares of our common stock;
•: the issuance by us to management of shares of restricted stock and shares of unrestricted stock issued under our long-term incentive plan;
•: the use of the net proceeds from this offering as described under "Use of Proceeds;" and
•: the provision for income taxes under our corporate holding company structure.

The unaudited pro forma consolidated balance sheet assumes the items listed above occurred as of June 30, 2008. The unaudited pro forma consolidated statements of operations data for the year ended December 31, 2007 and the six months ended June 30, 2008 assume the items listed above occurred as of January 1, 2007. We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $3.0 million that we expect to incur as a result of being a publicly traded corporation.

For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with "Use of Proceeds," "Business—Our History," the historical consolidated financial statements of Rhino Energy LLC and our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.

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 means earnings before interest, taxes, depreciation, depletion and amortization. This measure is not calculated or presented in accordance with generally accepted accounting principles ("GAAP"). We explain this

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

		Rhino Energy LLC Historical Consolidated															Rhino Resources, Inc. Pro Forma Consolidated
					Nine Months Ended December 31, 2006						Six Months Ended June 30,							Six Months Ended June 30, 2008
		Year Ended March 31, 2006						Year Ended December 31, 2007			Six Months Ended June 30,						Year Ended December 31, 2007
		Year Ended March 31, 2006						Year Ended December 31, 2007			2007			2008			Year Ended December 31, 2007
		(in thousands, except per share and per ton data)
Statement of Operations Data:
Total revenues		$	363,959.9		$	300,838.5		$	403,451.8		$	193,501.0		$	223,019.1		$	$
Costs and expenses:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		291,444.7			238,189.7			318,520.6			152,408.2			172,489.9
	Freight and handling costs		6,342.5			2,768.1			4,020.7			956.6			4,132.2
	Depreciation, depletion and amortization		13,744.3			28,471.2			30,749.8			14,326.4			17,247.4
	Selling, general and administrative		17,129.4			18,573.0			15,370.3			7,146.6			8,814.6
	(Gain) loss on sale of assets		(377.2	)		745.8			(944.3	)		(797.6	)		(376.2	)
	(Gain) loss on retirement of advance royalties		(236.9	)		2,994.6			(115.3	)		(125.3	)		8.0

Income from operations			35,913.1			9,096.1			35,850.0			19,586.1			20,703.2
Interest and other income (expense):
	Interest expense		(4,976.2	)		(6,498.0	)		(5,579.2	)		(3,121.6	)		(2,557.2	)
	Interest income		412.1			311.7			316.7			185.3			100.6
	Other—net		490.7			272.2			—			—			—

Total interest and other income (expense)			(4,073.4	)		(5,914.1	)		(5,262.5	)		(2,936.3	)		(2,456.6	)
Income tax expense (benefit)(1)			178.4			124.6			(126.3	)		(119.5	)		—
Equity in net income (loss) of unconsolidated affiliate			—			—			—			—			(38.5	)

Net income		$	31,661.3		$	3,057.4		$	30,713.8		$	16,769.3		$	18,208.1
Other comprehensive income (loss):
	Change in actuarial gain/(loss) under SFAS No. 158		—			(901.0	)		1,489.4			—			—

Net comprehensive income		$	31,661.3		$	2,156.4		$	32,203.2		$	16,769.3		$	18,208.1

Pro forma earnings per share, basic
Pro forma earnings per share, diluted
Pro forma weighted average number of shares outstanding, basic
Pro forma weighted average number of shares outstanding, diluted
Statement of Cash Flows Data:
Net cash provided by (used in):
	Operating activities	$	32,892.0		$	36,859.5		$	52,492.5		$	26,913.4		$	45,352.1		$	$
	Investing activities	$	(34,612.6	)	$	(28,827.6	)	$	(28,097.6	)	$	(2,941.9	)	$	(53,154.5	)
	Financing activities	$	(1,886.9	)	$	(9,140.8	)	$	(21,191.5	)	$	(21,320.3	)	$	5,372.1

Other Financial Data:
EBITDA(2)	$	50,560.2	$	38,151.2	$	66,916.5	$	34,097.8	$	38,012.7	$	$
Total capital expenditures(3)	$	66,373.3	$	42,393.4	$	39,738.1	$	11,041.7	$	41,910.9	$	$
Balance Sheet Data (at period end):
Cash and cash equivalents	$	1,488.8	$	380.0	$	3,583.4	$	3,031.1	$	1,153.1		$
Property and equipment, net	$	180,267.0	$	197,056.1	$	211,657.1	$	195,460.8	$	250,207.4		$
Total assets	$	246,759.3	$	248,194.5	$	275,992.2	$	253,415.2	$	325,643.7		$
Total liabilities	$	154,028.4	$	153,307.1	$	158,151.7	$	140,588.5	$	190,063.6		$
Total debt	$	87,764.1	$	88,570.5	$	83,953.7	$	72,830.9	$	90,328.6		$
Members'/stockholders' equity	$	92,730.9	$	94,887.4	$	117,840.5	$	112,826.7	$	135,580.1		$
Operating Data:
Tons of coal sold		7,900.3		6,222.9		8,159.0		3,976.6		4,188.3
Tons of coal produced		7,950.1		6,182.0		7,056.6		3,503.8		3,971.1
Coal revenues per ton(4)	$	44.48	$	47.31	$	48.30	$	47.85	$	50.43
Cost of operations per ton(5)	$	36.89	$	38.28	$	39.04	$	38.33	$	41.18

(1)

A pro forma provision for income taxes at statutory rates has been made in the financial statements on the assumption that Rhino Energy LLC was a taxable entity for the respective periods. As an entity treated as a partnership for income tax purposes, Rhino Energy LLC's taxable income was included in its members' income tax returns whereas Rhino Resources, Inc. will be subject to income taxes as a corporation.

(2)

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

•: our compliance with certain financial covenants included in our debt agreements;
•: our financial performance without regard to financing methods, capital structure or income taxes;
•: our ability to generate cash sufficient to pay interest on our indebtedness; and
•: the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

We are not contractually, legally or otherwise prohibited from using EBITDA for these purposes. 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, and these measures may vary among other companies. Therefore, 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 GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

		Rhino Energy LLC Historical Consolidated												Rhino Resources, Inc. Pro Forma Consolidated
									Six Months Ended June 30,					Rhino Resources, Inc. Pro Forma Consolidated
				Nine Months Ended December 31, 2006											Six Months Ended June 30, 2008
		Year Ended March 31, 2006				Year Ended December 31, 2007								Year Ended December 31, 2007
		Year Ended March 31, 2006				Year Ended December 31, 2007			2007			2008		Year Ended December 31, 2007
		(in thousands)
Reconciliation of EBITDA to net income:
Net income		$	31,661.3	$	3,057.4	$	30,713.8		$	16,769.3		$	18,208.1	$	$
Plus:
	Depreciation, depletion and amortization		13,744.3		28,471.2		30,749.8			14,326.4			17,247.4
	Interest expense		4,976.2		6,498.0		5,579.2			3,121.6			2,557.2
	Income tax expense (benefit)		178.4		124.6		(126.3	)		(119.5	)		—

EBITDA		$	50,560.2	$	38,151.2	$	66,916.5		$	34,097.8		$	38,012.7	$	$

Reconciliation of EBITDA to net cash provided by operating activities:
Net cash provided by operating activities		$	32,892.0	$	36,859.5	$	52,492.5		$	26,913.4		$	45,352.1	$	$
Plus:
	Increase in net operating assets		16,447.4		892.7		10,552.7			4,754.7			—
	Decrease in provision for doubtful accounts		—		282.8		175.2			—			—
	Gain on sale of assets		377.2		—		944.3			797.6			376.2
	Gain on retirement of advance royalties		236.9		—		115.3			125.3			—
	Interest expense		4,976.2		6,498.0		5,579.2			3,121.6			2,557.2
	Income tax expense		178.4		124.6		—			—			—
Less:
	Decrease in net operating assets		—		—		—			—			8,609.8
	Accretion on interest-free debt		321.2		255.1		359.8			177.0			282.8
	Amortization of advance royalties		2,186.8		1,098.5		699.7			441.3			115.7
	Increase in provision for doubtful accounts		354.4		—		—			—			—
	Equity in net loss of unconsolidated affiliate		—		—		—			—			38.5
	Loss on sale of assets		—		745.8		—			—			—
	Loss on retirement of advance royalties		—		2,994.6		—			—			8.0
	Income tax benefit		—		—		126.3			119.5			—
	Accretion on asset retirement obligations		1,685.5		1,412.4		1,756.9			877.0			1,218.0

EBITDA		$	50,560.2	$	38,151.2	$	66,916.5		$	34,097.8		$	38,012.7	$	$

(3): 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:

		Rhino Energy LLC Historical Consolidated
								Six Months Ended June 30,
				Nine Months Ended December 31, 2006
		Year Ended March 31, 2006				Year Ended December 31, 2007
		Year Ended March 31, 2006				Year Ended December 31, 2007		2007		2008
		(in thousands)
Reconciliation of total capital expenditures to net cash used for capital expenditures:
Additions to property, plant and equipment		$	31,485.5	$	32,701.3	$	14,598.7	$	5,638.0	$	26,989.8
Acquisitions of coal companies and coal properties			5,000.0		—		18,174.5		—		14,669.7

Net cash used for capital expenditures			36,485.5		32,701.3		32,773.2		5,638.0		41,659.5
Plus:
	Additions to property, plant and equipment financed through long-term borrowing		29,887.8		9,692.1		6,964.9		5,403.7		251.4

Total capital expenditures		$	66,373.3	$	42,393.4	$	39,738.1	$	11,041.7	$	41,910.9

(4): 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.
(5): 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.

RISK FACTORS

Investing in our common stock involves a high degree of risk. You should carefully consider the following risk factors, together with the other information contained in this prospectus, before investing in our common stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of our common stock could decline and you may lose all or part of your investment.

Risks Related to Our Business

A decline in coal prices could adversely affect our results of operations.

Our results of operations are dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. Declines in the prices we receive for our coal could adversely affect our results of operations. The prices we receive for coal depend upon factors beyond our control, including:

•: the price elasticity of supply;
•: the demand for electricity;
•: the demand for steel and the continued financial viability of the steel industry;
•: the supply of foreign coal;
•: the proximity to and the capacity and cost of transportation facilities;
•: governmental regulations and taxes;
•: air emission standards for coal-fired power plants;
•: regulatory, administrative and judicial decisions, including legislation to allow retail price competition in the electric utility industry;
•: the price and availability of alternative fuels, including the effects of technological developments; and
•: the effect of worldwide energy conservation measures.

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

We are subject to numerous and detailed federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air quality standards, water pollution, waste management, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Moreover, the possibility exists that new laws or regulations (or judicial interpretations of existing laws and regulations) may be adopted in the future that could materially affect our mining operations and results of operations, either through direct impacts such as new requirements impacting our existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit our customers' use of coal.

Mining accidents in the past several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these

states and the federal government have included increased sanctions for non-compliance. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices.

Complying with these state and federal laws and regulations could adversely affect our results of operations and financial position and could result in harsher sanctions being applied in the event of any violations. Please read "Business—Regulation and Laws."

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

Our mining operations are subject to conditions or events beyond our control that could disrupt operations, resulting in decreased production levels, and affect the cost of mining at particular mines for varying lengths of time. These risks include:

•: unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
•: poor mining conditions resulting from geological conditions or the effects of prior mining;
•: inability to acquire or maintain necessary permits or mining or surface rights;
•: changes in governmental regulation of the mining industry or the electric utility industry;
•: adverse weather conditions and natural disasters;
•: accidental mine water flooding;
•: labor-related interruptions;
•: interruptions due to transportation delays;
•: mining and processing equipment unavailability and failures and unexpected maintenance problems; and
•: accidents, including fire and explosions from methane.

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

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.

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 source of energy 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 parts of the country. For instance, coordination of the many eastern U.S. 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. The increased competition could have an adverse effect on our results of operations.

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

A shortage of skilled labor, together with rising labor costs in the mining industry, has increased and may further increase operating costs, which could adversely affect our results of operations.

Efficient mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In the event the shortage of

experienced labor continues or worsens or we are unable to train the necessary number of skilled laborers, there could be an adverse impact on our labor productivity and costs and our ability to expand production, which could have an adverse effect on our results of operations.

As a result of current market conditions and the high demand for skilled labor in the regions in which we operate, we are experiencing a record level of labor costs. If coal prices decrease in the future and labor costs are not reduced commensurately, our results of operations could be adversely affected.

Unexpected increases in raw material costs could adversely affect our results of operations.

Our coal mining operations use significant amounts of steel, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room and pillar method of mining. Historically, the prices of scrap steel and petroleum have fluctuated. There may be acts of nature or terrorist attacks or threats that could also increase the costs of raw materials. If the price of steel, petroleum products or other of these materials continue to increase, our cost of operations will increase, which could adversely affect our results of operations.

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

Mining companies must obtain numerous permits that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required for our operations may not be issued, maintained or renewed, may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct mining operations due to the inability to obtain or renew necessary permits could reduce our production and prevent us from mining certain reserves. Please read "Business—Regulation and Laws—Mining Permits and Approvals."

Individual or general permits under Section 404 of the federal Clean Water Act ("CWA") are required to discharge dredged or fill material into waters of the United States. Surface coal mining operators obtain such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. The U.S. Army Corps of Engineers ("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. Nationwide Permit 21 authorizes the disposal of dredged or fill material from mining activities into the waters of the United States. Individual CWA Section 404 permits for valley fill surface mining activities, which we also currently utilize, are subject to legal uncertainties. On March 23, 2007, the U.S. District Court for the Southern District of West Virginia rescinded several individual CWA Section 404 permits issued to other mining operations based on a finding that the Corps issued the permits in violation of the CWA and National Environmental Policy Act. This decision is currently on appeal to the U.S. Court of Appeals for the Fourth Circuit. Please read "Business—Regulation and Laws—Clean Water Act" for a discussion of recent litigation related to the CWA. An inability to conduct our mining operations pursuant to applicable permits would reduce our production and results of operations.

If we are not able to acquire replacement coal reserves that can be developed or acquired at competitive costs, our results of operations could be adversely affected.

Our results of operations depend substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because our reserves decline as we mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. 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. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. 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. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

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

We base our coal reserve estimates and non-reserve coal deposit information on engineering, economic and geological data assembled and analyzed by our staff, which includes various engineers and geologists, and which is periodically reviewed by outside firms. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are annually updated to reflect the production of coal from the reserves and new drilling or other data received. There are numerous uncertainties 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 such as:

•: geological and mining conditions and/or effects from prior mining that may not be fully identified by available exploration data or which may differ from experience, in current operations;
•: the assumed effects of regulation, including the issuance of required permits, and taxes by governmental agencies and assumptions concerning coal prices, operating costs, mining technology improvements, severance and excise tax, development costs and reclamation costs;
•: historical production from the area compared with production from other similar producing areas; and
•: assumptions concerning future coal prices, operating costs, capital expenditures, severance taxes and development and reclamation costs.

For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery are expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. Actual coal tonnage recovered from identified coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures with respect to the same may vary materially from estimates. These estimates, thus, may not accurately reflect our actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs.

If we are unable to acquire other attractive natural resource assets or are unable to successfully manage or grow these assets once we acquire them, our financial position and results of operations may be adversely affected.

One of our business strategies is to identify and acquire selected, attractive natural resource assets in which we have substantial experience and where we may have a strategic advantage. However:

•: we cannot be certain that we will be able to identify other attractive natural resource assets or will be successful in acquiring these assets at attractive prices, and this may reduce our growth;

•: the price of natural resources in which we acquire assets in the future may decline; and
•: we may not be able to operate these natural resource assets in a profitable manner.

Our acquisition strategy involves risks that could adversely affect our results of operations.

Even if we consummate acquisitions that we believe will be accretive, they may not enhance our financial position or results of operations. Any acquisition involves potential risks, including:

•: performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;
•: a significant increase in our indebtedness and working capital requirements;
•: the inability to timely and effectively integrate the operations of recently acquired businesses or assets, particularly those in new geographic areas or in new lines of business;
•: the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition, for which we are not indemnified or for which the indemnity is inadequate;
•: customer or key employee loss from the acquired businesses; and
•: diversion of our management's attention from other business concerns.

We recently entered into a joint venture that acquired the Eagle mining complex, a metallurgical coal operation requiring rehabilitation before production can resume. The time and expense involved with refurbishing and staffing this operation may exceed our expectations, which could adversely affect our financial position and results of operations.

Mining is a capital-intensive business, and the inability to fund necessary or desirable capital expenditures could have an adverse effect on our growth and profitability.

Mining is a capital-intensive business. We anticipate making significant capital expenditures over the next several years in connection with the development of new projects such as our joint venture's Eagle mining complex. Costs associated with capital expenditures have escalated on an industry-wide basis over the last several years, largely as a result of factors beyond our control such as increases in the price of steel, petroleum products and other raw materials. If costs associated with capital expenditures continue to increase, we could have difficulty funding or be unable to fund needed or planned capital expenditures, which would limit the expansion of our production or our ability to sustain our existing operations at optimal levels. Increased costs for capital expenditures could also have an adverse effect on the profitability of our existing operations and returns from our new projects.

Extensive environmental laws and regulations affect coal consumers, which has corresponding effects on the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations.

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 have affected demand and prices for our higher sulfur coal. Please read "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 actively 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. Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the U.S. Environmental Protection Agency ("EPA") may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) under the federal Clean Air Act ("CAA") even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under CAA's definition of "air pollutant" may also result in future regulation of greenhouse gas emissions from stationary sources under certain CAA programs.

The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental organizations for concerns related to greenhouse gas emissions from the new plants. In October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant's projected emissions of carbon dioxide. Other state regulatory authorities have also rejected the construction of new coal-fired 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-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. Please read "Business—Regulation and Laws—Carbon Dioxide Emissions."

Federal and state laws require bonds to secure our obligations related to the statutory requirement that we 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.

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 "reclaim") and to satisfy other miscellaneous obligations. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:

•: the lack of availability, higher expense or unreasonable terms of new surety bonds;
•: the ability of current and future surety bond issuers to increase required collateral; and
•: the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. Our inability to acquire or failure to maintain these bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations.

If a substantial portion of our supply contracts terminate and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations could be adversely affected.

We sell a material portion of our coal under supply contracts. As of August 7, 2008, we had sales commitments for approximately 99%, 77% and 36% of our estimated coal production of approximately 8.6 million tons (including purchased coal to supplement our production), 8.7 million tons and 9.2 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. When our current contracts with customers expire, our customers may decide not to extend or enter into new long-term contracts. As of June 30, 2008, coal supply contracts accounting for 25% of our sales commitments expire in the second half of 2008, contracts accounting for 40% of our sales commitments expire in 2009 and contracts accounting for 35% of our sales commitments expire in 2010 and beyond. 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. Our current long-term contracts could be renegotiated on terms less favorable to us. If a substantial portion of our supply contracts terminate and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations could be adversely affected. For additional information relating to these contracts, please read "Business—Customers—Coal Supply Contracts."

Reduced coal consumption by North American electric power generators could result in lower prices for our coal which could adversely affect our results of operations.

Steam coal accounted for 97% of our coal sales volume for the year ended December 31, 2007 and 88% of our coal sales volume for the six months ended June 30, 2008. The majority of our sales of steam coal for the year ended December 31, 2007 and for the six months ended June 30, 2008 were to electric utilities and affiliates. According to the U.S. Department of Energy's Energy Information Administration ("EIA"), domestic electric power generation accounted for 88% of all U.S. coal consumption for 2007. The amount of coal consumed for U.S. electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power, technological developments, and environmental and other governmental regulations.

Weather patterns can also affect electricity generation. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the lowest-cost sources of power generation when deciding which generation sources to dispatch. Accordingly, significant changes in weather patterns could reduce the demand for our coal.

Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand. Any downward pressure on coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise could adversely affect our results of operations.

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 reopener" and other similar provisions in long-term supply agreements may reduce the protection from short-term coal price volatility traditionally provided by such contracts. As of June 30, 2008, two of our long-term coal supply contracts (those with terms longer than one year), which together account for sales of approximately 20% of our estimated annual coal production through 2010, contained provisions that allow for the purchase price to be renegotiated at periodic intervals. This price reopener provision requires the parties to agree on a new price. Failure of the parties to agree on a price under a price reopener 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. Accordingly, long-term coal supply contracts may provide only limited protection during adverse market conditions.

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, in the extreme, termination of the contracts. In addition, certain of our supply contracts permit the customer to terminate the contract in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit.

We depend on a few customers for a significant portion of our revenues, the loss of any of which would adversely affect our results of operations.

We derived 91% of our revenues from coal sales to affiliates of our ten largest customers for the year ended December 31, 2007, with affiliates of our top four customers, Constellation Energy Commodities Group Inc., American Electric Power Company Inc., Progress Energy Inc. and Duke Energy Corp. accounting for 68% of our revenues for that period. For the six months ended June 30, 2008, we derived 70% of our revenues from coal sales to affiliates of our ten largest customers, with affiliates of our top two customers, Constellation Energy Commodities Group Inc. and American Electric Power Company Inc., accounting for 36% of our revenues for that period. No other customer, including its affiliates, accounted for more than 10% of our revenues for either period. As of June 30, 2008, 62% of our coal supply contracts, including over 28 coal supply agreements with our top ten customers, expire in 2008, 25% in 2009 and 13% in 2010 and beyond, representing 25%, 40% and 35%, respectively, of our total committed tons of coal. Negotiations to extend existing agreements or enter into new long-term agreements 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 agreements, or at all. If any of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our results of operations could be adversely affected.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If there is deterioration of the creditworthiness of electric power generator customers or trading counterparties, our results of operations could be adversely affected. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.

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 utilize contractors to operate certain of our mines. For the year ended December 31, 2007 and the six months ended June 30, 2008, 17% and 15%, respectively, of our coal production was from contractor-operated mines. Disruption in our supply of contractor-produced coal and outside vendors 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 contractors for us. Any increase in the prices we pay for contractor-produced coal could increase our costs and therefore adversely affect our results of operations.

Our results of operations could suffer if our customers reduce or suspend their coal purchases.

Interruption in the purchases by or operations of our principal customers could significantly affect our revenues and profitability. 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 are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

Disputes relating to our coal supply agreements could adversely affect our results of operations.

From time to time, we may have disputes with customers under our coal supply agreements. These disputes could be associated with claims by our customers that may affect our results of operations. Any dispute resulting in litigation could cause us to pay significant legal fees, which could also adversely affect our results of operations.

Changes in the export and import markets for coal products could affect the demand for our coal and our results of operations.

We compete in a worldwide market. The pricing and demand for our products is affected by a number of factors beyond our control. These factors include:

•: currency exchange rates;
•: growth of economic development;
•: global coal supply and demand; and
•: ocean freight rates.

Any decrease in the amount of coal exported from the United States, or any increase in the amount of coal imported into the United States, could have a material adverse impact on the demand for our coal and our results of operations.

Competition within the coal industry may adversely affect our ability to sell coal.

We compete with other large coal producers and many smaller coal producers in various regions of the United States for domestic sales. The industry has experienced increased consolidation. From 1990 to 2006, the top five U.S. coal producers have increased their market share from 22% to over 50% according to Platts Research and Consulting ("Platts"). This consolidation has led to several competitors having significantly larger financial and operating resources than we do. If we are unable to compete effectively, we may lose existing customers or fail to attract new customers, which could have an adverse affect on our results of operations.

In addition, a decrease in demand for coal caused by any number of factors could cause competition among coal producers to intensify, potentially resulting in additional downward pressure on domestic coal prices and adversely affecting our results of operations.

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

We conduct a significant part of our mining operations on properties that we lease. 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 properties and leasehold interests in our leased properties and 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 if defects in title or boundaries exist or if a lease expires. Any challenge to our title or 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 such 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 work force could become unionized in the future, which could adversely affect our production 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 currently union-free work force were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mines. In addition, even if we remain union-free, our operations may still be adversely affected by work stoppages at unionized companies.

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. 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 ("SMCRA") and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep 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.

We are a holding company with no operations of our own and depend on our subsidiaries for cash.

Because our operations are conducted through our subsidiaries, our ability to make payments on our indebtedness and pay dividends, if any, to our stockholders is dependent on the earnings and the distribution of funds from our subsidiaries. Future financing arrangements of our subsidiaries, such as project financing, may significantly restrict or prohibit our subsidiaries from paying dividends or otherwise transferring assets to us.

Due to our lack of asset diversification, adverse developments in the coal industry or in our operating areas could adversely affect our results of operations.

We rely primarily on sales generated from reserves that we control or manage in Central Appalachia and Northern Appalachia. Due to our lack of asset diversification, adverse developments in the coal industry or in our operating areas would have a significantly greater impact on our results of operations than if we maintained more diverse assets.

Any terrorist attacks and any global and domestic economic repercussions from terrorist activities and the government's response could adversely affect our results of operations.

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war could adversely affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States, and we could incur additional costs to implement additional security measures. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could adversely affect our results of operations.

Our limestone mining is dependent on our coal mining.

Our current limestone mining is incidental to the coal mining process at our Sands Hill mining complex in southern Ohio, and 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. If we cease our coal mining process at our Sands Hill mining complex, we will cease our limestone mining at the mining complex as well.

The limestone industry is highly regionalized and we may not be able to maintain or increase our market share.

The primary competitive factors in the limestone industry are quality, price, ability to meet customer demand, proximity to customers and timeliness of deliveries, with varying emphasis on these factors depending upon the specific product application. To the extent that one or more of our competitors becomes more successful with respect to any key competitive factor, our results of operations or competitive position could be materially adversely affected. Further, the demand for limestone product may decline due to regional economic conditions. Although demand and prices for limestone have been improving in recent years, we are unable to predict future demand and prices, and cannot provide any assurance that current levels of demand and prices will continue or that any future increases in demand or price can be sustained.

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

After this offering, we will continue to have the ability to incur additional debt. Our level of indebtedness could have important consequences to us, including the following:

•: our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
•: covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
•: we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, dividends and future business opportunities;

•: our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally; and
•: our debt level may limit our flexibility in responding to changing business and economic conditions.

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 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.

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

•: incur additional indebtedness or guarantee other indebtedness;
•: grant liens;
•: make certain loans or investments;
•: dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;
•: change the line of business conducted by us or our subsidiaries;
•: enter into a merger, consolidation or make acquisitions; or
•: declare a dividend if an event of default occurs.

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 facility, the lenders could seek to foreclose on such assets.

For more information, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."

Failure to maintain capacity for required letters of credit could limit our ability to obtain or renew surety bonds.

At June 30, 2008, we had $22.8 million of letters of credit in place, of which $20.7 million served as collateral for reclamation surety bonds and $2.1 million secured miscellaneous obligations. Our credit agreement provides for a $200.0 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 mining operations. For more information, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."

Risks Related to This Offering and Our Common Stock

Certain stockholders' shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly.

After this offering, Rhino Energy Holdings LLC will own shares of our outstanding common stock, representing approximately % of our outstanding common stock (or shares, representing approximately % of our outstanding common stock, if the underwriters exercise their option to purchase additional shares in full). The number of shares of common stock available for sale in the public market is limited by restrictions under federal securities law and under lock-up agreements that we, Rhino Energy Holdings LLC and our directors and executive officers have entered into with the underwriters. Those lock-up agreements restrict these persons to offer, sell, dispose of or hedge any shares of our common stock or securities convertible into or exchangeable for shares of our common stock, subject to specified limited exceptions and extensions described elsewhere in this prospectus, during the period continuing through the date that is 180 days (subject to extension) after the date of this prospectus, except with the prior written consent of , on behalf of the underwriters. However, , in its sole discretion on behalf of the underwriters, may release any of the securities subject to these lock-up agreements at any time without notice. These sales might make it difficult or impossible for us to sell additional securities if we need to raise capital. Please read "Underwriting" for a description of these lock-up agreements.

At our request, the underwriters have reserved up to shares, or % of our common stock offered by this prospectus, for sale under a directed share program to our officers, directors and employees. If any of our current directors or executive officers subject to lock-up agreements purchase these reserved shares, the shares will be restricted from sale under the lock-up agreements. If any of these shares are purchased by other persons, such shares will not be subject to lock-up agreements. Please read "Underwriting" for a description of the directed share program.

As restrictions on resale end, our stock price could drop significantly if the holders of these restricted shares sell them or the market perceives they intend to sell them. These sales may also make it more difficult for us to sell securities in the future at a time and at a price we deem appropriate.

Our sponsor, Wexford, may compete with us.

None of Rhino Energy Holdings LLC, Wexford and their affiliates (whether or not they are also a director, officer or employee of Rhino Resources, Inc.) will have any duty to refrain from engaging directly or indirectly in any investments, business activities or lines of business. Through its investment funds, Wexford currently holds substantial interests in other companies in the energy and natural resources sectors. Wexford, 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 may compete with us for investment opportunities and Wexford may own an interest in entities that compete with us. Please read "Description of Our Capital Stock—Corporate Opportunities."

We will be controlled by Wexford as long as they own or control a majority of our common stock, and they may make decisions with which you disagree.

After this offering, Rhino Energy Holdings LLC will own shares of our common stock, representing approximately % of our outstanding common stock (or shares, representing approximately % of our outstanding common stock, if the underwriters exercise their option to

purchase additional shares in full). As a result, Wexford will indirectly control all matters affecting us, including the election of directors as long as they own or control a majority of our common stock. They may make decisions which you and other stockholders will not be able to affect by voting your shares.

We may have conflicts of interest with Wexford, and because of their controlling ownership, we may not be able to resolve these conflicts on an arm's-length basis.

Conflicts of interest may in the future arise between Wexford and us in a number of areas relating to our business and our past and ongoing relationships. Factors that may create a conflict of interest between Wexford and us include the following:

•: Wexford currently holds substantial interests in other companies in the energy and natural resources sectors;
•: Wexford may in the future make significant investments in other energy and natural resources companies that directly compete with us;
•: sales or distributions by Rhino Energy Holdings of all or any portion of its ownership interest in us; and
•: certain of our directors also are directors, managing members or general partners of Wexford and its affiliates.

Wexford is under no obligation to resolve any conflicts that might develop between it and us in a manner that is favorable to us and we cannot guarantee that such conflicts will not result in harmful consequences to our business or future prospects. In addition, Wexford and its affiliates are not obligated to advise us of any investment or business opportunities of which they are aware, and they are not restricted or prohibited from competing with us. We have specifically renounced in our certificate of incorporation any interest or expectancy that Wexford and its affiliates, including its directors and officers, will offer to us any investment or business opportunity of which they are aware.

The New York Stock Exchange does not require a controlled company like us to comply with certain of its corporate governance requirements.

Because we are a controlled company, The New York Stock Exchange does not require us to have a majority of independent directors on our board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, stockholders will not have the same protections afforded to other corporations that are subject to all of The New York Stock Exchange corporate governance requirements.

Provisions in our charter documents and Delaware law may delay or prevent our acquisition by a third party.

We are a Delaware corporation and the anti-takeover provisions of Delaware law impose various barriers to the ability of a third party to acquire control of us, even if a change of control would be beneficial to our existing stockholders. In addition, our certificate of incorporation and bylaws contain provisions that may make it more difficult for a third party to acquire control of us without the approval of our board of directors. These provisions may make it more difficult or expensive for a third party to acquire a majority of our outstanding common stock. Among other things, these provisions:

•: authorize us to issue preferred stock that can be created and issued by the board of directors without prior stockholder approval, except as may be required by applicable rules of The New York Stock Exchange, with rights senior to those of common stock;
•: do not permit cumulative voting in the election of directors, which would otherwise allow less than a majority of stockholders to elect director candidates;

•: require vacancies and newly created directorships on the board of directors to be filled only by a majority of the directors then serving on the board; and
•: establish advance notice requirements for submitting nominations for election to the board of directors and for proposing matters that can be acted upon by stockholders at a meeting.

These provisions also may delay, prevent or deter a merger, acquisition, tender offer, proxy contest or other transaction that might otherwise result in our stockholders' receiving a premium over the market price for their common stock. Please read "Description of Our Capital Stock—Anti-Takeover Effects of Certain Provisions of Delaware Law, the Certificate of Incorporation and the Bylaws."

Stockholders will experience immediate and substantial dilution of $ per share.

The assumed initial public offering price of $ per share exceeds pro forma net tangible book value of $ per share. Stockholders will incur immediate and substantial dilution of $ per share. This dilution results primarily because the assets contributed to us by affiliates of Rhino Energy Holdings LLC are recorded at their historical cost, and not their fair value. Please read "Dilution."

The availability of shares for sale in the future could reduce the market price of our common stock.

In the future, we may issue securities to raise cash for acquisitions. We may also acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We may also issue securities convertible into our common stock. Any of these events may dilute your ownership interest in our company and have an adverse impact on the price of our common stock.

In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.

There is no existing market for our common stock, and a trading market that will provide our stockholders with adequate liquidity may not develop. The price of our common stock may fluctuate significantly, and stockholders could lose all or part of their investment.

Prior to the offering, there has been no public market for our common stock. Furthermore, because Rhino Energy Holdings LLC will own approximately % of our common stock immediately following this offering, we do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. In the event that the number of shares of our common stock to be sold in this offering by us or Rhino Energy Holdings LLC is decreased, liquidity could be adversely affected even further. Stockholders may not be able to resell their shares at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our common stock and limit the number of investors who are able to buy our common stock.

The initial public offering price for our common stock has been determined by negotiations between us and the representative of the underwriters and may not be indicative of the market price of our common stock that will prevail in the trading market. The market price of our common stock may decline below the initial public offering price. The market price of our common stock may also be influenced by many factors, some of which are beyond our control, including:

•: our quarterly or annual earnings or those of other companies in our industry;
•: loss of a large customer;
•: announcements by us or our competitors of significant contracts or acquisitions;
•: changes in accounting standards, policies, guidance, interpretations or principles;
•: general economic conditions;

•: the failure of securities analysts to cover our stock after this offering or changes in financial estimates by analysts;
•: future sales of our common stock; and
•: the other factors described in these "Risk Factors."

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

We have no history operating as a publicly traded corporation. As a publicly traded corporation, we will incur additional legal, accounting and other expenses that we did not incur as a private company. This increase will be due to the increased accounting support services, filing annual and quarterly reports with the SEC, increased audit fees, investor relations, directors' fees, directors' and officers' insurance, legal fees, stock exchange listing fees and registrar and transfer agent fees, which we expect to incur after the completion of this offering. In addition, we expect that complying with the rules and regulations implemented by the SEC and The New York Stock Exchange will increase our legal and financial compliance costs and make activities more time-consuming and costly. For example, as a result of becoming a publicly traded corporation, we are required to have three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded corporation reporting requirements.

USE OF PROCEEDS

We estimate that our net proceeds from this offering, assuming an offering price of $ per share, will be approximately $ million after deducting the estimated underwriting discount and offering expenses payable by us. We intend to use all of the net proceeds to repay outstanding indebtedness under our credit facility, a portion of which was used to finance the acquisitions of the Sands Hill and Deane mining complexes and our investment in the joint venture that acquired the Eagle mining complex and the Bolt field, leaving approximately $ million of outstanding indebtedness under our credit facility and approximately $ million of total indebtedness, on a pro forma basis as of June 30, 2008.

Our credit facility bears interest at either: (1) LIBOR plus 1.25% to 1.75% per annum depending on our leverage ratio; or (2) a base rate that is the higher of the prime rate or the federal funds rate plus 0.50%. We incur letter of credit fees equal to the then applicable spread above LIBOR on the undrawn face amount of standby letters of credit issued 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 facility at a rate of 0.25% per annum based on the unused portion of the facility. The credit facility will mature in 2013. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."

A $1.00 increase or decrease in the assumed initial public offering price of $ per share would cause the net proceeds from this offering, after deducting the underwriting discount and offering expenses payable by us, to increase or decrease, respectively, by approximately $ million. In addition, we may also increase or decrease the number of shares we are offering. Each increase of 1.0 million shares offered by us, together with a concomitant $1.00 increase in the assumed public offering price to $ per share, would increase net proceeds to us from this offering by approximately $ million. Similarly, each decrease of 1.0 million shares offered by us, together with a concomitant $1.00 decrease in the assumed initial offering price to $ per share, would decrease the net proceeds to us from this offering by approximately $ million. Any increase or decrease in either the initial offering price or number of shares sold by Rhino Holdings LLC would have a similar result on the net proceeds in which it receives. We do not expect that any increase or decrease by Rhino Energy Holdings LLC would have a material affect on us or the offering.

We will not receive any of the proceeds from the sale of shares by Rhino Energy Holdings LLC in this offering, including from any exercise of the underwriters' option to purchase additional shares. Rhino Energy Holdings LLC has informed us that it intends to distribute the net proceeds it receives from the sale of our common stock to Wexford Funds. Certain of our directors are Wexford Partners and, accordingly, may indirectly receive proceeds from this offering. Please read "Security Ownership of Certain Beneficial Owners, Management and the Selling Stockholder" and "Certain Relationships and Related Party Transactions."

We will pay all of the offering expenses of the selling stockholder, excluding the underwriting discount.

DIVIDEND POLICY

We expect to commence a policy of paying quarterly dividends, initially at an annual rate of between $ and $ per share, to the holders of our common stock. We would expect our board to continue this dividend policy for the foreseeable future subject to: (1) our results of operations and the amount of our surplus available to be distributed; (2) dividend availability and restrictions under our credit facility; (3) the dividend rate being paid by comparable companies in the coal industry; (4) our liquidity needs and financial condition; and (5) other factors that our board of directors may deem relevant. Please read "Risk Factors—Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities" and "—We are a holding company with no operations of our own and depend on our subsidiaries for cash."

Any future determination relating to our dividend policy will be made at the discretion of our board of directors and will depend on then existing conditions, including our financial condition, results of operations, contractual restrictions, including our credit agreement, capital requirements, business prospects and other factors our board of directors may deem relevant.

CAPITALIZATION

The following table shows our capitalization as of June 30, 2008:

•: on an actual basis for our predecessor, Rhino Energy LLC; and
•: on a pro forma basis, to reflect the offering of our common stock and the use of the net proceeds from this offering as described under "Use of Proceeds."

This table is derived from, and should be read together with, the historical and pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Use of Proceeds" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

				As of June 30, 2008
				Actual		Pro Forma(1)
				(in thousands)
Cash				$	1,153.1	$
Debt:
	Credit facility			$	80,000.0	$
	Other debt				10,328.6

		Total debt			90,328.6
Members' equity					135,580.1
Stockholder' equity:
	Common stock, par value $0.01 per share, 500,000,000 shares authorized, shares issued and outstanding(2)
	Additional paid-in capital				—
	Retained earnings				—
	Accumulated other comprehensive income				—

			Total members'/stockholders' equity		135,580.1

			Total capitalization	$	227,061.8	$

(1): Each $1.00 increase or decrease in the assumed public offering price of $ per share would increase or decrease, respectively, each of total stockholders' equity and total capitalization by approximately $ million, after deducting the underwriting discount and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase of 1.0 million shares offered by us, together with a concomitant $1.00 increase in the assumed offering price to $ per share, would increase total stockholders' equity and total capitalization by approximately $ million. Similarly, each decrease of 1.0 million shares offered by us, together with a concomitant $1.00 decrease in the assumed offering price to $ per share, would decrease total stockholders' equity and total capitalization by approximately $ million. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.
(2): The number of shares of common stock issued and outstanding on a pro forma basis includes shares of common stock outstanding, including awards of unrestricted stock to management and excluding awards of restricted stock to management.

DILUTION

Dilution is the amount by which the offering price will exceed the net tangible book value per share after the offering. Assuming an initial public offering price of $ per share, on a pro forma basis as of June 30, 2008, after giving effect to the offering of common stock, our net tangible book value was approximately $ million, or $ per share. The pro forma net book tangible value excludes $ million of deferred financing costs. Purchasers of our common stock in this offering will experience substantial and immediate dilution in net tangible book value per share for financial accounting purposes, as illustrated in the following table.

Assumed initial public offering price per share		$
Net tangible book value per share before the offering(1)	$
Increase in net tangible book value per share attributable to purchasers in the offering

Less: Pro forma net tangible book value per share after the offering(2)

Immediate dilution in net tangible book value per share to purchasers in the offering(3)		$

(1): Determined by dividing the net tangible book value of the contributed assets and liabilities by the aggregate of shares to be issued to Rhino Energy Holdings LLC for the contribution of assets and liabilities by Rhino Energy Holdings LLC and certain Wexford Funds to us.
(2): Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering by the total number of shares to be outstanding after the offering.
(3): Each $1.00 increase or decrease in the assumed public offering price of $ per share would increase or decrease, respectively, our pro forma net tangible book value by approximately $ million, or approximately $ per share, and dilution per share to investors in this offering by approximately $ per share, after deducting the underwriting discount and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. An increase of 1.0 million shares offered by us, together with a concomitant $1.00 increase in the assumed offering price to $ per share, would result in a pro forma net tangible book value of approximately $ million, or $ per share, and dilution per share to investors in this offering would be $ per share. Similarly, a decrease of 1.0 million shares offered by us, together with a concomitant $1.00 decrease in the assumed public offering price to $ per share, would result in an pro forma net tangible book value of approximately $ million, or $ per share, and dilution per share to investors in this offering would be $ per share. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.

The following table sets forth the number of shares that we will issue and the total consideration contributed to us by Rhino Energy Holdings LLC and certain Wexford Funds in respect of Rhino Energy Holdings LLC's shares and by the purchasers of our common stock in this offering upon consummation of the transactions contemplated by this prospectus.

	Shares Acquired(1)			Total Consideration
	Shares Acquired(1)			Total Consideration			Average Price Per Share
	Number	Percent		Amount	Percent		Average Price Per Share
Rhino Energy Holdings LLC(2)			%			%	$
New investors			%			%	$

Total		100	%	$	100	%	$

(1): The number of shares disclosed for Rhino Energy Holdings LLC includes the being sold by Rhino Energy Holdings LLC to the public in this offering. The number of shares disclosed for new investors does not include the shares being purchased by the new investors from Rhino Energy Holdings LLC in this offering. The number of shares disclosed in this table does not include the shares of restricted stock and shares of unrestricted stock that we will issue to management in connection with the consummation of the transactions contemplated by this prospectus.
(2): The assets contributed by Rhino Energy Holdings LLC and certain Wexford Funds will be recorded at historical cost. The book value of the consideration provided by Rhino Energy Holdings LLC and certain Wexford Funds is as of June 30, 2008.

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED
FINANCIAL AND OPERATING DATA

The following table presents selected historical consolidated financial and operating data of our predecessor, Rhino Energy LLC, as of the dates and for the periods indicated. The selected historical consolidated financial data presented as of December 31, 2003 and March 31, 2004, 2005 and 2006 and for the period from April 30, 2003 (date of inception) through December 31, 2003, the three months ended March 31, 2004 and the year ended March 31, 2005 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are not included in this prospectus. The selected historical consolidated financial data presented as of December 31, 2006 and 2007 and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 2007 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. The selected historical consolidated financial data presented as of June 30, 2008 and for the six months ended June 30, 2007 and 2008 is derived from the unaudited condensed consolidated historical financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. The selected historical consolidated financial data presented as of June 30, 2007 is derived from our predecessor's accounting records, which are unaudited. Effective January 1, 2004, Rhino Energy LLC changed its fiscal year end from December 31 to March 31. Effective April 1, 2006, Rhino Energy LLC changed its fiscal year end from March 31 to December 31.

The selected pro forma consolidated financial data presented for the year ended December 31, 2007 and as of and for the six months ended June 30, 2008 is derived from our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma consolidated financial statements give pro forma effect to:

•: the contribution by Rhino Energy Holdings LLC and certain Wexford Funds of 100% of the ownership interests in Rhino Energy LLC to us in exchange for an aggregate of shares of our common stock;
•: the issuance by us to the public of shares of our common stock;
•: the issuance by us to management of shares of restricted stock and shares of unrestricted stock issued under our long-term incentive plan;
•: the use of the net proceeds from this offering as described under "Use of Proceeds"; and
•: the provision for income taxes under our corporate holding company structure.

The unaudited pro forma consolidated balance sheet assumes the items listed above occurred as of June 30, 2008. The unaudited pro forma consolidated statements of operations data for the year ended December 31, 2007 and the six months ended June 30, 2008 assume the items listed above occurred as of January 1, 2007. We have not given pro forma effect to the incremental selling, general and administrative expenses of approximately $3.0 million that we expect to incur as a result of being a publicly traded corporation.

For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with "Use of Proceeds," "Business—Our History," the historical consolidated financial statements of Rhino Energy LLC and our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.

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 means earnings before interest, taxes, depreciation, depletion and amortization. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to its most directly comparable financial measures calculated and presented in accordance with GAAP.

			Rhino Energy LLC Historical Consolidated																								Rhino Resources, Inc. Pro Forma Consolidated
			Period from April 30, 2003 (date of inception) through December 31, 2003
						Three Months Ended March 31, 2004			Year Ended March 31,						Nine Months Ended December 31, 2006						Six Months Ended June 30,							Six Months Ended June 30, 2008
									Year Ended March 31,									Year Ended December 31, 2007			Six Months Ended June 30,						Year Ended December 31, 2007
									2005			2006						Year Ended December 31, 2007			2007			2008			Year Ended December 31, 2007
			(in thousands, except per share and per ton data)
Statement of Operations Data:
Total revenues			$	33,901.4		$	16,224.7		$	279,977.8		$	363,959.9		$	300,838.5		$	403,451.8		$	193,501.0		$	223,019.1		$	$
Costs and expenses:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			25,841.3			14,056.4			220,628.7			291,444.7			238,189.7			318,520.6			152,408.2			172,489.9
	Freight and handling costs			578.4			570.1			7,245.3			6,342.5			2,768.1			4,020.7			956.6			4,132.2
	Depreciation, depletion and amortization			1,715.8			698.3			4,583.4			13,744.3			28,471.2			30,749.8			14,326.4			17,247.4
	Selling, general and administrative			4,735.7			1,191.0			12,877.5			17,129.4			18,573.0			15,370.3			7,146.6			8,814.6
	(Gain) loss on sale of assets			(109.9	)		48.3			505.7			(377.2	)		745.8			(944.3	)		(797.6	)		(376.2	)
	(Gain) loss on retirement of advance royalties			—			—			—			(236.9	)		2,994.6			(115.3	)		(125.3	)		8.0

		Total costs and expenses		32,761.3			16,564.1			245,840.6			328,046.8			291,742.4			367,601.8			173,914.9			202,315.9

Income (loss) from operations				1,140.1			(339.4	)		34,137.2			35,913.1			9,096.1			35,850.0			19,586.1			20,703.2
Interest and other income (expense):
	Interest expense			(565.0	)		(287.9	)		(3,454.7	)		(4,976.2	)		(6,498.0	)		(5,579.2	)		(3,121.6	)		(2,557.2	)
	Interest income			30.2			13.1			442.3			412.1			311.7			316.7			185.3			100.6
	Other—net			109.8			(6.7	)		(1,296.4	)		490.7			272.2			—			—			—

Total interest and other income (expense)				(425.0	)		(281.5	)		(4,308.8	)		(4,073.4	)		(5,914.1	)		(5,262.5	)		(2,936.3	)		(2,456.6	)

Income (loss) before income tax expense and cumulative effect of change in accounting principle				715.1			(620.9	)		29,828.4			31,839.7			3,182.0			30,587.5			16,649.8			18,246.6
Income tax expense (benefit)(1)				—			—			73.8			178.4			124.6			(126.3	)		(119.5	)		—
Equity in net income (loss) of unconsolidated affiliate				—			—			—			—			—			—			—			(38.5	)

Net income (loss) before cumulative effect of change in accounting principles				715.1			(620.9	)		29,754.6			31,661.3			3,057.4			30,713.8			16,769.3			18,208.1
Cumulative effect of change in accounting principle—net of taxes				—			—			1,656.4			—			—			—			—			—

Net income (loss)			$	715.1		$	(620.9	)	$	28,098.2		$	31,661.3		$	3,057.4		$	30,713.8		$	16,769.3		$	18,208.1		$	$
Other comprehensive income (loss):
	Change in actuarial gain/(loss) under SFAS No. 158			—			—			—			—			(901.0	)		1,489.4			—			—

Net comprehensive income (loss)			$	715.1		$	(620.9	)	$	28,098.2		$	31,661.3		$	2,156.4		$	32,203.2		$	16,769.3		$	18,208.1		$	$

		Rhino Energy LLC Historical Consolidated																								Rhino Resources, Inc. Pro Forma Consolidated
		Period from April 30, 2003 (date of inception) through December 31, 2003
					Three Months Ended March 31, 2004			Year Ended March 31,						Nine Months Ended December 31, 2006						Six Months Ended June 30,							Six Months Ended June 30, 2008
								Year Ended March 31,									Year Ended December 31, 2007			Six Months Ended June 30,						Year Ended December 31, 2007
								2005			2006						Year Ended December 31, 2007			2007			2008			Year Ended December 31, 2007
		(in thousands, except per share and per ton data)
Pro forma earnings per share, basic																										$	$
Pro forma earnings per share, diluted																										$	$
Pro forma weighted average number of shares outstanding, basic
Pro forma weighted average number of shares outstanding, diluted
Statement of Cash Flows Data:
Net cash provided by (used in):
	Operating activities	$	(568.2	)	$	(1,079.1	)	$	33,142.6		$	32,892.0		$	36,859.5		$	52,492.5		$	26,913.4		$	45,352.1		$	$
	Investing activities	$	(20,796.1	)	$	(13,406.2	)	$	(47,182.2	)	$	(34,612.6	)	$	(28,827.6	)	$	(28,097.6	)	$	(2,941.9	)	$	(53,154.5	)
	Financing activities	$	21,368.0		$	14,485.1		$	19,132.5		$	(1,886.9	)	$	(9,140.8	)	$	(21,191.5	)	$	(21,320.3	)	$	5,372.1
Other Financial Data:
EBITDA(2)		$	2,995.9		$	365.3		$	36,210.0		$	50,560.2		$	38,151.2		$	66,916.5		$	34,097.8		$	38,012.7		$	$
Total capital expenditures(3)		$	17,048.1		$	14,528.8		$	61,905.0		$	66,373.3		$	42,393.4		$	39,738.1		$	11,041.7		$	41,910.9		$	$
Balance Sheet Data (at period end):
Cash and cash equivalents		$	3.6		$	3.4		$	5,096.3		$	1,488.8		$	380.0		$	3,583.4		$	3,031.1		$	1,153.1			$
Property and equipment, net		$	26,805.5		$	42,818.8		$	128,407.4		$	180,267.0		$	197,056.1		$	211,657.1		$	195,460.8		$	250,207.4			$
Total assets		$	41,163.6		$	59,422.1		$	181,138.4		$	246,759.3		$	248,194.5		$	275,992.2		$	253,415.2		$	325,643.7			$
Total liabilities		$	24,568.2		$	43,644.6		$	120,068.7		$	154,028.4		$	153,307.1		$	158,151.7		$	140,588.5		$	190,063.6			$
Total debt		$	16,597.1		$	31,279.2		$	61,941.9		$	87,764.1		$	88,570.5		$	83,953.7		$	72,830.9		$	90,328.6			$
Members'/stockholders' equity		$	16,595.4		$	15,777.5		$	61,069.6		$	92,730.9		$	94,887.4		$	117,840.5		$	112,826.7		$	135,580.1			$
Operating Data:
Tons of coal sold			1,058.6			455.4			7,051.6			7,900.3			6,222.9			8,159.0			3,976.6			4,188.3
Tons of coal produced			1,122.1			511.5			7,201.6			7,950.1			6,182.0			7,056.6			3,503.8			3,971.1
Coal revenues per ton(4)		$	31.25		$	35.42		$	38.63		$	44.48		$	47.31		$	48.30		$	47.85		$	50.43
Cost of operations per ton(5)		$	24.96		$	32.12		$	32.32		$	36.89		$	38.28		$	39.04		$	38.33		$	41.18

(1)

(2)

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

•: our compliance with certain financial covenants included in our debt agreements;
•: our financial performance without regard to financing methods, capital structure or income taxes;
•: our ability to generate cash sufficient to pay interest on our indebtedness; and
•: the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

		Rhino Energy LLC Historical Consolidated																				Rhino Resources, Inc. Pro Forma Consolidated
		Period from April 30, 2003 (date of inception) through December 31, 2003
																	Six Months Ended June 30,
					Three Months Ended March 31, 2004			Year Ended March 31,				Nine Months Ended December 31, 2006											Six Months Ended June 30, 2008
								Year Ended March 31,						Year Ended December 31, 2007								Year Ended December 31, 2007
								2005		2006				Year Ended December 31, 2007			2007			2008		Year Ended December 31, 2007
		(in thousands, except per share and per ton data)
Reconciliation of EBITDA to net income:
Net income (loss)		$	715.1		$	(620.9	)	$	28,098.2	$	31,661.3	$	3,057.4	$	30,713.8		$	16,769.3		$	18,208.1	$	$
Plus:
	Depreciation, depletion and amortization		1,715.8			698.3			4,583.4		13,744.3		28,471.2		30,749.8			14,326.4			17,247.4
	Interest expense		565.0			287.9			3,454.7		4,976.2		6,498.0		5,579.2			3,121.6			2,557.2
	Income tax expense (benefit)		—			—			73.8		178.4		124.6		(126.3	)		(119.5	)		—

EBITDA		$	2,995.9		$	365.3		$	36,210.1	$	50,560.2	$	38,151.2	$	66,916.5		$	34,097.8		$	38,012.7	$	$

Reconciliation of EBITDA to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities		$	(568.2	)	$	(1,079.1	)	$	33,142.6	$	32,892.0	$	36,859.5	$	52,492.5		$	26,913.4		$	45,352.1	$	$
Plus:
	Increase in net operating assets		2,889.2			1,676.9			3,176.6		16,447.4		892.7		10,552.7			4,754.7			—
	Decrease in provision for doubtful accounts		—			—			—		—		282.8		175.2			—			—
	Gain on sale of assets		—			—			—		377.2		—		944.3			797.6			376.2
	Gain on retirement of advance royalties		109.9			—			—		236.9		—		115.3			125.3			—
	Interest expense		565.0			287.9			3,454.7		4,976.2		6,498.0		5,579.2			3,121.6			2,557.2
	Income tax expense		—			—			73.8		178.4		124.6		—			—			—
Less:
	Decrease in net operating assets		—			—			—		—		—		—			—			8,609.8
	Accretion on interest-free debt		—			—			473.2		321.2		255.1		359.8			177.0			282.8
	Amortization of advance royalties		—			406.0			1,231.5		2,186.8		1,098.5		699.7			441.3			115.7
	Increase in provision for doubtful accounts		—			—			103.6		354.4		—		—			—			—
	Equity in net loss of unconsolidated affiliate		—			—			—		—		—		—			—			38.5
	Loss on sale of assets		—			48.3			505.7		—		745.8		—			—			—
	Loss on retirement of advance royalties		—			—			—		—		2,994.6		—			—			8.0
	Income tax benefit		—			—			—		—		—		126.3			119.5			—
	Accretion on asset retirement obligations		—			66.1			1,323.6		1,685.5		1,412.4		1,756.9			877.0			1,218.0

EBITDA		$	2,995.9		$	365.3		$	36,210.1	$	50,560.2	$	38,151.2	$	66,916.5		$	34,097.8		$	38,012.7	$	$

(3): 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:

		Rhino Energy LLC Historical Consolidated
		Period from April 30, 2003 (date of inception) through December 31, 2003
				Three Months Ended March 31, 2004										Six Months Ended June 30,
						Years Ended March 31,				Nine Months Ended December 31, 2006
						Years Ended March 31,						Year Ended December 31, 2007
						2005		2006				Year Ended December 31, 2007		2007		2008
		(in thousands)
Reconciliation of total capital expenditures to net cash used for capital expenditures:
Additions to property, plant and equipment		$	6,443.1	$	1,928.8	$	31,047.1	$	31,485.5	$	32,701.3	$	14,598.7	$	5,638.0	$	26,989.8
Acquisitions of coal companies and coal properties			10,605.0		12,600.0		16,928.0		5,000.0		—		18,174.5		—		14,669.7

Net cash used for capital expenditures			17,048.1		14,528.8		47,975.1		36,485.5		32,701.3		32,773.2		5,638.0		41,659.5
Plus:
	Additions to property, plant and equipment financed through long-term borrowing		—		—		13,928.9		29,887.8		9,692.1		6,964.9		5,403.7		251.4

Total capital expenditures		$	17,048.1	$	14,528.8	$	61,905.0	$	66,373.3	$	42,393.4	$	39,738.1	$	11,041.7	$	41,910.9

(4): 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.
(5): 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of the financial condition and results of operations of our predecessor, Rhino Energy LLC and its wholly owned subsidiaries, in conjunction with the historical consolidated financial statements of Rhino Energy LLC and the unaudited pro forma consolidated financial statements of Rhino Resources, Inc. included elsewhere in this prospectus. Among other things, those historical and pro forma consolidated financial statements include more detailed information regarding the basis of presentation for the following information.

Overview

As of October 31, 2007, we controlled approximately 222.3 million tons of proven and probable coal reserves and approximately 97.8 million tons of non-reserve coal deposits. We completed the acquisitions of the Sands Hill mining complex located in Northern Appalachia in December 2007 and the Deane mining complex located in Central Appalachia in February 2008. These acquisitions collectively added approximately 18.6 million tons of proven and probable coal reserves and approximately 4.1 million tons of non-reserve coal deposits. We expect to produce approximately 1.8 million tons of coal in 2009 from these mining complexes. In May 2008, we entered into a joint venture, in which we have a 51% membership interest and for which we serve as the manager, that acquired the Eagle mining complex and the Bolt field located in Central Appalachia. The joint venture controls approximately 21.1 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits. We expect that the Eagle mining complex will produce approximately 0.6 million tons of metallurgical coal in 2009. We produce high quality coal that is sold in both the steam and metallurgical coal markets. We market our steam coal primarily to electric utilities, the majority of which are rated investment grade. The metallurgical coal that we produce is sold for end use by domestic and international steel producers. In addition, the Sands Hill mining complex added approximately 21.6 million tons of proven and probable limestone reserves and approximately 3.7 million tons of non-reserve limestone deposits.

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, tires, 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 of the mining industry or the electric utility industry, (2) the availability and prices of competing electricity- generation fuels, (3) our ability to secure or acquire high-quality coal reserves and (4) our ability to find buyers for coal under supply contracts with terms comparable to those under existing contracts.

We conduct business through five reportable segments: Central Appalachia, Rhino Eastern, Northern Appalachia, Sands Hill and Other segments. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane (which we acquired in February 2008), which, as of June 30, 2008, together included nine underground mines, seven surface mines and three preparation and/or loadout facilities in eastern Kentucky and southern West Virginia. Our Rhino Eastern segment consists of our equity interest in the Eagle operation (which our joint venture acquired in May 2008), which had an immaterial impact on our overall results of operations for the six months ended June 30, 2008. Since we use the equity method to account for the joint venture, we report results of operations for our Rhino Eastern segment only at the net income level. Our Northern Appalachia segment consists of the Hopedale mining complex located in southern Ohio which, as of June 30, 2008, included one underground mine and one preparation plant and loadout facility. Our Sands Hill segment consists of the Sands Hill mining complex located in southern Ohio (which we acquired in December 2007), which as of June 30, 2008 included two surface mines and a preparation plant. For the year ended December 31, 2007 and the six months ended June 30, 2008, our Other segment included the results of our operation in the Western Bituminous Region, reserves in the Illinois Basin and our ancillary businesses.

One of our business strategies is to expand our operations through strategic acquisitions, including coal and non-coal natural resource assets. Such non-coal natural resource assets may include assets that will serve as a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel.

Recent Trends and Economic Factors Affecting the Coal Industry

Our coal revenues depend on the price at which we are able to sell our coal. We believe that current coal pricing fundamentals in the U.S. coal industry are among the strongest in recent history. Please read "The Coal Industry." Any decrease in coal prices due to, among other reasons, the supply of domestic and foreign coal, the demand for electricity or the price and availability of alternative fuels for electricity generation could adversely affect our results of operations. In addition, our results of operations depend on the cost of coal production. We are experiencing increased operating costs for diesel fuel and explosives, health care and labor. Recently, low interest rates have resulted in an increase in the present value of employee-benefit-related liabilities and therefore have increased our employee-benefit-related expenses. Increases in the costs of regulatory compliance could also adversely impact results of operations.

In recent years, certain trends and economic factors affecting the coal industry have emerged, garnering the attention of industry participants. Such factors include the following:

•: Promulgation of more stringent mine safety laws. Mining accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent

mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. Implementing and complying with these new laws and regulations imposes additional costs on coal producers. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices.

•: Shortage of skilled labor and rising labor costs. The coal industry is experiencing a shortage of skilled labor and rising labor costs, due in large part to increased demand by coal producers attempting to increase production in response to the strong market demand for coal and to demographic changes as existing miners are retiring at a faster rate than the rate at which new miners are entering the mining workforce. In the event the shortage of experienced labor continues or worsens or coal producers are unable to train the necessary amount of skilled laborers, there could be an adverse impact on labor productivity and costs and our ability to expand production. Further, as a result of current market conditions and the high demand for skilled labor in the regions in which we operate, we are experiencing a record level of labor costs.
•: Delays in obtaining and renewing permits. Numerous governmental permits or approvals are required for mining operations. The permitting process can extend over several years. The permitting rules are complex and the public frequently has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention, which can delay the issuance of or renewal of permits. Such delays in obtaining and renewing permits have an obvious detrimental effect on the ability of coal producers to conduct their mining operations.
•: Rising prices of basic mining materials. Coal mining operations use significant amounts of steel, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials. The coal industry has seen the price of steel, petroleum products and other materials increase, a trend that has continued through August 2008. Prices for basic mining materials such as diesel fuel and explosives have also increased.

For additional information regarding some of the risks and uncertainties that affect our business and the industry in which we operate, please read "Risk Factors."

Results of Operations

Evaluating Our Results of Operations

Our management uses a variety of financial measurements to analyze our performance. These measurements include (1) EBITDA, (2) coal revenues per ton, (3) cost of operations per ton and (4) cost of operations per ton produced.

EBITDA. The discussion of our results of operations below includes references to, and analysis of, our segments' EBITDA results. EBITDA represents net income from operations before deducting interest expense, depreciation, depletion and amortization, and income taxes. EBITDA is used by management primarily as a measure 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. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis for each of the periods indicated.

Coal Revenues Per Ton. Coal revenues per ton represent coal revenues divided by tons of coal sold.

Cost of Operations Per Ton. Cost of operations per ton represents the cost of operations (exclusive of depreciation, depletion and amortization) divided by tons of coal sold.

Cost of Operations Per Ton Produced. Cost of operations per ton produced represents the cost of operations for produced coal (exclusive of depreciation, depletion and amortization) divided by tons of coal produced.

Comparability of Results of Operations

We present comparisons of our results of operations for the following periods:

•: Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007;
•: Year Ended December 31, 2007 Compared to Year Ended December 31, 2006;
•: Year Ended December 31, 2007 Compared to Nine Months Ended December 31, 2006; and
•: Nine Months Ended December 31, 2006 Compared to Year Ended March 31, 2006.

Effective April 1, 2006, Rhino Energy LLC changed its fiscal year end from March 31 to December 31. Information for the year ended December 31, 2006 is derived from the unaudited historical consolidated financial statements of Rhino Energy LLC that are not included in this prospectus. Information for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. Information for the six months ended June 30, 2007 and 2008 is derived from the unaudited historical condensed consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus. Information presented as of June 30, 2007 is derived from our predecessor's accounting records, which are unaudited. We include the comparison of our audited results of operations for the year ended December 31, 2007 to our unaudited results of operations for the year ended December 31, 2006 as a supplement to the generally required comparisons of audited results of operations based on our belief that such a year-to-year comparison will enhance the reader's understanding of our results of operations.

Changes in Our Segmentation

Rhino Energy LLC changed the presentation of its reporting business segments and retrospectively restated its segment disclosures in its financial statements for the year ended December 31, 2007 to report Sands Hill as a separate reporting business segment as its assets exceeded 10% of the combined assets of all operating segments as of December 31, 2007. The Sands Hill operating segment, which was acquired in December 2007, was previously reported under the Other reporting business segment. Accordingly, segment disclosures for the year ended December 31, 2007 within "Management's Discussion and Analysis of Financial Condition and Results of Operations" have been likewise restated. For additional information, please read Footnote 14 to the audited historical consolidated financial statements of Rhino Energy LLC for the year ended December 31, 2007.

Effective April 1, 2008, Rhino Energy LLC's interest in Rhino Eastern LLC, the joint venture that acquired the Eagle mining complex and the Bolt field, was also added as a separate reporting business segment. Rhino Energy LLC acquired a 51% membership interest in the joint venture in May 2008 and the results of operations for the joint venture were immaterial for the six months ended June 30, 2008. The mining complex has two underground mines that are in the process of redevelopment but as of June 30, 2008 were inactive. The mining complex commenced operations in August 2008.

Changes in Our Legal Structure

Our operations are currently conducted by a limited liability company, Rhino Energy LLC. Prior to the closing of this offering, Rhino Energy LLC will become a wholly owned subsidiary of Rhino Resources, Inc. Following this offering, we will report our results of operations and financial condition as a corporation on a consolidated basis rather than a limited liability company.

Historically, we did not incur income tax expenses (with the exception of Kentucky income taxes as a result of a Kentucky state law that required partnerships to pay state income taxes, which was repealed effective January 1, 2007) because we were treated as a partnership for income tax purposes. Our unaudited pro forma financial statements included elsewhere in this prospectus, however, include a pro forma adjustment for income taxes, resulting in pro forma net income adjusted for income taxes. As a consequence of our change in structure, we will recognize deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. In connection with the change to a corporate holding company structure prior to the closing of this offering, we will record income tax expense for the cumulative effect of recording our net deferred tax liability. Following this offering, we will incur income taxes under our new corporate holding company structure, and our financial statements will reflect the actual impact of income taxes.

Public Company Expenses

We believe that our general and administrative expenses will increase as a result of becoming a publicly traded corporation following this offering. This increase will be due to the increased accounting support services, filing annual and quarterly reports with the SEC, increased audit fees, investor relations, directors' fees, directors' and officers' insurance, legal fees, stock exchange listing fees and registrar and transfer agent fees, which we expect to incur after the completion of this offering. Our financial statements following this offering will reflect the impact of these increased expenses and will affect the comparability of our financial statements with periods prior to the completion of this offering.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Summary. For the six months ended June, 2008, we sold 4.2 million tons of coal as compared to 4.0 million tons of coal for the six months ended June 30, 2007. Total revenues increased to $223.0 million for the six months ended June 30, 2008 from $193.5 million for the six months ended June 30, 2007. Net income was $18.2 million for the six months ended June 30, 2008 as compared to $16.8 million for the same period in 2007. EBITDA also increased to $38.0 million for the six months ended June 30, 2008 from $34.1 million for the same period in 2007.

Tons Sold. The following table presents tons of coal sold by reportable segment for the six months ended June 30, 2007 and 2008:

	Six Months Ended June 30, 2007	Six Months Ended June 30, 2008	Increase/(Decrease)
Segment			Increase/(Decrease)
Segment			Tons		%*
	(in millions, except %)
Central Appalachia	3.2	3.0	(0.2	)	(6.9	)%
Rhino Eastern	n/a	—	n/a		n/a
Northern Appalachia	0.7	0.8	0.1		21.4	%
Sands Hill	n/a	0.3	n/a		n/a
Other	0.1	0.1	—		—

Total	4.0	4.2	0.2		5.3	%

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

For the six months ended June 30, 2008, we sold 4.2 million tons of coal as compared to 4.0 million tons for the same period in 2007. For the six months ended June 30, 2008, the addition of our Sands Hill operation increased tons of coal sold by 0.3 million and, in the Northern Appalachia segment, tons of coal sold increased by 0.1 million tons while tons of coal sold decreased by 0.2 million tons in the Central Appalachia segment.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the six months ended June 30, 2007 and 2008:

		Six Months Ended June 30, 2007		Six Months Ended June 30, 2008		Increase/(Decrease)
Segment						Increase/(Decrease)
Segment						Dollars		%*
		(in millions, except per ton data and %)
Central Appalachia
	Coal revenues	$	162.0	$	164.7	$	2.7	1.7	%
	Freight and handling revenues		—		0.7		0.7	n/a
	Other revenues		0.5		1.5		1.0	227.5	%

	Total revenues	$	162.5	$	166.9	$	4.4	2.7	%

	Coal revenues per ton*	$	50.80	$	55.45	$	4.65	9.2	%
Northern Appalachia
	Coal revenues	$	24.1	$	30.5	$	6.4	26.3	%
	Freight and handling revenues		0.1		0.9		0.8	976.2	%
	Other revenues		1.8		2.0		0.7	10.7	%

	Total revenues	$	26.0	$	33.4	$	7.4	28.4	%

	Coal revenues per ton*	$	37.34	$	38.87	$	1.53	4.1	%
Sands Hill
	Coal revenues		n/a		11.7		n/a	n/a
	Freight and handling revenues		n/a		1.3		n/a	n/a
	Other revenues		n/a		3.8		n/a	n/a

	Total revenues		n/a		16.8		n/a	n/a

	Coal revenues per ton*		n/a	$	40.17		n/a	n/a
Other
	Coal revenues	$	4.1	$	4.3	$	0.2	3.1	%
	Freight and handling revenues		0.9		1.1		0.2	31.6	%
	Other revenues		0.1		0.5		0.4	n/a

	Total revenues	$	5.1	$	5.9	$	0.8	17.1	%

	Coal revenues per ton*	$	29.41	$	30.27	$	0.86	2.9	%
Total
	Coal revenues	$	190.2	$	211.2	$	21.0	11.0	%
	Freight and handling revenues		1.0		4.1		3.1	328.3	%
	Other revenues		2.3		7.7		5.4	242.9	%

	Total revenues	$	193.5	$	223.0	$	29.5	15.3	%

	Coal revenues per ton*	$	47.85	$	50.43	$	2.58	5.4	%

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

For the six months ended June 30, 2008, our total revenues increased to $223.0 million from $193.5 million for the six months ended June 30, 2007, due to higher coal revenues per ton and increased tons of coal sold, an increase in freight and handling revenues of $3.1 million and an increase in revenues from limestone and other ancillary businesses of $5.4 million.

For our Central Appalachia segment, coal revenues increased by $2.7 million, to $164.7 million for the six months ended June 30, 2008, as compared to the six months ended June 30, 2007. This increase was due to higher revenues per ton and increased sales of metallurgical coal, offset by a total of 0.2 million fewer tons of coal sold for the segment. In addition, freight and handling and other revenues increased for the six months ended June 30, 2008.

For our Northern Appalachia segment, total revenues increased to $33.4 million for the six months ended June 30, 2008 from $26.0 million for the six months ended June 30, 2007, primarily due to increased coal sales of 0.1 million tons. Coal revenues per ton also increased to $38.87 per ton for the

six months ended June 30, 2008 from $37.34 per ton for the six months ended June 30, 2007. In addition, freight and handling revenues increased due to increased sales of coal with accompanying freight and handling charges.

For our Sands Hill segment, coal revenues were $11.7 million for the six months ended June 30, 2008 and coal revenues per ton were $40.17 per ton. Other revenues were $3.8 million, primarily from the sale of limestone incidental to the Sands Hill coal mining operation. We acquired the Sands Hill operation in December 2007.

For our Other segment, coal revenues increased to $4.3 million for the six months ended June 30, 2008 from $4.1 million for the six months ended June 30, 2007, primarily due to an increase in coal revenues per ton. Freight and handling revenues and other revenues from our ancillary businesses also increased.

Costs and Expenses. The following table presents costs and expenses, cost of operations per ton and cost of operations per ton produced by reportable segment for the six months ended June 30, 2007 and 2008:

	Six Months Ended June 30, 2007		Six Months Ended June 30, 2008		Increase/(Decrease)
Segment					Increase/(Decrease)
Segment					Dollars			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	130.1	$	132.9	$	2.8		2.2	%
Freight and handling costs		—		0.7		0.7		n/a
Depreciation, depletion and amortization		11.6		12.1		0.5		4.7	%
Selling, general and administrative		5.0		5.8		0.8		15.4	%
Cost of operations per ton*	$	40.79	$	44.76	$	3.97		9.7	%
Cost of operations per ton produced*	$	41.29	$	44.77	$	3.48		8.4	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	17.1	$	19.9	$	2.8		16.6	%
Freight and handling costs		0.1		1.0		0.9		984.5	%
Depreciation, depletion and amortization		2.0		2.4		0.4		18.7	%
Selling, general and administrative		1.4		1.7		0.3		17.8	%
Cost of operations per ton*	$	26.46	$	25.41	$	(1.05	)	(4.0	)%
Cost of operations per ton produced*	$	26.46	$	25.41	$	(1.05	)	(4.0	)%
Sands Hill
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		n/a	$	14.5		n/a		n/a
Freight and handling costs		n/a		1.3		n/a		n/a
Depreciation, depletion and amortization		n/a		1.3		n/a		n/a
Selling, general and administrative		n/a		0.5		n/a		n/a
Cost of operations per ton*		n/a	$	49.72		n/a		n/a
Cost of operations per ton produced*		n/a	$	49.72		n/a		n/a

Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	5.2	$	5.1	$	(0.1	)	(2.5	)%
Freight and handling costs		0.9		1.2		0.3		36.8	%
Depreciation, depletion and amortization		0.7		1.4		0.7		94.0	%
Selling, general and administrative		0.7		0.8		0.1		14.7	%
Cost of operations per ton*	$	36.86	$	35.89	$	(0.97	)	(2.6	)%
Cost of operations per ton produced*	$	36.86	$	35.89	$	(0.97	)	(2.6	)%
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	152.4	$	172.5	$	20.1		13.2	%
Freight and handling costs		1.0		4.1		3.1		332.0	%
Depreciation, depletion and amortization		14.3		17.2		2.9		20.4	%
Selling, general and administrative		7.1		8.8		1.7		23.3	%
Cost of operations per ton*	$	38.33	$	41.18	$	2.85		7.5	%
Cost of operations per ton produced*	$	38.37	$	40.99	$	2.62		6.8	%

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

Cost of Operations. For the six months ended June 30, 2008, our cost of operations increased by $20.1 million, to $172.5 million, as compared to the six months ended June 30, 2007 due to an increase of $2.85 in cost of operations per ton and an increase of 0.2 million tons of coal sold for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007. Cost of operations per ton increased to $41.18 for the six months ended June 30, 2008 from $38.33 for the six months ended June 30, 2007 primarily due to increases in labor, operating supplies, maintenance and utilities costs of $1.52, $1.60, $1.20 and $0.11 per ton, respectively, offset by lower costs of benefits, outside services and rental expenses of $0.88, $0.46 and $0.49 per ton, respectively. In addition, production taxes and royalty costs also increased as a result of the increases in coal revenues per ton.

For our Central Appalachia segment, cost of operations increased by $2.8 million to $132.9 million for the six months ended June 30, 2008 from $130.1 million for the six months ended June 30, 2007 and cost of operations per ton increased to $44.76 for the six months ended June 30, 2008 as compared to $40.79 for the six months ended June 30, 2007. These increases were due to increases in labor, maintenance and utilities cost of $0.85, $0.80, and $0.18 per ton, respectively. Production taxes and royalty costs also increased by an aggregate $0.43 per ton as a result of the increases in coal revenues per ton. Contract mining and other operating costs also increased by an aggregate $1.92 per ton. Offsetting those increases in costs, benefits and rental costs decreased by $1.11 and $0.45 per ton, respectively.

For our Northern Appalachia segment, cost of operations increased by $2.8 million to $19.9 million for the six months ended June 30, 2008 as compared to $17.1 million for the six months ended June 30, 2007 due to increased coal sales. On a per ton basis, cost of operations decreased to $25.41 per ton for the six months ended June 30, 2008 from $26.46 per ton for the six months ended June 30, 2007, primarily due to lower benefits and labor costs of $1.55 per ton.

For our Sands Hill segment, cost of operations was $14.5 million for the six months ended June 30, 2008 and cost of operations per ton was $49.72 per ton. We acquired the Sands Hill operation in December 2007.

For our Other segment, cost of operations for the six months ended June 30, 2008 was $5.1 million, a slight decrease from $5.2 million for the same period in 2007. Cost of operations per ton decreased slightly to $35.89 per ton for the six months ended June 30, 2008 from $36.86 per ton for the same period in 2007 due to lower cost of operations of $1.95 per ton in our Western Bituminous operation in Colorado, offset by higher cost experienced in our ancillary businesses.

Freight and Handling. For the six months ended June 30, 2008, our freight and handling cost was $4.1 million as compared to $1.0 million for the same period in 2007 due to increased sales with accompanying freight and handling fees for all our segments.

Depreciation, Depletion and Amortization. For the six months ended June 30, 2008, depreciation, depletion and amortization ("DD&A") expense was $17.2 million, an increase of $2.9 million, or 20.4%, as compared to the same period in 2007. This increase was primarily due to increased depreciation expense of $2.7 million in connection with our Sands Hill acquisition, as well as increased depreciation for our other operations. Depletion expense and amortization expense each increased by $0.1 million for the six months ended June 30, 2008 as compared to the same period in 2007 as a result of an increase in production of 0.4 million tons for the six months ended June 30, 2008 as compared to the same period in 2007.

Selling, General and Administrative. For the six months ended June 30, 2008, selling, general and administration ("SG&A") expense increased by $1.7 million, to $8.8 million from $7.1 million for the six months ended June 30, 2007, primarily due to increased general and administration cost of $1.1 million, higher permit and bond cost of $0.4 million and higher sales taxes of $0.2 million resulting from an increase in supply purchases.

Interest Expense. For the six months ended June 30, 2008, interest expense was $2.6 million, a decrease of $0.5 million as compared to the six months ended June 30, 2007 due to lower LIBOR rate, offset by an increase in our total debt level of $17.5 million, as a result of the Sands Hill, Deane and Rhino Eastern acquisitions.

Income Tax Expense/Benefit. For the six months ended June 30, 2008, we incurred no income tax. For the six months ended June 30, 2007, we had an income tax benefit of $0.2 million due to the repeal of a Kentucky state law that required partnerships to pay state income taxes effective January 1, 2007, which resulted in an accrual of income tax benefit in 2007.

Net Income/Loss. The following table presents net income/loss by reportable segment for the six months ended June 30, 2007 and 2008:

	Six Months Ended June 30, 2007			Six Months Ended June 30, 2008			Increase/(Decrease)
Segment	Six Months Ended June 30, 2007			Six Months Ended June 30, 2008			Dollars			%*
	(in millions, except %)
Central Appalachia	$	12.9		$	12.8		$	(0.1	)	(0.5	)%
Rhino Eastern		n/a			—			n/a		n/a
Northern Appalachia		4.4			7.3			2.9		67.6	%
Sands Hill		n/a			(2.0	)		n/a		n/a
Other		(0.5	)		0.1			0.6		n/a

Total	$	16.8		$	18.2		$	1.4		8.8	%

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

Our net income increased by $1.4 million for the six months ended June 30, 2008 as compared to the same period in 2007, to $18.2 million from $16.8 million, primarily due to higher revenues that more than offset the increase in cost of operations. Lower interest and other expenses also contributed $0.4 million to the increase in net income, offset by a loss from our Sands Hill segment.

For our Central Appalachia segment, net income for the six months ended June 30, 2008 was $12.8 million as compared to $12.9 million for the six months ended June 30, 2007, as increases in coal sales and other revenues were offset by increases in cost of operations and DD&A.

For our Rhino Eastern segment, the two underground mines at the Eagle mining complex are in the process of redevelopment but were inactive as of June 30, 2008. The mining complex commenced operations in August 2008.

For our Northern Appalachia segment, net income increased by 67.6%, to $7.3 million for the six months ended June 30, 2008 from $4.4 million for the six months ended June 30, 2007, primarily due to the increase in revenues that more than offset the increase in cost of operations.

For our Sands Hill segment, we incurred a net loss of $2.0 million for the six months ended June 30, 2008 due to higher than expected cost of operations, which resulted from an increase in cost of operating supplies and lower than expected production from our new mine. We acquired the Sands Hill operation in December 2007.

For our Other segment, net income was $0.1 million for the six months ended June 30, 2008 as compared to net loss of $0.5 million for the six months ended June 30, 2007. This increase was a result of increased coal sales and higher coal revenue per ton from our operation in the Western Bituminous Region, lower cost of operations and increased net income from our ancillary businesses.

EBITDA. The following table presents EBITDA by reportable segment for the six months ended June 30, 2007 and 2008:

		Six Months Ended June 30, 2007		Six Months Ended June 30, 2008			Increase/(Decrease)
Segment							Increase/(Decrease)
Segment							Dollars			%*
		(in millions, except %)
Central Appalachia		$	26.7	$	26.6		$	(0.1	)	(0.5	)%
Rhino Eastern			n/a		—			n/a		n/a
Northern Appalachia			6.8		10.1			3.3		48.4	%
Sands Hill			n/a		(0.5	)		n/a		n/a
Other			0.6		1.8			1.2		222.9	%

	Total	$	34.1	$	38.0		$	3.9		11.6	%

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

For the six months ended June 30, 2008, our EBITDA increased by $3.9 million, or 11.6%, to $38.0 million from $34.1 million for the same period in 2007, primarily due to higher revenues that more than offset the increase in cost of operations.

For our Central Appalachia segment, EBITDA was $26.6 million for the six months ended June 30, 2008, similar to EBITDA of $26.7 million for the six months ended June 30, 2007. For our Northern Appalachia segment, EBITDA increased by 48.4%, to $10.1 million for the six months ended June 30, 2008 from $6.8 million for the six months ended June 30, 2007. This increase was primarily due to higher coal and other revenues that more than offset the increase in cost of operations.

For our Sands Hill segment, EBITDA was a negative $0.5 million for the six months ended June 30, 2008 due to higher than expected cost of operations. We acquired the Sands Hill operation in December 2007.

For our Other segment, EBITDA increased by 222.9% for the six months ended June 30, 2008, to $1.8 million from $0.6 million for the same period in 2007. This increase was primarily due to higher coal revenues per ton and increases from other revenues from our ancillary businesses, as well as our lower cost of operations in the Western Bituminous region.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

The following table presents certain historical consolidated financial and operating data of our predecessor, Rhino Energy LLC, as of the dates and for the periods indicated. The historical consolidated financial data presented for the quarter ended March 31, 2006 and the year ended December 31, 2006 is derived from the unaudited historical consolidated financial statements of Rhino Energy LLC that are not included in this prospectus. The historical consolidated financial data presented as of March 31, 2006 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are not included in this prospectus. The historical consolidated financial data presented as of December 31, 2006 and 2007 and for the nine months ended December 31, 2006 and the year ended December 31, 2007 is derived from the audited historical consolidated financial statements of Rhino Energy LLC that are included elsewhere in this prospectus.

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 means earnings before interest, taxes, depreciation, depletion and amortization. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to net income. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis for each of the periods indicated.

			Three Months Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2006			Year Ended December 31, 2007
			(in thousands, except per ton data)
Statement of Operations Data:
Total revenues			$	103,958.7		$	300,838.5		$	404,797.2		$	403,451.8
Costs and expenses:
	Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			84,959.3			238,189.7			323,149.0			318,520.6
	Freight and handling costs			1,671.1			2,768.1			4,439.2			4,020.7
	Depreciation, depletion and amortization			5,277.7			28,471.2			33,748.9			30,749.8
	Selling, general and administrative			2,691.6			18,573.0			21,264.6			15,370.3
	(Gain) loss on sale of assets			(366.0	)		745.8			379.8			(944.3	)
	(Gain) loss on retirement of advance royalties			44.6			2,994.6			3,039.2			(115.3	)

		Total costs and expenses		94,278.3			291,742.4			386,020.7			367,601.8

Income from operations				9,680.4			9,096.1			18,776.5			35,850.0
Interest and other income (expense):
	Interest expense			(1,125.8	)		(6,498.0	)		(7,623.8	)		(5,579.2	)
	Interest income			99.4			311.7			411.1			316.7
	Other—net			476.5			272.2			748.7			—

Total interest and other income (expense)				(549.9	)		(5,914.1	)		(6,464.0	)		(5,262.5	)

Income before income tax expense and cumulative effect of change in accounting principle				9,130.5			3,182.0			12,312.5			30,587.5
Income tax expense (benefit)				150.2			124.6			274.8			(126.3	)

Net income			$	8,980.3		$	3,057.4		$	12,037.7		$	30,713.8
Other comprehensive income (loss):
	Change in actuarial gain/(loss) under SFAS No. 158			—			(901.0	)		(901.0	)		1,489.4

Net comprehensive income			$	8,980.3		$	2,156.4		$	11,136.7		$	32,203.2

Other Financial Data:
EBITDA(1)	$	15,534.0	$	38,151.2	$	53,685.2	$	66,916.5
Balance Sheet Data (at period end):
Cash and cash equivalents	$	1,488.8	$	380.0	$	380.0	$	3,583.4
Property and equipment, net	$	180,267.0	$	197,056.1	$	197,056.1	$	211,657.1
Total assets	$	246,759.3	$	248,194.5	$	248,194.5	$	275,992.2
Total liabilities	$	154,028.4	$	153,307.1	$	153,307.1	$	158,151.7
Total debt	$	87,764.1	$	88,570.5	$	88,570.5	$	83,953.7
Members'/stockholders' equity	$	92,730.9	$	94,877.4	$	94,887.4	$	117,840.5
Operating Data:
Tons of coal sold		2,132.0		6,222.9		8,354.9		8,159.0
Tons of coal produced		2,211.7		6,182.0		8,403.7		7,056.6
Coal revenues per ton(2)	$	46.96	$	47.31	$	47.22	$	48.30
Cost of operations per ton(3)	$	39.85	$	38.28	$	38.68	$	39.04

(1)

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

•: our compliance with certain financial covenants included in our debt agreements;
•: our financial performance without regard to financing methods, capital structure or income taxes;
•: our ability to generate cash sufficient to pay interest on our indebtedness; and
•: the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

		Three Months Ended March 31, 2006		Nine Months Ended December 31, 2006		Year Ended December 31, 2006		Year Ended December 31, 2007
		(in thousands)
Reconciliation of EBITDA to net income:
Net income		$	8,980.3	$	3,057.4	$	12,037.7	$	30,713.8
Plus:
	Depreciation, depletion and amortization		5,277.7		28,471.2		33,748.9		30,749.8
	Interest expense		1,125.8		6,498.0		7,623.8		5,579.2
	Income tax expense (benefit)		150.2		124.6		274.8		(126.3	)

EBITDA		$	15,534.0	$	38,151.2	$	53,685.2	$	66,916.5

(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.
(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.

Summary. For the year ended December 31, 2007, we sold 8.2 million tons of coal, which is 0.2 million fewer tons, or 2.3% less, than the 8.4 million tons of coal sold for the year ended December 31, 2006. Accordingly, our total revenues also declined slightly to $403.5 million for the year ended December 31, 2007 from $404.8 million for the year ended December 31, 2006. The decrease was minimal partly because we were able to efficiently operate two underground mines in our Northern Appalachia segment for all of 2006 whereas, having completed the natural exhaustion of one mine and transitioned our operations, we operated two mines for only four months in 2007. Despite lower coal production and sales, both net income and EBITDA increased for the year ended December 31, 2007 from the year ended December 31, 2006. Net income increased to $30.7 million from $12.0 million for the year ended December 31, 2006, and EBITDA increased to $66.9 million for the year ended December 31, 2007 from $53.7 million for the year ended December 31, 2006. These increases in net income and EBITDA were due to higher coal revenues per ton for both steam and metallurgical coal and to our successful efforts to control the cost of operations.

Tons Sold. The following table presents tons of coal sold by reportable segment for the years ended December 31, 2006 and 2007:

			Increase/(Decrease)
Segment	Year Ended December 31, 2006	Year Ended December 31, 2007	Increase/(Decrease)
Segment	Year Ended December 31, 2006	Year Ended December 31, 2007	Tons		%*
	(in millions, except %)
Central Appalachia	6.5	6.6	0.1		1.6	%
Northern Appalachia	1.6	1.3	(0.3	)	(18.8	)%
Sands Hill	n/a	—	n/a		n/a
Other	0.3	0.3	—		—

Total	8.4	8.2	(0.2	)	(2.3	)%

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

Tons of coal sold for the year ended December 31, 2007 decreased by 0.2 million tons, primarily due to lower production in our Northern Appalachia segment. We operated two underground mines in our Northern Appalachia segment for all of 2006 as compared to only four months in 2007 due to the natural exhaustion of one mine. Tons of coal sold in our Central Appalachia segment increased by 0.1 million, or 1.6%, to 6.6 million tons for the year ended December 31, 2007 from 6.5 million tons for the year ended December 31, 2006. For our Other segment, tons of coal sold was flat at 0.3 million tons for the year ended December 31, 2007. We produced 7.1 million tons of coal and purchased 1.0 million tons of coal in 2007 as compared to producing 8.4 million tons of coal and purchasing no coal in 2006.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2006 and 2007:

						Increase/(Decrease)
Segment		Year Ended December 31, 2006		Year Ended December 31, 2007		Increase/(Decrease)
Segment		Year Ended December 31, 2006		Year Ended December 31, 2007		Dollars			%*
		(in millions, except per ton data and %)
Central Appalachia
	Coal revenues	$	333.0	$	337.4	$	4.4		1.3	%
	Freight and handling revenues		0.5		1.1		0.6		108.0	%
	Other revenues		2.7		1.1		(1.6	)	(58.8	)%

	Total revenues	$	336.2	$	339.6	$	3.4		1.0	%

	Coal revenues per ton*	$	51.35	$	51.19	$	(0.16	)	(0.3	)%
Northern Appalachia
	Coal revenues	$	53.9	$	48.7	$	(5.2	)	(9.6	)%
	Freight and handling revenues		2.3		1.3		(1.0	)	(45.1	)%
	Other revenues		3.1		3.4		0.3		9.4	%

	Total revenues	$	59.3	$	53.4	$	(5.9	)	(10.0	)%

	Coal revenues per ton*	$	33.53	$	37.34	$	3.81		11.4	%
Sands Hill
	Coal revenues		n/a	$	0.8		n/a		n/a
	Freight and handling revenues		n/a		0.1		n/a		n/a
	Other revenues		n/a		0.1		n/a		n/a

	Total revenues		n/a	$	1.0		n/a		n/a

	Coal revenues per ton*		n/a	$	37.97		n/a		n/a
Other
	Coal revenues	$	7.6	$	7.2	$	(0.4	)	(4.8	)%
	Freight and handling revenues		1.6		1.6		—		—	%
	Other revenues		0.1		0.7		0.6		665.6	%

	Total revenues	$	9.3	$	9.5	$	0.2		2.0	%

	Coal revenues per ton*	$	28.96	$	29.60	$	0.64		2.2	%
Total
	Coal revenues	$	394.5	$	394.1	$	(0.4	)	(0.1	)%
	Freight and handling revenues		4.4		4.1		(0.3	)	(7.9	)%
	Other revenues		5.9		5.3		(0.6	)	(9.7	)%

	Total revenues	$	404.8	$	403.5	$	(1.3	)	(0.3	)%

	Coal revenues per ton*	$	47.22	$	48.30	$	1.08		2.3	%

*: 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, 2007 decreased by $1.3 million, or 0.3%, to $403.5 million from $404.8 million for the year ended December 31, 2006. The slight decline in total revenues was due to decreased coal production in our Northern Appalachia segment. Coal revenues per ton were $48.30, an increase of $1.08, or 2.3%, from $47.22 per ton for the year ended December 31, 2006 primarily due to favorable quality adjustments for coal sold that was above the specification under the supply contracts. For our Central Appalachia segment, coal revenues increased by $4.4 million, or 1.3%, to $337.4 million for the year ended December 31, 2007 from $333.0 million for the year ended December 31, 2006 due to more tons of coal sold during the year ended December 31, 2007. Coal revenues per ton for our Central Appalachia segment were $51.19 for the year ended December 31, 2007 as compared to $51.35 for the year ended December 31, 2006. For our Northern Appalachia segment, coal revenues were

$48.7 million for the year ended December 31, 2007, a decrease of $5.2 million, or 9.6%, from the year ended December 31, 2006 due to the natural exhaustion of one mine, partially offset by higher coal revenues per ton. Coal revenues per ton for our Northern Appalachia segment increased 11.4%, to $37.34 per ton for the year ended December 31, 2007 from $33.53 per ton for the year ended December 31, 2006, due to favorable quality adjustments for coal sold that was above the specification under the supply contracts. For our Sands Hill segment, coal revenues were $0.8 million for the year ended December 31, 2007. We acquired the Sands Hill operation in December 2007. For our Other segment, coal revenues decreased by $0.4 million, or 4.8%, to $7.2 million from $7.6 million for the year ended December 31, 2006. Coal revenues per ton for our Other segment were $29.60 for the year ended December 31, 2007, an increase of $0.64, or 2.2%, from $28.96 for the year ended December 31, 2006 as a result of a contractual price increase effective June 2007.

Costs and Expenses. The following table presents costs and expenses, cost of operations per ton and cost of operations per ton produced by reportable segment for the years ended December 31, 2006 and 2007:

					Increase/(Decrease)
Segment	Year Ended December 31, 2006		Year Ended December 31, 2007		Increase/(Decrease)
Segment	Year Ended December 31, 2006		Year Ended December 31, 2007		Dollars			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	272.8	$	272.8		—		—
Freight and handling costs		0.6		1.2		0.6		97.0	%
Depreciation, depletion and amortization		29.0		24.5		(4.5	)	(15.5	)%
Selling, general and administrative		16.0		11.2		(4.8	)	(30.3	)%
Cost of operations per ton*	$	42.06	$	41.40	$	(0.66	)	(1.6	)%
Cost of operations per ton produced*	$	42.06	$	41.75	$	(0.31	)	(0.7	)%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	39.2	$	34.0	$	(5.2	)	(13.2	)%
Freight and handling costs		2.3		1.2		(1.1	)	(46.2	)%
Depreciation, depletion and amortization		3.8		4.2		0.4		9.2	%
Selling, general and administrative		4.2		3.0		(1.2	)	(29.4	)%
Cost of operations per ton*	$	24.39	$	26.08	$	1.69		7.0	%
Cost of operations per ton produced*	$	24.39	$	26.08	$	1.69		7.0	%
Sands Hill
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		n/a	$	0.8		n/a		n/a
Freight and handling costs		n/a		0.1		n/a		n/a
Depreciation, depletion and amortization		n/a		0.1		n/a		n/a
Selling, general and administrative		n/a		0.1		n/a		n/a
Cost of operations per ton*		n/a	$	38.87		n/a		n/a
Cost of operations per ton produced*		n/a	$	38.87		n/a		n/a
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	11.1	$	10.8	$	(0.3	)	(2.7	)%
Freight and handling costs		1.6		1.6		—		—
Depreciation, depletion and amortization		0.9		2.0		1.1		109.5	%
Selling, general and administrative		1.0		1.2		0.2		15.4	%
Cost of operations per ton*	$	42.57	$	44.48	$	1.91		4.5	%
Cost of operations per ton produced*	$	42.57	$	44.48	$	1.91		4.5	%

Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	323.1	$	318.5	$	(4.6	)	(1.4	)%
Freight and handling costs		4.5		4.0		(0.5	)	(9.4	)%
Depreciation, depletion and amortization		33.7		30.8		(2.9	)	(8.9	)%
Selling, general and administrative		21.3		15.4		(5.9	)	(27.7	)%
Cost of operations per ton*	$	38.68	$	39.04	$	0.36		0.9	%
Cost of operations per ton produced*	$	38.68	$	39.00	$	0.32		0.8	%

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

Cost of Operations. Total cost of operations was $318.5 million for the year ended December 31, 2007 as compared to $323.1 million for the year ended December 31, 2006. We produced 1.3 million fewer tons of coal for the year ended December 31, 2007 than for the same period in 2006; however, we sold 1.0 million tons of purchased coal and also sold 0.1 million tons from our inventory for the year ended December 31, 2007. Our cost of operations per ton was $39.04 for the year ended December 31, 2007, an increase of $0.36, or 0.9%, similar to cost of operations per ton produced.

Our cost of operations for our Central Appalachia segment remained flat as we produced 1.3 million fewer tons but cost of purchased coal increased by $35.9 million as we bought 1.0 million tons of coal for the year ended December 31, 2007 as compared to the same period in 2006. Our cost of operations per ton decreased to $41.40 for the year ended December 31, 2007 from $42.06 for the year ended December 31, 2006, similar to cost of operations per ton produced. This decrease was primarily due to lower outside services and trucking costs, which decreased $0.40 and $0.65 per ton, respectively, for the year ended December 31, 2007. These decreases were offset in part by increased labor and operating supplies costs of $0.30 and $0.33 per ton, respectively, for the year ended December 31, 2007.

In our Northern Appalachia segment, our cost of operations decreased by 13.2%, to $34.0 million for the year ended December 31, 2007 from $39.2 million for the year ended December 31, 2006, primarily because we operated from two underground mines for all of 2006 as opposed to operating from two mines for only four months in 2007 due to the natural exhaustion of one mine. However, our cost of operations per ton and cost of operations per ton produced increased to $26.08 for the year ended December 31, 2007 from $24.39 for the year ended December 31, 2006, an increase of $1.70 per ton, or 7.0%. This increase was primarily due to higher employee-benefits cost, which was $1.20 more per ton for the year ended December 31, 2007 than for the same period in 2006.

For our Sands Hill segment, cost of operations was $0.8 million for the year ended December 31, 2007 and cost of operations per ton was $38.87 per ton. We acquired the Sands Hill operation in December 2007.

Cost of operations in our Other segment decreased by $0.3 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006.

Freight and Handling. Total freight and handling cost for the year ended December 31, 2007 decreased by $0.5 million to $4.0 million from $4.5 million for the year ended December 31, 2006. This decrease was primarily due to a decrease of 0.2 million tons of coal sold for the year ended December 31, 2007 from the same period in 2006.

Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2007 was $30.8 million as compared to $33.7 million for the year ended December 31, 2006. The decrease in DD&A expense was primarily due to a decrease in depletion. For the year ended December 31, 2007, our depletion cost was $3.6 million as compared to $9.0 million for the year ended December 31, 2006. The higher depletion cost in 2006 was primarily due to idled and closed mines, which incurred $5.6 million in total depletion cost, $5.0 million of which was due to asset impairments, for the year. In 2007, there is no depletion cost for the idled and closed mines. On a per ton basis, DD&A for the year ended December 31, 2007 was $3.77 per ton, as compared to $4.04 per ton for the year ended December 31, 2006. This decrease was primarily due to lower depletion cost per ton. Depreciation cost per ton was $2.57 per ton for the year ended December 31, 2007, as compared to $2.99 per ton for the year ended December 31, 2006. Offsetting the lower depreciation and depletion cost per ton, amortization cost was $0.78 per ton higher in 2007 than in 2006, due to higher mine development cost.

Selling, General and Administrative. Total SG&A expense for the year ended December 31, 2007 was $15.4 million as compared to $21.3 million for the year ended December 31, 2006. The decrease in SG&A expense was primarily due to the consolidation of SG&A expense at the Hopedale operation in Northern Appalachia as a result of reducing from two operating mines in 2006 to one operating mine in 2007.

Interest Expense. Interest expense for the year ended December 31, 2007 was $5.6 million as compared to $7.6 million for the year ended December 31, 2006, a decrease of $2.0 million, or 36.6%. Increased cash from our operations enabled us to reduce the overall debt level which in turn lowered our interest expense.

Income Tax Expense/Benefit. Income tax benefit, which related to state income taxes, for the year ended December 31, 2007 was $0.1 million as compared to a $0.3 million expense for the year ended December 31, 2006. The income tax expense for the year ended December 31, 2006 was a result of a Kentucky state law that required partnerships to pay state income taxes. This law was repealed effective January 1, 2007, which resulted in an accrual of income tax benefit for $0.1 million for the year ended December 31, 2007.

Net Income/Loss. The following table presents net income/loss by reportable segment for the years ended December 31, 2006 and 2007:

							Increase/(Decrease)
	Year Ended December 31, 2006			Year Ended December 31, 2007			Increase/(Decrease)
	Year Ended December 31, 2006			Year Ended December 31, 2007			Dollars		%*
	(in millions, except %)
Central Appalachia	$	7.9		$	23.1		$	15.2	192.0	%
Northern Appalachia		6.7			9.1			2.4	36.1	%
Sands Hill		n/a			(0.2	)		n/a	n/a
Other		(2.5	)		(1.3	)		1.2	49.1	%

Total	$	12.0		$	30.7		$	18.7	155.1	%

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

For the year ended December 31, 2007, total net income increased to $30.7 million from $12.0 million for the year ended December 31, 2006. This increase was due to higher coal revenues per ton, lower SG&A expense, lower DD&A expense, lower interest expense, gains from asset sales and retirement of advanced royalties and the reversal of income tax expense. In addition, in October 2006, our lease for the Bolt field in West Virginia was cancelled, resulting in a write-off of $2.1 million. In February 2008, we re-entered into a lease with respect to the Bolt field, which our joint venture acquired in May 2008. Purchasing coal, instead of producing the purchased tons of coal, had the effect of decreasing net income by approximately $0.4 million for the year ended December 31, 2007 and had no impact on net income for the year ended December 31, 2006. For our Central Appalachia segment, net income increased to $23.1 million for the year ended December 31, 2007, an increase of 192.0% primarily due to higher coal sales, lower SG&A expense, lower DD&A expense and lower interest and income tax expenses, as well as gains on sales of assets and on the retirement of advanced royalties. Purchasing coal, rather than producing the purchased tons of coal, had the effect of increasing net income by $2.3 million for our Central Appalachia segment for the year ended December 31, 2007. Net income in our Northern Appalachia segment also increased by $2.4 million, or 36.1%, to $9.1 million for the year ended December 31, 2007, primarily due to higher coal revenues per ton. Our Sands Hill segment had a net loss of $0.2 million for the year ended December 31, 2007. We acquired the Sands Hill operation in December 2007. For our Other segment, net loss decreased by $1.2 million, primarily due to increased revenues and reduced cost from our ancillary businesses for the year ended December 31, 2007.

EBITDA. The following table presents EBITDA by reportable segment for the years ended December 31, 2006 and 2007:

						Increase/(Decrease)
	Year Ended December 31, 2006			Year Ended December 31, 2007		Increase/(Decrease)
	Year Ended December 31, 2006			Year Ended December 31, 2007		Dollars		%*
	(in millions, except %)
Central Appalachia	$	42.7		$	51.6	$	8.9	20.8	%
Northern Appalachia		11.6			14.0		2.4	20.2	%
Sands Hill		n/a			—		n/a	n/a
Other		(0.6	)		1.3		1.9	321.6	%

Total	$	53.7		$	66.9	$	13.2	24.6	%

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

Total EBITDA for the year ended December 31, 2007 was $66.9 million, an increase of $13.2 million, or 24.6%, from the year ended December 31, 2006. This increase in EBITDA was due to higher coal revenues and lower cost of operations, despite rising market prices for basic commodities used in mining such as diesel fuel, explosives and steel products for roof support used in our underground mining. EBITDA for our Central Appalachia segment increased by $8.9 million for the year ended December 31, 2007, due to higher coal revenues per ton and lower cost of operations per ton. EBITDA for our Northern Appalachia segment increased by $2.4 million for the year ended December 31, 2007, due to an increase in operating margins as a result of higher coal revenues per ton. EBITDA for our Sands Hill segment was negligible for the year ended December 31, 2007. We acquired the Sands Hill operation in December 2007. For our Other segment, EBITDA for the year ended December 31, 2007 was $1.3 million as compared to a negative $0.6 million for the year ended December 31, 2006. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

Year Ended December 31, 2007 Compared to Nine Months Ended December 31, 2006

Summary. We sold 8.2 million tons of coal for the year ended December 31, 2007 as compared to 6.2 million tons of coal sold for the nine months ended December 31, 2006. Our coal revenues were $394.1 million for the year ended December 31, 2007 as compared to $294.3 million for the nine months ended December 31, 2006. Net income for the year ended December 31, 2007 was $30.7 million as compared to $3.1 million for the nine months ended December 31, 2006. EBITDA was $66.9 million in 2007 as compared to $38.2 million for the nine months ended December 31, 2006. The increase in coal revenues, net income and EBITDA was primarily due to the additional three months of operations for the year ended December 31, 2007. Our 2007 results were also positively impacted by higher coal revenues per ton for both steam and metallurgical coal and by our successful efforts to control our cost of operations.

Tons Sold. The following table presents tons of coal sold by reportable segment for the nine months ended December 31, 2006 and the year ended December 31, 2007:

Segment	Nine Months Ended December 31, 2006	Year Ended December 31, 2007
	(in millions)
Central Appalachia	4.8	6.6
Northern Appalachia	1.2	1.3
Sands Hill	n/a	—
Other	0.2	0.3

Total	6.2	8.2

Tons of coal sold was 8.2 million tons for the year ended December 31, 2007 as compared to 6.2 million tons for the nine months ended December 31, 2006. We produced 7.1 million tons of coal and purchased 1.0 million tons of coal for the year ended December 31, 2007 as compared to producing and selling 6.2 million tons of coal for the nine months ended December 31, 2006. Tons of coal sold in our Central Appalachia segment was 6.6 million tons for the year ended December 31, 2007, which included the sale of 1.0 million tons of purchased coal and 0.1 million tons of coal sold from our inventory, as compared to 4.8 million tons for the nine months ended December 31, 2006. The increase in tons of coal sold in 2007 was due to higher demand for coal in the regions in which we operate and the additional three months of operations. For our Northern Appalachia segment, we sold 1.3 million tons of coal for the year ended December 31, 2007 as compared to 1.2 million tons for the nine months ended December 31, 2006. We operated two underground mines in our Northern Appalachia segment for all of 2006 as compared to only four months in 2007 due to the natural exhaustion of one mine. For our Other segment, the greater 0.1 million in tons of coal sold for the year ended December 31, 2007 was primarily a result of our increased production in the Western Bituminous Region.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the nine months ended December 31, 2006 and the year ended December 31, 2007:

	Nine Months Ended December 31, 2006				Increase/(Decrease)
Segment			Year Ended December 31, 2007		Increase/(Decrease)
Segment			Year Ended December 31, 2007		Dollars			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	246.4	$	337.4
Freight and handling revenues		0.1		1.1
Other revenues		1.3		1.1

Total revenues	$	247.8	$	339.6

Coal revenues per ton*	$	51.64	$	51.19	$	(0.45	)	(0.9	)%
Northern Appalachia
Coal revenues	$	41.7	$	48.7
Freight and handling revenues		1.4		1.3
Other revenues		2.3		3.4

Total revenues	$	45.4	$	53.4

Coal revenues per ton*	$	33.72	$	37.34	$	3.62		10.7	%
Sands Hill
Coal revenues		n/a	$	0.8
Freight and handling revenues		n/a		0.1
Other revenues		n/a		0.1

Total revenues		n/a	$	1.0

Coal revenues per ton*		n/a	$	37.97		n/a		n/a
Other
Coal revenues	$	6.2	$	7.2
Freight and handling revenues		1.3		1.6
Other revenues		0.1		0.7

Total revenues	$	7.6	$	9.5

Coal revenues per ton*	$	29.02	$	29.60	$	0.58		2.0	%
Total
Coal revenues	$	294.3	$	394.1
Freight and handling revenues		2.8		4.1
Other revenues		3.7		5.3

Total revenues	$	300.8	$	403.5

Coal revenues per ton*	$	47.31	$	48.30	$	0.99		2.1	%

*: 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, 2007 were $403.5 million as compared to $300.8 million for the nine months ended December 31, 2006. Our coal revenues were $394.1 million for the year ended December 31, 2007 as compared to $294.2 million for the nine months ended December 31, 2006, primarily due to an additional 2.0 million tons of coal sold for the year ended December 31, 2007, as a result of higher demand for coal in the regions in which we operate and the

additional three months of operations. Coal revenues per ton increased by 2.1% to $48.30 for the year ended December 31, 2007 from $47.31 for the nine months ended December 31, 2006, primarily as a result of favorable quality adjustments for coal sold that was above the specification under the supply contracts and improved market prices. For our Central Appalachia segment, coal revenues were $337.4 million for the year ended December 31, 2007 as compared to $246.4 million for the nine months ended December 31, 2006. The greater coal revenues in 2007 in Central Appalachia were partially due to an increase in tons of coal sold. Coal revenues per ton for our Central Appalachia segment decreased by $0.45 per ton for the year ended December 31, 2007, as compared to the nine months ended December 31, 2006, primarily due to lower spot coal prices for the period as a result of market conditions, partially offset by additional tons of metallurgical coal sold. For our Northern Appalachia segment, coal revenues were $48.7 million for the year ended December 31, 2007 as compared to $41.7 million for the nine months ended December 31, 2006. These greater coal revenues were primarily due to higher coal revenues per ton in Northern Appalachia, which increased by $3.62, or 10.7%, to $37.34 from $33.72 for the nine months ended December 31, 2006. The increase in coal revenues per ton for our Northern Appalachia segment was primarily due to coal contract sales prices that were $3.60 higher per ton for the year ended December 31, 2007 than for the nine months ended December 31, 2006. For our Sands Hill segment, coal revenues were $0.8 million for the year ended December 31, 2007. We acquired the Sands Hill operation in December 2007. For our Other segment, coal revenues were $7.2 million for the year ended December 31, 2007, as compared to $6.2 million for the nine months ended December 31, 2006. These greater coal revenues were due to additional production from our Western Bituminous operation as well as the additional three months of operations. Coal revenues per ton for our Other segment also increased, to $29.60 for the year ended December 31, 2007 from $29.02 per ton for the nine months ended December 31, 2006 due to an increase in coal contract sales prices.

Costs and Expenses. The following table presents costs and expenses, cost of operations per ton and cost of operations per ton produced by reportable segment for the nine months ended December 31, 2006 and the year ended December 31, 2007:

	Nine Months Ended December 31, 2006				Increase/(Decrease)
Segment			Year Ended December 31, 2007		Increase/(Decrease)
Segment			Year Ended December 31, 2007		Dollars			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	200.4	$	272.8
Freight and handling costs		0.1		1.2
Depreciation, depletion and amortization		24.6		24.5
Selling, general and administrative		13.9		11.2
Cost of operations per ton*	$	41.98	$	41.40	$	(0.58	)	(1.4	)%
Cost of operations per ton produced*	$	41.98	$	41.75	$	(0.23	)	(0.5	)%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	29.6	$	34.0
Freight and handling costs		1.4		1.2
Depreciation, depletion and amortization		3.1		4.2
Selling, general and administrative		3.7		3.0
Cost of operations per ton*	$	23.91	$	26.08	$	2.18		9.1	%
Cost of operations per ton produced*	$	23.91	$	26.08	$	2.18		9.1	%

Sands Hill
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		n/a	$	0.8
Freight and handling costs		n/a		0.1
Depreciation, depletion and amortization		n/a		0.1
Selling, general and administrative		n/a		0.1
Cost of operations per ton*		n/a	$	38.87
Cost of operations per ton produced*		n/a	$	38.87		n/a	n/a
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	8.2	$	10.8
Freight and handling costs		1.3		1.6
Depreciation, depletion and amortization		0.8		2.0
Selling, general and administrative		0.9		1.2
Cost of operations per ton*	$	38.68	$	44.48	$	5.80	15.0	%
Cost of operations per ton produced*	$	38.68	$	44.48	$	5.80	15.0	%
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	238.2	$	318.5
Freight and handling costs		2.8		4.0
Depreciation, depletion and amortization		28.5		30.8
Selling, general and administrative		18.6		15.4
Cost of operations per ton*	$	38.28	$	39.04	$	0.76	2.0	%
Cost of operations per ton produced*	$	38.28	$	39.00	$	0.72	1.9	%

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

Cost of Operations. Total cost of operations was $318.5 million for the year ended December 31, 2007 as compared to $238.2 million for the nine months ended December 31, 2006. The greater cost of operations was primarily due to the additional three months of operations for the year ended December 31, 2007. Cost of operations per ton for the year ended December 31, 2007 was $39.04, an increase of $0.76 per ton from $38.28 per ton for the nine months ended December 31, 2006, similar to cost of operations per ton produced. This increase was primarily due to increases in labor, royalty and operating supplies costs of $1.06, $0.93, $0.62 and $0.33 per ton, respectively, and the additional cost of purchased coal. The increases were offset by lower costs for outside services and trucking, which declined by $0.80 and $1.46 per ton, respectively, for the year ended December 31, 2007.

In our Central Appalachia segment, our cost of operations per ton decreased by $0.58, or 1.4%, to $41.40 per ton for the year ended December 31, 2007 from $41.98 per ton for the nine months ended December 31, 2006, similar to cost of operations per ton produced. The decrease was primarily due to lower costs for outside services, maintenance and trucking, which decreased by $0.78, $0.21 and $0.62 per ton, respectively. This decrease was offset by increases in royalty, operating supplies and labor costs, which were greater by $0.70, $0.32 and $0.28 per ton, respectively, for the year ended December 31, 2007. We produced 7.1 million tons of coal but sold 1.0 million tons of purchased coal and sold 0.1 million tons of coal from our inventory for the year ended December 31, 2007 as

compared to producing and selling 6.2 million tons of coal for the nine months ended December 31, 2006.

In our Northern Appalachia segment, our cost of operations per ton and cost of operations per ton produced increased to $26.08 for the year ended December 31, 2007 from $23.91 for the nine months ended December 31, 2006, an increase of $2.18 per ton, or 9.1%. This increase was primarily due to an increase in the cost of labor and benefits of $1.62 more per ton for the year ended December 31, 2007 from the cost of labor and benefits per ton for the nine months ended December 31, 2006.

In our Sands Hill segment, our cost of operations was $0.8 million and cost of operations per ton was $38.87 per ton for the year ended December 31, 2007. We acquired the Sands Hill operation in December 2007.

In our Other segment, our cost of operations was $10.8 million for the year ended December 31, 2007 as compared to $8.2 million for the nine months ended December 31, 2006. This increase was primarily due to costs of operations in our ancillary businesses.

Freight and Handling. Total freight and handling cost for the year ended December 31, 2007 was $4.0 million as compared to $2.8 million for the nine months ended December 31, 2006. The greater freight and handling cost was primarily due to the sale of an additional 2.0 million tons of coal for the year ended December 31, 2007 as compared to the nine months ended December 31, 2006.

Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2007 was $30.8 million as compared to $28.5 million for the nine months ended December 31, 2006. This greater DD&A expense was primarily due to additional asset depreciation of $8.2 million and $1.4 million greater retirement cost amortization, offset by $3.8 million less in depletion and $3.8 million less in amortization of developmental costs.

Selling, General and Administrative. Total SG&A expense for the year ended December 31, 2007 was $15.4 million as compared to $18.5 million for the nine months ended December 31, 2006. The decrease was primarily due to the consolidation of SG&A expense at the Hopedale operation in Northern Appalachia as a result of reducing from two operating mines in 2006 to one operating mine in 2007.

Interest Expense. Interest expense for the year ended December 31, 2007 was $5.6 million as compared to $6.5 million for the nine months ended December 31, 2006. Our ability to reduce our debt level resulted in a lower interest expense. Please read "—Liquidity and Capital Resources" for more information.

Income Tax Expense/Benefit. Income tax benefit was $0.1 million for the year ended December 31, 2007 as compared to an expense of $0.1 million for the nine months ended December 31, 2006. This income tax expense for the nine months ended December 31, 2006 was a result of the state of Kentucky instituting a law effective January 1, 2005 that required partnerships to pay state income taxes. This law was repealed effective January 1, 2007, which resulted in an accrual of income tax benefit of $0.1 million for the year ended December 31, 2007.

Net Income/Loss. The following table presents net income/loss by reportable segment for the nine months ended December 31, 2006 and the year ended December 31, 2007:

Segment	Nine Months Ended December 31, 2006			Year Ended December 31, 2007
	(in millions)
Central Appalachia	$	(0.2	)	$	23.1
Northern Appalachia		5.2			9.1
Sands Hill		n/a			(0.2	)
Other		(1.9	)		(1.3	)

Total	$	3.1		$	30.7

For the year ended December 31, 2007, total net income was $30.7 million as compared to $3.1 million for the nine months ended December 31, 2006. This higher income was due to the three additional months of operations, as well as higher coal sales, lower SG&A expense, lower DD&A expense, lower interest and income tax expenses, gains on sales of assets and on the retirement of advance royalties. Purchasing coal, instead of producing the purchased tons of coal, had the effect of decreasing net income by approximately $0.4 million for the year ended December 31, 2007 and had no impact on net income for the nine months ended December 31, 2006. In addition, in October 2006, our lease for the Bolt field in West Virginia was cancelled, resulting in a write-off of $2.1 million. In February 2008, we re-entered into a lease with respect to the Bolt field, which our joint venture acquired in May 2008. For our Central Appalachia segment, net income was $23.1 million for the year ended December 31, 2007 as compared to a net loss of $0.2 million for the nine months ended December 31, 2006. Net income in our Northern Appalachia segment was also greater for the year ended December 31, 2007, at $9.1 million as compared to $5.2 million for the nine months ended December 31, 2006, primarily due to greater coal revenues. Our Sands Hill segment had a net loss of $0.2 million for the year ended December 31, 2007. We acquired the Sands Hill operation in December 2007. Net loss in our Other segment was $1.3 million for the year ended December 31, 2007 as compared to $1.9 million for the nine months ended December 31, 2006.

EBITDA. The following table presents EBITDA by reportable segment for the nine months ended December 31, 2006 and the year ended December 31, 2007:

Segment	Nine Months Ended December 31, 2006			Year Ended December 31, 2007
	(in millions)
Central Appalachia	$	29.1		$	51.6
Northern Appalachia		9.3			14.0
Sands Hill		n/a			—
Other		(0.3	)		1.3

Total	$	38.2		$	66.9

EBITDA was higher for the year ended December 31, 2007 as compared to the nine months ended December 31, 2006 as a result of higher coal revenues per ton as well as lower costs, such as SG&A expense and outside services cost, and also the three additional months of operations. Total EBITDA was $66.9 million for the year ended December 31, 2007 as compared to $38.2 million for the nine months ended December 31, 2006. EBITDA for our Central Appalachia segment of $51.6 million for the year ended December 31, 2007 as compared to $29.1 million for the nine months ended December 31, 2006 was due to higher coal revenues and lower cost of operations. The higher EBITDA for our Northern Appalachia segment of $14.0 million for the year ended December 31, 2007, as compared to $9.3 million for the nine months ended December 31, 2006, was primarily due to greater coal revenues. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

Nine Months Ended December 31, 2006 Compared to the Year Ended March 31, 2006

Summary. Coal revenues for the nine months ended December 31, 2006 were $294.3 million as compared to $351.3 million for the year ended March 31, 2006. The additional coal revenues were due to the three fewer months of operations, offset by higher coal revenues per ton for our steam coal and increased production and sales. Net income for the nine months ended December 31, 2006 was $3.1 million as compared to $31.7 million for the year ended March 31, 2006. EBITDA was $38.2 million for the nine months ended December 31, 2006 as compared to $50.5 million for the year ended March 31, 2006. Net income and EBITDA for the nine months ended December 31, 2006 were both adversely impacted by the shorter operating period, higher SG&A expense, higher cost of operations, including higher commodity prices such as diesel fuel and explosives.

Tons Sold. The following table presents tons of coal sold by reportable segment for the year ended March 31, 2006 and the nine months ended December 31, 2006:

Segment	Year Ended March 31, 2006	Nine Months Ended December 31, 2006
	(in millions)
Central Appalachia	6.3	4.8
Northern Appalachia	1.4	1.2
Other	0.2	0.2

Total	7.9	6.2

Total tons of coal sold and produced was 6.2 million tons for the nine months ended December 31, 2006 as compared to 7.9 million tons for the year ended March 31, 2006. This decrease was due to the three fewer months of operations.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the year ended March 31, 2006 and the nine months ended December 31, 2006:

	Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Increase/(Decrease)
Segment	Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Dollars		%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	302.4	$	246.4
Freight and handling revenues		1.5		0.1
Other revenues		3.2		1.3

Total revenues	$	307.1	$	247.8

Coal revenues per ton*	$	48.29	$	51.64	$	3.35	6.9	%
Northern Appalachia
Coal revenues	$	42.4	$	41.7
Freight and handling revenues		3.4		1.4
Other revenues		3.1		2.3

Total revenues	$	48.9	$	45.4

Coal revenues per ton*	$	30.50	$	33.72	$	3.23	10.6	%

Other
Coal revenues	$	6.5	$	6.2
Freight and handling revenues		1.3		1.3
Other revenues		0.1		0.1

Total revenues	$	7.9	$	7.6

Coal revenues per ton*	$	26.46	$	29.02	$	2.56	9.7	%
Total
Coal revenues	$	351.3	$	294.3
Freight and handling revenues		6.2		2.8
Other revenues		6.4		3.7

Total revenues	$	364.0	$	300.8

Coal revenues per ton*	$	44.48	$	47.31	$	2.83	6.4	%

*: 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 nine months ended December 31, 2006 were $300.8 million as compared to $364.0 million for the year ended March 31, 2006. Coal revenues were $294.3 million for the nine months ended December 31, 2006 as compared to $351.3 million for the year ended March 31, 2006. The lower revenues were primarily due to a decrease in coal sales as a result of the three fewer months of operations. Coal revenues per ton increased to $47.31 per ton for the nine months ended December 31, 2006 from $44.48 per ton for the year ended March 31, 2006. For our Central Appalachia segment, coal revenues per ton increased to $51.64 for the nine months ended December 31, 2006, an increase of $3.35, or 6.9%, from the year ended March 31, 2006, due to strong market demand in the region. For our Northern Appalachia segment, market demand was also strong, causing coal revenues per ton to increase by $3.23, or 10.6%, to $33.72 for the nine months ended December 31, 2006. Similarly, our Other segment benefited from an increase in coal prices, and the coal revenues per ton increased 9.7% to $29.02 for the nine months ended December 31, 2006.

Costs and Expenses. The following table presents total costs and expenses, cost of operations per ton and cost of operations per ton produced by reportable segment for the year ended March 31, 2006 and the nine months ended December 31, 2006:

	Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Increase/(Decrease)
Segment	Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Dollars		%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	249.1	$	200.4
Freight and handling costs		1.6		0.1
Depreciation, depletion and amortization		11.0		24.6
Selling, general and administrative		13.1		13.9
Cost of operations per ton*	$	39.77	$	41.98	$	2.22	5.6	%
Cost of operations per ton produced*	$	39.77	$	41.98	$	2.22	5.6	%

Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	35.0	$	29.6
Freight and handling costs		3.4		1.4
Depreciation, depletion and amortization		2.5		3.1
Selling, general and administrative		3.3		3.7
Cost of operations per ton*	$	25.14	$	23.91	$	(1.23	)	(4.9	)%
Cost of operations per ton produced*	$	25.14	$	23.91	$	(1.23	)	(4.9	)%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	7.4	$	8.2
Freight and handling costs		1.4		1.3
Depreciation, depletion and amortization		0.3		0.8
Selling, general and administrative		0.7		0.9
Cost of operations per ton*	$	30.07	$	38.68	$	8.61		28.6	%
Cost of operations per ton produced*	$	30.07	$	38.68	$	8.61		28.6	%
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	291.5	$	238.2
Freight and handling costs		6.3		2.8
Depreciation, depletion and amortization		13.8		28.5
Selling, general and administrative		17.1		18.5
Cost of operations per ton*	$	36.89	$	38.28	$	1.39		3.8	%
Cost of operations per ton produced*	$	36.89	$	38.28	$	1.39		3.8	%

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

Cost of Operations. Total cost of operations was $238.2 million for the nine months ended December 31, 2006 as compared to $291.5 million for the year ended March 31, 2006. This lower cost was primarily due to the three fewer months of operations.

Cost of operations per ton and cost of operations per ton produced increased by $1.39, or 3.8%, for the nine months ended December 31, 2006 from the year ended March 31, 2006. The higher cost of operations per ton was primarily due to increases in purchased coal, which increased by $1.09 per ton and the cost of operating supplies, which increased by $0.88 per ton, offset by decreased maintenance cost of $0.22 per ton.

In our Central Appalachia segment, the cost of operations per ton and cost of operations per ton produced increased by $2.22, or 5.6%, to $41.98 per ton for the nine months ended December 31, 2006 from $39.77 per ton for the year ended March 31, 2006. The increase was primarily due to rising costs of operating supplies, contract mining, equipment rental and lease, and outside services, which increased by $0.90, $0.49, $0.47 and $0.23 per ton, respectively.

In our Northern Appalachia segment, our cost of operations per ton and cost of operations per ton produced declined to $23.91 per ton for the nine months ended December 31, 2006 from $25.14 for the year ended March 31, 2006, a decrease of $1.23 per ton, or 4.9%. This decrease was primarily due to lower labor and employee-benefits cost of $0.78 per ton and lower maintenance costs of $0.40 per ton.

In our Other segment, cost of operations was greater for the nine months ended December 31, 2006 than for the year ended March 31, 2006, primarily due to costs associated with the drilling, exploration and other development of our mining operations of $1.8 million.

Freight and Handling. Total freight and handling cost was $2.8 million for the nine months ended December 31, 2006 as compared to $6.3 million for the year ended March 31, 2006. This lower cost was primarily due to the three fewer months of operations and 1.7 million fewer tons of coal sold.

Depreciation, Depletion and Amortization. Total DD&A expense was $28.5 million for the nine months ended December 31, 2006, as compared to $13.8 million for the year ended March 31, 2006. This increase in DD&A expense was due to additional amortization of $5.5 million for development costs related to our Central Appalachia and Western Bituminous operations, $4.6 million decrease in amortization cost adjustment associated with coal sales contract liabilities due to fewer tons shipped and $4.3 million of additional depletion.

Selling, General and Administrative. Total SG&A expense was $18.5 million for the nine months ended December 31, 2006 as compared to $17.1 million for the year ended March 31, 2006. This lower SG&A expense was primarily due to lower corporate expense allocation.

Interest Expense. Interest expense was $6.5 million for the nine months ended December 31, 2006, due to our assumption of additional debt for mine development expenses, as compared to $5.0 million for the year ended March 31, 2006.

Income Tax Expense. Income tax expense, related to state income taxes, was flat at $0.1 million for the nine months ended December 31, 2006 and for the year ended March 31, 2006.

Net Income/Loss. The following table presents net income/loss by reportable segment for the year ended March 31, 2006 and the nine months ended December 31, 2006:

Segment	Year Ended March 31, 2006		Nine Months Ended December 31, 2006
	(in millions)
Central Appalachia	$	29.0	$	(0.2	)
Northern Appalachia		2.7		5.2
Other		—		(1.9	)

Total	$	31.7	$	3.1

Total net income was $3.1 million for the nine months ended December 31, 2006 as compared to $31.7 million for the year ended March 31, 2006. The lower net income was partially due to the three fewer months of operations. Cost of purchased coal did not impact net income for either period. In addition, in October 2006, our lease for the Bolt field in West Virginia was cancelled, resulting in a write-off of $2.1 million. In February 2008, we re-entered into a lease with respect to the Bolt field, which our joint venture acquired in May 2008. Net income was also adversely impacted by increases in DD&A expense of $14.7 million and SG&A expense of $1.5 million.

EBITDA. The following table presents EBITDA by reportable segment for the year ended March 31, 2006 and the nine months ended December 31, 2006:

Segment	Year Ended March 31, 2006		Nine Months Ended December 31, 2006
	(in millions)
Central Appalachia	$	44.3	$	29.1
Northern Appalachia		5.8		9.3
Other		0.4		(0.3	)

Total	$	50.5	$	38.2

Total EBITDA was $38.2 million for the nine months ended December 31, 2006 as compared to $50.5 million for the year ended March 31, 2006. This lower EBITDA was due to the three fewer months of operations. Our EBITDA for the nine months ended December 31, 2006 was also adversely affected by additional $1.5 million of SG&A expense as well as the development cost for our Western Bituminous operation. Please read "—Reconciliation of EBITDA to Net Income by Segment" for reconciliations of EBITDA to net income on a segment basis.

Reconciliation of EBITDA to Net Income by Segment

EBITDA represents net income from operations before deducting interest expense, depreciation, depletion and amortization, and income taxes. EBITDA is used by management primarily as a measure 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 March 31, 2006	Central Appalachia		Northern Appalachia		Other		Total
	(in millions)
Net income	$	29.0	$	2.7	$	—	$	31.7
Plus:
Depreciation, depletion and amortization		11.0		2.5		0.3		13.8
Interest expense		4.2		0.6		0.2		5.0
Income tax expense		0.1		—		—		0.1

EBITDA	$	44.3	$	5.8	$	0.4	$	50.5

Nine Months Ended December 31, 2006	Central Appalachia			Northern Appalachia		Other			Total
	(in millions)
Net income (loss)	$	(0.2	)	$	5.2	$	(1.9	)	$	3.1
Plus:
Depreciation, depletion and amortization		24.6			3.1		0.8			28.5
Interest expense		4.5			1.0		0.9			6.5
Income tax expense (benefit)		0.2			—		(0.1	)		0.1

EBITDA	$	29.1		$	9.3	$	(0.3	)	$	38.2

Year Ended December 31, 2006	Central Appalachia		Northern Appalachia		Other			Total
	(in millions)
Net income (loss)	$	7.9	$	6.7	$	(2.5	)	$	12.0
Plus:
Depreciation, depletion and amortization		29.0		3.8		0.9			33.7
Interest expense		5.5		1.0		1.1			7.6
Income tax expense (benefit)		0.3		0.1		(0.1	)		0.3

EBITDA	$	42.7	$	11.6	$	(0.6	)	$	53.7

Year Ended December 31, 2007	Central Appalachia			Northern Appalachia		Sands Hill			Other			Total
	(in millions)
Net income (loss)	$	23.1		$	9.1	$	(0.2	)	$	(1.3	)	$	30.7
Plus:
Depreciation, depletion and amortization		24.5			4.2		0.1			2.0			30.8
Interest expense		4.1			0.8		—			0.6			5.6
Income tax (benefit)		(0.1	)		—		—			—			(0.1	)

EBITDA	$	51.6		$	14.0	$	—		$	1.3		$	66.9

Six Months Ended June 30, 2007	Central Appalachia			Northern Appalachia		Other			Total
	(in millions)
Net income	$	12.9		$	4.4	$	(0.5	)	$	16.8
Plus:
Depreciation, depletion and amortization		11.6			2.0		0.7			14.3
Interest expense		2.4			0.4		0.3			3.1
Income tax expense		(0.1	)		—		—			(0.1	)

EBITDA	$	26.7		$	6.8	$	0.6		$	34.1

Six Months Ended June 30, 2008	Central Appalachia		Rhino Eastern		Northern Appalachia		Sands Hill			Other		Total
	(in millions)
Net income	$	12.8	$	—	$	7.3	$	(2.0	)	$	0.1	$	18.2
Plus:
Depreciation, depletion and amortization		12.1		—		2.4		1.3			1.4		17.2
Interest expense		1.6		—		0.4		0.2			0.3		2.6
Income tax expense		—		—		—		—			—		—

EBITDA	$	26.6	$	—	$	10.1	$	(0.5	)	$	1.8	$	38.0

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental 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 primary sources of liquidity to meet these needs are cash generated by our operations, borrowings under our credit facility and equity offerings. Furthermore, we expect to pay a dividend of between $ and $ per share per year from cash from operations. Historically, we have generated sufficient cash from operations to pay a $ per share annual dividend beginning April 1, 2005.

The principal indicators of our liquidity are our cash on hand and availability under our credit facility. As of June 30, 2008, our available liquidity was $98.4 million, including cash on hand of $1.2 million and $97.2 million available under our credit facility. As of June 30, 2008, we had $22.8 million in letters of credit outstanding, of which $20.7 million served as collateral for surety bonds.

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

Cash Flows

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007. Net cash provided by operating activities was $45.4 million for the six months ended June 30, 2008 as compared to $26.9 million for the six months ended June 30, 2007. The increase was due to higher net income of $1.4 million, a decrease in net operating assets of $13.4 million and a decrease in non-cash charges of $3.6 million.

For the six months ended June 30, 2008, net cash used in investing activities was $53.2 million as compared to $2.9 million for the six months ended June 30, 2007. The increase was primarily due to the acquisitions of the Deane mining complex and the Eagle joint venture.

Net cash provided by financing activities was $5.4 million for the six months ended June 30, 2008 as compared to net cash used in financing activities of $21.3 million for the six months ended June 30, 2007. We borrowed $13.3 million more for the six months ended June 30, 2008 as compared to the same period in 2007. In addition, this net decrease was due to the fact that we paid down $15.5 million less on our debt. The $15.5 million was instead used primarily to fund acquisitions.

Year Ended December 31, 2007 Compared to the Nine Months Ended December 31, 2006. Net cash provided by operating activities was $52.5 million for the year ended December 31, 2007 as compared to $36.9 million for the nine months ended December 31, 2006. This increase was due to an increase in net income of $27.7 million, which was offset by an increase in net operating assets and liabilities of $9.7 million and an increase in non-cash charges of $2.4 million. The additional cash required for operating assets and liabilities for the year ended December 31, 2007 as compared to the nine months ended December 31, 2006 was primarily due to the following factors:

•: Because of a change in our trade accounts receivable, our use of cash was $19.1 million greater for the year ended December 31, 2007 than for the nine months ended December 31, 2006. Total revenues increased by 34% for the year ended December 31, 2007 as compared to the nine months ended December 31, 2006. Our days sales outstanding as of December 31, 2007 was 37.5 days, an increase of 9.5 days from our days sales outstanding as of December 31, 2006, due to increased sales late in the fourth quarter of 2007. In addition, aged accounts receivable totaling $1.1 million from two of our customers were settled in early 2007. There were no changes in our credit or collection terms or policies during the two periods, and those events had no material impact on our liquidity.
•: The change in accounts payable and other current accrued liabilities provided $13.4 million more in cash for the year ended December 31, 2007 as compared to the nine months ended December 31, 2006. The change in these liabilities resulted in a use of cash of $8.8 million for the nine months ended December 31, 2006, while the change in these liabilities resulted in a use of cash of $4.6 million for the year ended December 31, 2007.
•: The cash required for asset retirement obligations increased by $5.8 million for the year ended December 31, 2007 as compared to the nine months ended December 31, 2006, primarily due to reclamation projects during 2007.

Net income for the year ended December 31, 2007 was $27.7 million greater, as compared to the nine months ended December 31, 2006, primarily as a result of coal revenues per ton that were higher by $0.99 and the sale of 1.0 million tons of purchased coal. Our interest expense was also $0.9 million lower for the year ended December 31, 2007.

For the year ended December 31, 2007, net cash used in investing activities was $28.1 million as compared to $28.8 million for the nine months ended December 31, 2006. We invested cash of $32.8 million in mining equipment and coal properties for the year ended December 31, 2007 as compared to $32.7 million for the nine months ended December 31, 2006. Proceeds from the sales of assets were $4.5 million for the year ended December 31, 2007 as compared to $0.4 million for the nine months ended December 31, 2007 due to the sale of certain excess equipment during 2007. We received $0.3 million as payment on notes receivables during the year ended December 31, 2007 as compared to $2.0 million during the nine months ended December 31, 2006.

Net cash used by financing activities was $21.2 million for the year ended December 31, 2007 as compared to $9.1 million for the nine months ended December 31, 2006. In 2007, we had sufficient cash provided by operations to finance a larger portion of our growth and relied less on financing activities. In 2007, we borrowed $13.4 million more than the nine months in 2006, but paid back an additional $16.2 million of the debt as compared to the nine months ended December 31, 2006. We also distributed $9.3 million to equity holders during the year ended December 31, 2007, but did not make any distributions during the nine months ended December 31, 2006.

Nine Months Ended December 31, 2006 Compared to the Year Ended March 31, 2006. Net cash provided by operating activities was $36.9 million for the nine months ended December 31, 2006 as compared to $32.9 million for the year ended March 31, 2006. This greater amount was due to less net income of $28.6 million, offset by less net operating assets and liabilities of $15.6 million and less non-cash charges of $17.0 million.

Net cash used in investing activities for the nine months ended December 31, 2006 was $28.8 million for the development of new mining areas, the purchase of additional coal reserves and the replacement and expansion of our mining equipment fleet as compared to $34.6 million in the year ended March 31, 2006. We used an additional $3.7 million for the year ended March 31, 2006 as compared to the nine months ended December 31, 2006 for equipment and asset acquisitions. Proceeds from asset sales were $0.4 million for the nine months ended December 31, 2006 as compared to $0.7 million for the year ended March 31, 2006. Investing activities in the nine months ended December 31, 2006 also included cash received of $2.0 million as payment on a note receivable as compared to $0.1 million cash received for the year ended March 31, 2006.

Net cash used in financing activities was $9.1 million for the nine months ended December 31, 2006 as compared to net cash provided by financing activities of $1.9 million for the year ended March 31, 2006. For the year ended March 31, 2006, we had sufficient cash provided by operating activities to finance a larger portion of our growth and relied less on financing activities. We made an additional $7.2 million debt payment for the year ended March 31, 2006 compared to the nine months ended December 31, 2006.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amount of our contractual obligations as of December 31, 2007 were as follows:

		Payments Due by Period
		Total		Less than 1 Year		1–3 Years		4–5 Years		More than 5 Years
		(in thousands)
Long-term debt obligations (including interest)⁽¹⁾		$	84,276	$	10,162	$	2,721	$	69,000	$	2,394
Asset retirement obligations			36,387		2,582		10,072		2,219		21,514
Operating lease obligations⁽²⁾			23,417		7,788		7,236		2,250		6,143
Diesel fuel obligations			18,024		15,686		2,338		—		—
Advance royalties⁽³⁾			16,100		2,315		3,804		2,971		7,010
Retiree medical obligations			5,564		92		385		776		4,311

	Total	$	183,768	$	38,625	$	26,556	$	77,216	$	41,372

(1): Assumes a current LIBOR of 5.20% 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.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. For the year ending December 31, 2008, we have budgeted $47.3 million in capital expenditures. We believe that we have sufficient liquid assets, cash flows from operations, borrowing capacity under our credit facility and the ability to offer our equity 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.

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 facility. 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 June 30, 2008, we had $22.8 million in letters of credit outstanding, of which $20.7 million served as collateral for surety bonds.

Credit Facility

Rhino Energy LLC, our wholly owned subsidiary, as borrower, and our operating subsidiaries, as guarantors, are parties to our $200.0 million credit facility, which is available to repay indebtedness as well as for general business 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. We expect to amend our credit facility in connection with this offering.

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 our subsidiaries CAM Mining LLC, CAM-BB LLC, CAM-Kentucky Real Estate LLC, Rhino Northern Holdings LLC, CAM Coal Trading LLC, Leesville Land, LLC, CAM Aircraft LLC, Hopedale Mining LLC, CAM-Ohio Real Estate LLC, Springdale Land, LLC, Taylorville Mining LLC, Clinton Stone LLC, McClane Canyon Mining LLC, Rhino Coalfield Services LLC, Deane Mining LLC, Reserve Holdings LLC, CAM-Colorado LLC, Rhino Trucking LLC, Rhino Oilfield Services LLC, Rhino Exploration LLC and Rhino Services LLC.

Our credit facility bears interest at either (1) LIBOR plus 1.25% to 1.75% per annum, depending on our leverage ratio, or (2) a base rate that is the higher of the prime rate or the federal funds rate plus 0.50%. We incur letter of credit fees equal to the then applicable spread above LIBOR on the undrawn face amount of standby letters of credit issued 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 facility at a rate of 0.25% per annum based on the unused portion of the facility. The credit facility will mature in 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.

The credit agreement prohibits us from declaring dividends if any potential default or event of default, as defined in the credit agreement, occurs or would result from such dividend. In addition, the credit agreement contains various covenants that may limit, among other things, our ability to:

•: incur additional indebtedness or guarantee other indebtedness;
•: grant liens;
•: make certain loans or investments;
•: dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;
•: change the line of business conducted by us or our subsidiaries;
•: enter into a merger, consolidation or make acquisitions; or
•: declare dividends if an event of default occurs.

The credit agreement also contains financial covenants requiring us to maintain:

•: a maximum leverage ratio of debt to trailing four quarters EBITDA (as defined in the credit agreement) of 3.0 to 1.0; and
•: a minimum interest coverage ratio of EBITDA (as defined in the credit agreement) to interest expense for the trailing four quarters of 4.0 to 1.0.

If an event of default exists under the credit agreement, the lenders are able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following could be an event of default:

•: failure to pay principal, interest or any other amount when due;
•: breach of the representations or warranties;
•: failure to comply with the covenants in the credit agreement;
•: cross-default to other indebtedness;
•: bankruptcy or insolvency;
•: failure to have adequate resources to maintain and obtain operating permits as necessary to conduct operations substantially as contemplated by the mining plans used in preparing the financial projections; and
•: a change of control.

As of June 30, 2008, we had borrowings outstanding under our credit facility of approximately $80.0 million and $22.8 million of letters of credit in place.

Impact of Inflation

Since mid-2005, we have been materially impacted by inflation in some steel products for roof support used in our underground mining. Petroleum-based products such as diesel fuel and lubricants and products related to natural gas such as ammonia nitrate have all increased significantly.

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 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. Actual results may differ from the estimates used. Note 2 to the historical consolidated financial statements of Rhino Energy LLC provides a summary of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.

Revenue Recognition

Coal revenues result primarily from long-term sales contracts with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenues are recognized on coal sales in accordance with the terms of the sales agreement, which is when the coal is shipped to the customer and title has passed. Advance payments received are deferred and recognized in revenue as coal is shipped and title has passed.

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

Other revenues consist of limestone sales, coal handling, royalties, contract mining 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 apply the relevant accounting literature as appropriate, 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 collectability is reasonably assured. Advance payments received are deferred and recognized in revenue as coal is shipped or rental income is earned.

Reserves and Non-Reserve Deposits

Marshall Miller & Associates, Inc. ("Marshall Miller") prepared a detailed study of our coal reserves and non-reserve coal deposits for the Tug River mining complex, Rob Fork mining complex, Hopedale mining complex, Leesville field, Springdale field, Taylorville field and McClane Canyon mine as of October 31, 2007; the Deane mining complex as of the acquisition date, February 8, 2008; the Bolt field as of the lease date, February 15, 2008; and the Sands Hill mining complex as of the acquisition date, December 14, 2007. John T. Boyd Company ("Boyd") prepared a detailed study of our coal reserves for the Eagle mining complex as of the acquisition date, May 13, 2008 based on all of our geologic information, including our most recent drilling and mining data. The studies conducted by Marshall Miller and Boyd were planned and performed to obtain reasonable assurance of our subject demonstrated reserves and non-reserve coal deposits. In connection with the studies, Marshall Miller and Boyd prepared maps and had certified professional geologists develop estimates based on data supplied by us and using standards accepted by government and industry.

Based on the Marshall Miller and Boyd studies and the foregoing assumptions and qualifications, we estimate that, as of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007; and Eagle mining complex, which is as of the acquisition date, May 13, 2008), we owned, managed or leased 262.0 million tons of proven and probable coal reserves and 126.5 million tons of non-reserve coal deposits. Please read "Business—Coal Reserves and Non-Reserve Coal Deposits."

This estimate bears the risk of change as we could encounter an unknown geologic change in the coal reserves we control or if for some reason we could not gain control of the non-reserve coal deposits. Due to the extensive knowledge of the coal reserves possessed by our third-party engineering firms, we have not encountered any major discrepancies in our estimated versus actual coal reserves. We do not believe that the estimate of coal reserves or non-reserve coal deposits is likely to change based on our past experience.

As of December 14, 2007, as confirmed by Marshall Miller, all of the 21.6 million tons of proven and probable limestone reserves were assigned reserves, which are limestone reserves that can be mined without a significant capital expenditure for mine development. In addition, we control 3.7 million tons of non-reserve limestone deposits. Please read "Business—Limestone."

Reclamation

Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon third-party costs. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of SFAS No. 143, we determine the fair value of our asset

retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:

•: Discount rate. SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
•: Third-party margin. SFAS No. 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.

On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures and revisions to cost estimates and productivity assumptions to reflect current experience. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2007, we estimate that the aggregate undiscounted cost of final mine closure is approximately $49.0 million. As of December 31, 2007, we had recorded asset retirement obligations of $36.4 million. As of June 30, 2008, we had recorded asset retirement obligation liabilities of $52.8 million, including amounts reported as current liabilities.

This estimate bears the risk of change as we are subject to changing laws at the federal and state level, which could affect the cost of reclaiming disturbed areas at our mines. In addition, the cost of reclamation is discounted in accordance with SFAS No. 143. Our discount rate is subject to change due to being based on treasury bonds with maturities similar to expected mine lives. The cost of this work could also be impacted by unexpected inflation in cost associated with this activity. Third parties that are familiar with the current laws governing this activity and with the cost to perform this work prepared the reclamation estimate. To mitigate any long-term effects, these estimates are adjusted on at least an annual basis and the estimate is adjusted accordingly. In prior years, we have found the cost of reclamation to be reasonably close to the revised studies as these estimates are updated. For these reasons, we do not believe that the estimate of work to be performed or the cost of the work is likely to materially change and, therefore, we do not believe that this estimate will materially change.

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.

Coal properties are depleted using the units-of-production method, based on estimated recoverable reserves. The coal land's fair values are established by either using third party mining engineering consultants or market values as established when coal lands are purchased on the open market. These values are then evaluated as to the number of recoverable tons contained in a particular mining area. Once the coal land values are established, and the number of recoverable tons contained in a particular coal land area is determined, a "units of production" depletion rate can be calculated. This rate is then utilized to calculate depletion expense for each period mining is conducted on a particular coal lands area.

Any uncertainty surrounding the application of the depletion policy is directly related to the assumptions as to the number of recoverable tons contained in a particular coal land area. The amount of compensation paid for the coal lands is a set amount; however, the "recoverable tons" contained in the coal land area are based on third party engineering estimates, which can and often do change as the tons are mined. Any change in the number of "recoverable tons" contained in a coal land area will result in a change in the depletion rate and corresponding depletion expense. For the year ended December 31, 2007 and the six months ended June 30, 2008, we recorded $3.6 million and $1.9 million, respectively, of depletion expense. Assuming that "recoverable tons" are reduced by 10%, this would result in a decrease in pre-tax income of $0.4 million and $0.2 million for the year ended December 31, 2007 and the six months ended June 30, 2008, respectively. This calculation would also be applied in the case of a coal land area containing more "recoverable tons" than the original estimate. This would result in increased net income.

Mine development costs are amortized using the units-of-production method, based on estimated recoverable reserves in the same manner described above.

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.

This method bears the risk of change primarily due to changing estimates in coal reserves, which could affect the cost of depletion at our mines due to the cost associated with the coal lands being depleted by the "units of production method." As stated in the discussion above in "—Reserves and Non-Reserve Deposits" we do not believe that the life of the coal reserves will materially change and, therefore, we do not believe that this estimate is subject to material change.

Asset Impairments

We follow SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"), which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets. When the sum of projected cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, discounted cash flows are utilized to determine the fair value of the assets being evaluated. 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 asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized.

This method bears the risk of change primarily due to changing market situations, which could result in a lower selling price of coal and/or increase the cost of production at any individual mine site. We follow SFAS No. 144 to ensure that future cash flows from the use and disposition of assets are greater than carrying value of those assets. Historically, we have not experienced any material asset impairments that resulted in an impairment being recognized. We do not believe that this estimate is subject to material change.

Postretirement Benefits

Our Northern Appalachia segment has long and short-term liabilities for postretirement benefit cost obligations. Detailed information related to these liabilities is included in the notes to our consolidated financial statements included elsewhere in this prospectus. Liabilities for postretirement benefits are not funded. The liability is actuarially determined, and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for postretirement benefits. The discount rate assumption reflects the rates available on high quality fixed income debt instruments. The discount rate used to determine the net periodic benefit cost for

postretirement medical benefits was 5.6% for the six months ended June 30, 2007 and 6.25% for the six months ended December 31, 2007. We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injury and illness obligations. The future health care cost trend rate represents the rate at which health care costs are expected to increase over the life of the plan. The health care cost trend rate assumptions are determined primarily based upon our historical rate of change in retiree health care costs. The postretirement expense in the year ended December 31, 2007 was based on an assumed health care inflationary rate of 9.0% in the operating period decreasing to 5.0% in 2016, which represents the ultimate health care cost trend rate for the remainder of the plan life. A one-percentage point increase in the assumed ultimate health care cost trend rate would increase the accumulated postretirement benefit obligation at December 31, 2007 by $0.4 million. A one-percentage point decrease in the assumed ultimate health care cost trend rate would decrease the accumulated postretirement benefit obligation at December 31, 2007 by $0.4 million. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our requirement to satisfy these or additional obligations.

This method bears the risk of change primarily due to the liability being actuarially calculated. A change in various actuarial assumptions or change in future trends for health care costs could result in a material change in this liability. Historically, we have found these estimates to be accurate and we have not experienced any material adjustments to this liability. This liability is calculated by a third-party actuary and is adjusted on at least an annual basis. We do not believe that this estimate is subject to material change.

Income Taxes

Our predecessor was considered a partnership for income tax purposes. Accordingly, the members of Rhino Energy LLC reported their share of its taxable income or loss on their tax returns. The provisions for income tax consisted of state income tax for the year ended March 31, 2006 and for the nine months ended December 31, 2006. This provision was a result of the state of Kentucky instituting a law effective January 1, 2005 that required partnerships to pay state income tax. This law was rescinded on January 1, 2007, resulting in an income tax benefit for the year ended December 31, 2007. Following this offering, we will incur income taxes under our new corporate holding company structure, and our financial statements will reflect the actual impact of income taxes.

Recent Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board ("FASB") issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since we are not a taxable entity for federal and state income tax purposes, our adoption of FIN 48 on January 1, 2007 did not have a material impact on our consolidated financial statements. Following this offering, we will incur income taxes under our new corporate holding company structure, and our financial statements will reflect the actual impact of income taxes. We are currently evaluating the effect FIN 48 will have on our consolidated financial statements as a corporation following this offering.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measures ("SFAS No. 157"), which establishes a framework for measuring fair value and expands disclosures about fair value measurements. Pursuant to FASB Financial Staff Position 157-2, the FASB issued a partial deferral of the implementation of SFAS No. 157 as it relates to all non-financial assets and liabilities where fair value is not already the required measurement attribute by other accounting standards. The remainder

of SFAS No. 157 was effective for us on January 1, 2008. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R) ("SFAS No. 158"). SFAS No. 158 requires the recognition of the funded status of a defined benefit plan in the statement of financial position, requires that changes in the funded status be recognized through comprehensive income, changes the measurement date for defined benefit plan assets and obligations to the entity's fiscal year-end and expands disclosures. The recognition and disclosures under SFAS No. 158 are required as of the end of fiscal years ending after December 15, 2006, while the new measurement date is effective for fiscal years ending after December 15, 2008. We adopted the recognition and disclosure provisions of SFAS No. 158 as of December 31, 2006 on the required prospective basis.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115 ("SFAS No. 159"). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. The fair value option may be applied on an instrument by instrument basis with certain exceptions. The election is irrevocable and must be applied to entire instruments and not to portions of instruments, thus the election to apply the standard and measure certain financial instruments at fair value would be effective prospectively beginning January 1, 2008. The adoption of SFAS No. 159 did not have a material impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (Revised), Business Combinations ("SFAS No. 141R"), and SFAS No. 160, Noncontrolling Interests in Combined Financial Statements ("SFAS No. 160"). SFAS No. 141R and SFAS No. 160 revise the method of accounting for a number of aspects of business combinations, including acquisition costs, contingencies (including contingent assets, contingent liabilities and contingent purchase price), the impacts of partial and step-acquisitions (including the valuation of net assets attributable to non-acquired minority interests), and post acquisition exit activities of acquired businesses. SFAS No. 141R and SFAS No. 160 will be effective for us on January 1, 2009.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133 ("SFAS No. 161"). SFAS No. 161 requires enhanced disclosures about an entity's derivative and hedging activities and thereby improves the transparency of financial reporting. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently evaluating the effect that adoption of SFAS No. 161 will have on our consolidated financial statements.

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 long-term coal supply agreements 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 fuel 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 $1.0 million for the year ended December 31, 2007 and by $0.6 million for the six months ended June 30, 2008. A

hypothetical increase of 10% in steel prices would have reduced net income by $0.9 million for the year ended December 31, 2007 and by $0.7 million for the six months ended June 30, 2008. A hypothetical increase of 10% in explosives prices would have reduced net income by $1.0 million for the year ended December 31, 2007 and by $0.6 million for the six months ended June 30, 2008.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit facility. 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 $0.7 million for the year ended December 31, 2007 and by $0.4 million for the six months ended June 30, 2008.

THE COAL INDUSTRY

Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel for the generation of electric power. World-wide recoverable coal reserves are estimated to be approximately 1.0 trillion tons. According to the EIA, the United States is one of the world's largest producers of coal and has approximately 27% of global coal reserves, representing approximately 244 years of supply based on current usage rates. Coal is the most abundant fossil fuel in the United States, representing the vast majority of the nation's total fossil fuel reserves.

Recent Coal Market Conditions and Trends

•: Continued strong demand in the United States. Domestic demand for steam coal from the electricity generating sector, continues to be strong, driven principally by growth in electricity sales, which are expected to increase by 34% from 2007 to 2030, as estimated by the EIA;
•: Growing export market. Coal producers in the Appalachian region of the United States are benefiting from growing demand for coal in Europe, Asia and other foreign markets. Total U.S. coal exports increased by approximately 19% from 2006 to 2007, according to the EIA. In particular, exports to Europe and Brazil have increased 30% and 44%, respectively, through December 2007 as compared to the same period in 2006, as reported by the EIA;
•: Proximity of eastern U.S. coal market. Eastern U.S. coal producers are also positioned to capitalize on the current favorable export market given their geographical proximity. Eastern U.S. coal producers have access to multiple modes of transportation within the United States, but are also located close to the coast, which provides access to transoceanic shipments. The total cost to purchase and ship coal from the East Coast of the United States to Europe is currently competitive with other coal exporting regions, as freight rates from the Pacific coal supply regions have increased significantly in recent months. Shipping costs from the eastern United States to western Europe, as measured by the Panamax Coal Voyage Spot Rates from Hampton Roads (VA) to the ARA (Antwerp-Rotterdam-Amsterdam) 70,000t, have ranged between $18.56 and $43.23 per ton since 2007;
•: U.S. transportation logistics. Constraints in the U.S. transportation system continue to persist. In particular, rail bottlenecks and rail maintenance downtime in the western United States have limited the coal produced in those regions, such as the Powder River Basin, from being transported and sold in the eastern end use markets;
•: Decline in production and reserve levels. Coal production in the eastern United States continues to decline. Based on the EIA's reported data for 2007 and reported data for 2006, production in the Appalachian region decreased 4% from 391.2 million tons in 2006 to 377.1 million tons in 2007. Not only has production declined, but coal reserves also continue to decline in the eastern United States regions. According to the EIA, as of December 31, 2006, total coal reserves in the Central Appalachia region are estimated to be 2,486 million tons, which is approximately 0.3% lower than the estimated 2,494 million tons at December 31, 2005; and
•: High prices for alternative energy sources. Coal continues to be the lowest cost source of energy relative to its substitutes. Spot prices as of June 30, 2008 for Henry Hub natural gas and New

York Harbor No. 2 heating oil were $13.19 per million Btu and $3.90 per gallon or $28.15 per million Btu, respectively, as reported by Bloomberg L.P. and the EIA. On the other hand, Central Appalachian spot coal prices, as measured by Big Sandy Barge 12,500 Btu, <3.0 lb SO2/MMBtu prices, reached $133.50 per ton on June 30, 2008, representing $5.34 per million Btu.

•: Demand for coal by emerging global economies, in particular China and India, continues to increase.
•: Traditional exporters of coal to Asia and other regions around the world are challenged to meet the growing demand for coal, which is creating export opportunities for other coal producers, particularly those located in the eastern United States.
•: The continued weakness of the U.S. dollar is also improving the competitiveness of U.S. exports.
•: Coal supply curtailment in Australia is causing Asian countries dependent on Australian coal to source coal from other places.

Coal Pricing

Steam Coal Pricing

Steam coal prices remained relatively flat through most of the mid-to-late 1990s. When long-term contracts for many producers began to expire in 2000 and beyond, new contracts were entered into reflecting then-current market demand and operating conditions. Coal prices increased significantly between 2000 and 2006, especially in the eastern regions of the United States. During 2006, mild weather conditions across the United States led to reduced electricity demand and higher coal inventory levels, resulting in a decline in spot steam coal prices. Electricity demand went from 1,027 short tons in 2006 to 1,046 short tons in 2007, while coal production in Appalachia declined by 3.6% compared to the same period in 2005. In 2007, the pricing environment for coal, eastern U.S. coal in particular, became extremely favorable as production remained low while demand increased. This momentum in the eastern U.S. coal markets has only increased in 2008.

Metallurgical Coal Pricing

Metallurgical coal prices in both the domestic and seaborne export markets have increased significantly over the past two to three years and remain strong due to tight supply and strong global steel production. The price increase in the U.S. metallurgical coal market is due in part to improved stability in the U.S. steel industry, which has increased domestic demand for metallurgical coal. The price increase in the U.S. metallurgical coal market has also been supported by tightening supply on the U.S. metallurgical coal supply side, where operating disruptions have reduced production at several U.S. metallurgical coal mines in recent years. High international prices for metallurgical coal also affected the price in the United States. The eastern regions of the United States profited most from the robust pricing environment, trending upward through late 2003 and into early 2008. High U.S.

demand for metallurgical coal worldwide and recent international logistical issues put a strain on already tight eastern supplies.

Coal Markets

NYMEX Market

In 1996, the New York Mercantile Exchange ("NYMEX") began providing companies in the electric power industry with secure and reliable risk management tools by creating a series of electricity futures contracts fashioned to meet the particular regional needs and practices of the power industry. The buying and selling of these futures contracts and the related options contracts provided the industry a price reference and risk management tool. In the restructured electric power industry, where the utility's ability to pass price increases along to customers was limited, the pricing of resources used to generate electricity became more important.

Since coal is the largest single power generating fuel in the United States, the once relatively stable cash markets became more volatile and subject to strong market forces. In response to dramatic changes in both electric and coal industry practices, NYMEX, after conferring with coal producers and consumers, sought and received regulatory approval to offer coal futures and options contracts to allow these parties to better manage this volatility. On July 12, 2001, NYMEX began trading Central Appalachian coal futures.

The Central Appalachian coal futures contract, which represents a 12,000 Btu per pound, 1% sulfur coal loaded in the barge on the Big Sandy River, is currently the only coal futures contract traded electronically on the NYMEX. The contract trades in one-barge increments of 1,550 tons. This contract was designed as a financial instrument to be settled on a monthly basis although it can be nominated for physical delivery.

Coal futures provide the electric power industry with another set of risk management options, as well as offer coal producers necessary risk management tools:

•: Coal producers can sell futures contracts to lock in a specific sales price for a specific volume of the coal they intend to produce in coming months;
•: Electric utilities can buy coal futures to hedge against rising prices for their base load fuel;
•: Power marketers, who mitigate their generation price risk exposure, can hedge with electricity futures to control their delivery price risk;
•: Non-utility industrial coal users, such as steel mills, can use futures to lock in their own coal supply costs;
•: International coal trading companies can use futures to hedge their export or import prices; and
•: Power generating companies that use both coal and natural gas to produce electricity can use coal futures in conjunction with natural gas futures to offset seasonal cost variations and to take advantage of the "spark spread"—the differential between the cost of the two fuels and the relative value of the electricity generated by each of the two fuels.

Over-The-Counter Market

The over-the-counter ("OTC") coal market developed in the United States in 1997 as a risk-management tool allowing electricity generators to manage their inherent short fuel position. The OTC coal market serves traders, producers, energy merchants and consumers of coal by bringing parties together to enter into instruments, including sale and purchase agreements for the physical delivery of coal, calls, puts and swaps, to hedge against price exposure and minimize the risks of volatility.

A variety of coals trade in the OTC market. However, the majority of the activity is based on Central Appalachia rail coals, NYMEX look-alike barge coals and Powder River Basin coals. Both barge and rail coals are actively traded in the eastern United States. A NYMEX look-alike product has the same quality and delivery specifications criteria of the NYMEX futures contract. As many coals originating from the Kanawha River mimic NYMEX specifications, prices are often quoted at a discount (or basis) to NYMEX or NYMEX look-alike. Central Appalachia trades in train loads of 10,000 tons for either 1% sulfur or compliance sulfur originating typically from either the Big Sandy or Kanawha freight districts on CSX Rail to the Kenova and Thacker freight districts on NS Rail. Contracts for Powder River Basin coal, which are for 8,400 and 8,800 Btus per pound, are traded actively. The market is largely physical and trades in train lots of 14,500 short tons.

Coal Characteristics

In general, coal of all geological composition is characterized by end use as either steam coal or metallurgical coal. Heat value and sulfur content are the most important variables in the profitable marketing and transportation of steam coal, while sulfur, ash and various coking characteristics are important variables in the profitable marketing and transportation of metallurgical coal.

Heat Value

The heat value of coal is commonly measured in Btus per pound of coal. A Btu is the amount of heat required to raise one pound of water one degree Fahrenheit. Coal found in the eastern and midwestern regions of the United States tends to have a heat content ranging from 10,000 to 14,000 Btus per pound, as received. As received Btus per pound includes the weight of moisture in the coal on an as sold basis. Most coal found in the western United States ranges from 8,000 to 10,000 Btus per pound, as received.

Sulfur Content

Sulfur content can vary from seam to seam and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus and complies with the requirements of the CAA. Low sulfur coal is coal which has a sulfur content of 1.0% or less.

High sulfur coal can be burned in electric utility plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 90%. Plants without sulfur-reduction technologies can burn high sulfur coal by blending it with lower sulfur coal, or by purchasing emission allowances on the open market, which credits allow the user to emit a ton of sulfur dioxide. More than 15,000 megawatts of coal-based generating capacity has been retrofitted with scrubbers since the beginning of Phase I of the CAA. Furthermore, utilities have announced plans to scrub an additional 66,000 megawatts by 2010. Additional scrubbing will provide new market opportunities for our medium sulfur coal. All new coal-fired generation plants to be built in the United States will use some form of emissions-control technology addressing sulfur and certain other substances emitted.

Other

Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel production. Moisture content of coal varies by the type of coal and the region where it is mined. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby

making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal's weight.

Coal Regions

Coal is mined from coal fields throughout the United States, with the major production centers located in the Appalachian Region, the Interior Region and the western United States. The quality of coal varies by region.

Appalachian Region

Northern Appalachia. Northern Appalachia includes Maryland, Ohio, Pennsylvania and northern West Virginia. Coal from this region generally has a heat value of between 10,500 and 13,500 Btu/lb. Its typical sulfur content ranges from 1.0% to 4.5%. We have one underground mine and two surface mines in Ohio and, as of October 31, 2007 (except for the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007) we controlled approximately 59.0 million tons of proven and probable coal reserves and approximately 54.2 million tons of non-reserve coal deposits in Northern Appalachia.

Central Appalachia. Central Appalachia includes eastern Kentucky, Virginia and southern West Virginia. Coal from this region generally has a sulfur content of 0.7% to 1.5% and a heat value of between 10,000 and 13,500 Btu/lb. We have nine underground mines and seven surface mines in Kentucky and West Virginia and, as of October 31, 2007 (except for the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Eagle mining complex, which is as of the acquisition date, May 13, 2008), controlled or managed approximately 99.1 million tons of proven and probable coal reserves and approximately 49.4 million tons of non-reserve coal deposits in Central Appalachia.

Southern Appalachia. Southern Appalachia includes Alabama and Tennessee. Coal from this region typically has a sulfur content of 0.7% to 1.5% and a heat value of between 11,500 and 12,500 Btu/lb.

Interior Region

Illinois Basin. The Illinois Basin includes Illinois, Indiana and western Kentucky and is the major coal production center in the interior United States. There has been significant consolidation among coal producers in the Illinois Basin over the past several years. Coal from this region varies in heat value from 10,000 to 12,500 Btu/lb and has a sulfur content of 2.0% to 4.0%. In this region, as of October 31, 2007, we controlled approximately 102.4 million tons of proven and probable coal reserves and approximately 22.9 million tons of non-reserve coal deposits.

Other Interior. Other coal-producing states in the interior United States include Arkansas, Kansas, Louisiana, Mississippi, Missouri, North Dakota, Oklahoma and Texas. The majority of production in the interior region outside of the Illinois Basin consists of lignite production from Texas and North Dakota. This lignite typically has a heat value of between 5,000 and 12,500 Btu/lb and a sulfur content of between 1.0% and 2.0%.

Western United States

Powder River Basin. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. This coal has a sulfur content of between 0.15% to 0.55% and a heat value of between 8,000 and 10,500 Btu/lb.

Western Bituminous Region. The Western Bituminous Region includes western Colorado and eastern Utah. The coal from this region typically has a sulfur content of 0.5% to 1.0% and a heat value of between 10,000 and 12,000 Btu/lb. In this region, as of October 31, 2007, we controlled approximately 1.5 million tons of proven and probable coal reserves. We also operate an underground mine in Colorado on property leased from the Bureau of Land Management ("BLM").

Four Corners. The Four Corners area includes northwestern New Mexico, northeastern Arizona, southeastern Utah and southwestern Colorado. The coal from this region typically has a sulfur content of 0.75% to 1.0% and a heat value of between 9,000 and 12,500 Btu/lb.

U.S. Coal Production by Region

Coal is mined from coal fields throughout the United States, with the major production centers located in the western United States, Northern and Central Appalachia and the Illinois Basin. The quality of coal varies by region. U.S. coal production was approximately 1.1 billion tons in 2007 according to the EIA. The following table, derived from data prepared by the EIA, sets forth production statistics in the three coal producing regions in the United States for the periods indicated.

	Actual										Projected						Compounded Annual Growth Rate
	2003		2004		2005		2006		2007		2010		2020		2030		2007–2010		2007–2030
	(in million tons)
Total Tons:
Appalachian Region	376		391		397		391		377		381		326		328		(0.3	)%	(0.7	)%
Interior Region	146		146		149		151		147		166		199		241		2.1	%	1.9	%
Western United States	549		575		585		620		621		619		745		886		0.2	%	1.6	%

Total	1,071		1,112		1,131		1,162		1,145		1,166		1,270		1,455		0.3	%	1.0	%

Percentage of Total Tons:
Appalachian Region	35	%	35	%	35	%	34	%	33	%	33	%	26	%	22	%
Interior Region	14	%	13	%	13	%	13	%	13	%	14	%	16	%	17	%
Western United States	51	%	52	%	52	%	53	%	54	%	53	%	58	%	61	%

Demand for U.S. Coal Production

Coal is primarily consumed by utilities to generate electricity. It is also used by steel companies to make steel products and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In general, coal is characterized by end use as either steam coal or metallurgical coal. Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coke, which is used in the production of steel. Over the past quarter century, total coal consumption in the United States has nearly doubled to approximately 1.1 billion tons in 2007. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators.

The following table sets forth demand trends for U.S. coal by consuming sector as projected by the EIA for the periods indicated.

	Actual					Projected			Compounded Annual Growth Rate
	2003	2004	2005	2006	2007	2010	2020	2030	2007-2010		2007-2030
	(in million tons)
Electrical Generation	1,005	1,016	1,037	1,027	1,046	1,054	1,202	1,401	0.3	%	1.3	%
Industrial	61	62	60	59	57	64	59	58	3.8	%	0.0	%
Steel Production	24	24	23	23	23	23	20	18	(0.3	)%	(1.0	)%
Residential/Commercial	4	5	5	3	3	4	4	4	10.4	%	1.2	%
Coal to Liquids	—	—	—	—	—	—	42	64	n/a		n/a
Export	43	48	50	50	59	71	34	35	6.6	%	(2.2	)%

Total	1,137	1,155	1,175	1,162	1,188	1,216	1,361	1,580	0.8	%	1.2	%

The nation's power generation infrastructure is approximately 50.4% coal-fired. As a result, coal has consistently maintained approximately a 49% to 53% market share during the past 10 years, principally because of its relatively low cost, reliability and abundance. Coal is the lowest cost fossil-fuel used for base-load electric power generation, being considerably less expensive than natural gas or fuel oil. Coal-fired generation is also competitive with nuclear power generation especially on a total cost per megawatt-hour basis. The production of electricity from existing hydroelectric facilities is inexpensive, but its application is limited both by geography and susceptibility to seasonal and climatic conditions. In 2007, non-hydropower renewable power generation accounted for only 2.6% of all the electricity generated in the United States, of which wind power—the alternative fuel sources that provides some of the greatest environmental benefits—represented only 0.8% of U.S. power generation and are generally not economically competitive with existing technologies.

Coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting power generation, technological developments and the location, availability and cost of other fuels such as natural gas, nuclear and hydroelectric power.

The following chart sets forth the source fuel for net electricity generation for 2007, according to the EIA.

Electricity Generation Source	% of Total Electricity Generation
Coal	47.9	%
Natural Gas	21.2	%
Nuclear	19.1	%
Hydro	5.7	%
Petroleum and Other	3.5	%
Renewables Other Than Hydro	2.6	%

Total	100.0	%

The largest cost component in electricity generation is fuel. Coal's primary advantage is its relatively low cost compared to other fuels used to generate electricity. The EIA has estimated the

average fuel prices per million of Btu to electricity generators, using coal and competing fossil fuel generation alternatives, as follows:

	Actual				Projected
Electric Generation Type	January 2007		January 2008		2010		2020		2030
	(per million Btu)
Petroleum Products	$	6.86	$	8.28	$	7.91	$	7.08	$	7.96
Natural Gas	$	8.27	$	14.81	$	6.22	$	5.76	$	6.33
Coal	$	1.74	$	1.91	$	1.71	$	1.58	$	1.69

Mining Methods

Coal is mined using one of two methods, underground or surface mining.

Underground Mining

Underground mines in the United States are typically operated using one of two different methods: room and pillar mining or longwall mining. In room and pillar mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment is used to cut the coal from the mining face. Generally, openings are driven 20 feet wide and the pillars are generally rectangular in shape. As mining advances, a grid-like pattern of entries and pillars is formed. Shuttle cars are used to transport coal to the conveyor belt for transport to the surface. When mining advances to the end of a panel, retreat mining may begin. In retreat mining, as much coal as is feasible is mined from the pillars that were created in advancing the panel, allowing the roof to cave. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned. The room and pillar method is often used to mine smaller coal blocks or thin seams, and seam recovery ranges from 35% to 70%, with higher seam recovery rates applicable where retreat mining is combined with room and pillar mining. Productivity for continuous room and pillar mining in the United States averages 2.7 tons per employee per hour, according to the EIA.

The other underground mining method commonly used in the United States is the longwall mining method. In longwall mining, a rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface.

Surface Mining

Surface mining is generally used when coal is found relatively close to the surface, when multiple seams in close vertical proximity are being mined or when conditions otherwise warrant. Surface mining involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life and making other improvements that have local community and environmental benefit. Overburden is typically removed at our mines using explosives in combination with large, rubber-tired diesel loaders. Seam recovery for surface mining is typically 90% or more. Productivity depends on equipment, geological composition and mining ratios and averages 3.5 tons per employee per hour in eastern regions of the United States, according to the EIA.

Surface-mining methods include area, contour, highwall and mountaintop removal. Area mines are surface mines that remove shallow coal over a broad area where the land is fairly flat. After the coal has been removed, the overburden is placed back into the pit. Contour mines are surface mines that mine coal in steep, hilly, or mountainous terrain. A wedge of overburden is removed along the coal outcrop on the side of a hill, forming a bench at the level of the coal. After the coal is removed, the overburden is placed back on the bench to return the hill to its natural slope. Highwall mining is a form of mining in which a remotely controlled continuous miner extracts coal and conveys it via augers,

belt or chain conveyors to the outside. The cut is typically a rectangular, horizontal cut from a highwall bench, reaching depths of several hundred feet or deeper. A highwall is the unexcavated face of exposed overburden and coal in a surface mine. Mountaintop removal mines are special area mines used where several thick coal seams occur near the top of a mountain. Large quantities of overburden are removed from the top of the mountains, and this material is used to fill in valleys next to the mine.

Transportation

Coal used for domestic consumption is generally sold free-on-board at the mine, and the purchaser normally bears the transportation costs. Export coal, however, is usually sold at the loading port, and coal producers are responsible for shipment to the export coal-loading facility, with the buyer paying the ocean freight.

Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs. Transportation can be a large component of a purchaser's total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. According to the National Mining Association, in 2006, railroads accounted for approximately 72% of total U.S. coal shipments, while truck movements account for approximately 12%. Trucks and overland conveyors haul coal over shorter distances, while barges, Great Lake carriers and ocean vessels move coal to export markets and domestic markets requiring shipment over the Great Lakes. Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two competing rail carriers, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. Rail competition in this major coal-producing region is important because rail costs constitute a significant portion of the delivered cost of Powder River Basin coal in eastern markets.

BUSINESS

Overview

We are a growth-oriented Delaware corporation formed to control and operate coal properties and related assets. We have a geographically diverse asset base, with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. For the year ended December 31, 2007, we produced approximately 7.1 million tons of coal and sold approximately 8.2 million tons of coal. For the six months ended June 30, 2008, we produced approximately 4.0 million tons of coal and sold approximately 4.2 million tons of coal. As of October 31, 2007, we controlled approximately 222.3 million tons of proven and probable coal reserves and approximately 97.8 million tons of non-reserve coal deposits. We completed the acquisitions of the Sands Hill mining complex located in Northern Appalachia in December 2007 and the Deane mining complex located in Central Appalachia in February 2008. These acquisitions collectively added approximately 18.6 million tons of proven and probable coal reserves and approximately 4.1 million tons of non-reserve coal deposits. We expect to produce approximately 1.8 million tons of coal in 2009 from these mining complexes. In May 2008, we entered into a joint venture, in which we have a 51% membership interest and for which we serve as the manager, that acquired the Eagle mining complex and the Bolt field located in Central Appalachia. The joint venture controls approximately 21.1 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits. We expect that the Eagle mining complex will produce approximately 0.6 million tons of metallurgical coal in 2009. We produce high quality coal that is sold in both the steam and metallurgical coal markets. We market our steam coal primarily to electric utilities, the majority of which are rated investment grade. The metallurgical coal that we produce is sold for end use by domestic and international steel producers.

In addition, we have successfully grown our production through internal development projects. For example, we invested approximately $19.0 million between 2004 and 2006 in the Hopedale mine located in Northern Appalachia to develop the approximately 17.1 million tons of proven and probable coal reserves at the mine. The Hopedale mine produced approximately 1.3 million tons of coal for the year ended December 31, 2007 and approximately 0.8 million tons of coal for the six months ended June 30, 2008. In 2007, we completed development of a new underground metallurgical coal mine at the Rob Fork mining complex located in Central Appalachia. The mine produced approximately 650,000 tons of coal for the year ended December 31, 2007 and approximately 383,000 tons of coal for the six months ended June 30, 2008. We also control or manage proven and probable coal reserves that are currently undeveloped of approximately (1) 102.4 million tons in the Taylorville field located in the Illinois Basin, (2) 16.7 million tons in the Leesville field located in Northern Appalachia, (3) 15.3 million tons in the Bolt field located in Central Appalachia and (4) 13.8 million tons in the Springdale field located in Northern Appalachia. These reserves can be developed and produced over time as industry and regional conditions permit. We believe our existing asset base will continue to provide attractive internal growth projects.

For the year ended December 31, 2007, we generated revenues of approximately $403.5 million and net income of approximately $30.7 million. For the six months ended June 30, 2008, we generated

revenues of approximately $223.0 million and net income of approximately $18.2 million. As of August 7, 2008, we had sales commitments for approximately 99%, 77% and 36% of our estimated coal production of approximately 8.6 million tons (including purchased coal to supplement our production), 8.7 million tons and 9.2 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. The following table summarizes our coal operations and reserves by region:

	Production for the		As of October 31, 2007(1)
Region	Year Ended December 31, 2007	Six Months Ended June 30, 2008	Proven & Probable Reserves	Average Heat Value	Average Sulfur Content	Type of Mines	Steam / Metallurgical Reserves	Transportation(2)
	(in million tons)		(in million tons)	(Btu/lb)	(%)		(in million tons)
Central Appalachia
Tug River Complex (KY, WV)	2.3	1.0	36.3	12,808	1.23	Underground and Surface	32.8/3.5	Truck, Barge, Rail (NS)
Rob Fork Complex (KY)	3.3	1.6	34.5	13,341	1.13	Underground and Surface	25.7/8.8	Truck, Barge, Rail (CSX)
Deane Complex (KY)(1)	n/a	0.2	7.2	13,196	1.55	Underground	7.2/—	Rail (CSX)
Eagle Complex (WV)(1)(3)	n/a	—	5.8	n/a	n/a	Underground	—/5.8	Truck, Rail (NS) (CSX)
Bolt Field (WV)(1)(3)	n/a	—	15.3	14,094	0.57	Underground	—/15.3	Rail (CSX)
Northern Appalachia
Hopedale Complex (OH)	1.3	0.8	17.1	13,026	2.18	Underground	17.1/—	Truck, Barge, Rail (OHC)
Sands Hill Complex (OH)(1)	<0.1	0.3	11.4	11,830	3.59	Surface	11.4/—	Truck, Barge
Leesville Field (OH)	—	—	16.7	13,152	2.21	Underground	16.7/—	Rail (OHC)
Springdale Field (PA)	—	—	13.8	13,443	1.72	Underground	13.8/—	Barge
Illinois Basin
Taylorville Field (IL)	—	—	102.4	12,084	3.83	Underground	102.4/—	Rail (NS)
Western Bituminous
McClane Canyon Mine (CO)	0.2	0.1	1.5	11,522	0.57	Underground	1.5/—	Truck

Total	7.1	4.0	262.0

(1): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, which is as of February 15, 2008; the Sands Hill mining complex is as of the acquisition date, December 14, 2007; and the Eagle mining complex is as of the acquisition date, May 13, 2008. Average heat value and average sulfur content for the Eagle mining complex are currently unavailable.
(2): NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad
(3): Owned by a joint venture in which we have a 51% membership interest and serve as the manager.

Business Strategies

Our primary business objective is to enhance stockholder value by continuing to execute the following strategies:

•: Maximize profitability. We intend to maximize profitability by focusing on (1) improving the efficiency of our operations, (2) maximizing our revenue, including by entering into short-term and longer-term sales commitments with third parties that have a strong credit profile and (3) managing our costs. We continually maintain our equipment and monitor our reserve plans to ensure we are prudently producing the maximum quantity of high quality coal from our mines. We have sales commitments for the majority of our estimated coal production for 2008 and 2009. We believe our short-term and longer-term sales commitments provide us with a reliable revenue base in the near term, while at the same time our uncommitted position enables

us to sell coal in the current strong coal pricing market environment. We will also continue to manage our cost structure, which will include further vertical integration of substantially all of our trucking, reclamation, drilling and blasting activities.

•: Grow our business through internal development opportunities. A significant portion of our proven and probable coal reserves and our non-reserve coal deposits are located in the vicinity of our existing infrastructure. We believe that such proximity to our existing operations provides a number of opportunities to develop these reserves and non-reserve coal deposits without significant capital expenditures necessary to develop or expand our infrastructure. In addition, our existing base of proven and probable coal reserves includes development opportunities that will involve infrastructure development such as our joint venture's Bolt field in West Virginia (15.3 million tons in proven and probable coal reserves), our Leesville field in Ohio (16.7 million tons in proven and probable coal reserves), our Springdale field in Pennsylvania (13.8 million tons in proven and probable coal reserves) and our Taylorville field in Illinois (102.4 million tons in proven and probable coal reserves). We have and will continue to maintain an aggressive program of systematically exploring the development of our proven and probable coal reserves as well as our non-reserve coal deposits, including the acquisition of necessary mining rights, and to deploy capital necessary to develop these coal reserves and non-reserve coal deposits to take advantage of internal development opportunities.
•: Selectively expand our operations through strategic acquisitions. Since our predecessor's inception in April 2003, we have grown through a series of strategic acquisitions of mining operations, reserves and infrastructure. We will continue to pursue strategic and accretive acquisitions of such assets both within our existing areas of operations and in new geographic areas. We also intend to further leverage our infrastructure by acquiring coal properties in close proximity to our current operations to (1) extend the lives of our mines, (2) maximize the efficiencies of our coal processing and distribution infrastructure and (3) provide us opportunities for new mine development. In addition, we intend to evaluate selected stable, cash generating coal and non-coal natural resource assets that we have substantial experience in identifying, acquiring at attractive valuations and operating efficiently.
•: Focus on excellence in safety and environmental stewardship. We intend to maintain our recognized leadership in mining in a safe and prudent manner. For the year ended December 31, 2007, our nonfatal days lost incidence rate for our operations was 32.8% below the industry average. For the six months ended June 30, 2008, our nonfatal days lost incidence rate was 19.2% below the industry average. For the year ended December 31, 2007, our operations received 57.4% fewer violations per inspection day than the national average according to the MSHA. We will continue to implement safety measures that are designed to promote safe operating practices and to emphasize environmental stewardship to our employees. We believe our ability to minimize lost-time injuries and environmental violations will increase our operating efficiency which will directly improve our cost structure and financial performance and also bolster employee morale.

Competitive Strengths

We believe the following competitive strengths will enable us to execute our business strategies successfully:

•: We have significant internal expansion opportunities. We believe that our undeveloped proven and probable coal reserves and our non-reserve coal deposits will allow us to significantly expand production on a capital efficient basis through the utilization of our existing infrastructure, as some of these reserves and non-reserve coal deposits are located in close proximity to our existing operations. For example, in 2007 in an effort to supplement and enhance production at

our Rob Fork mining complex, we completed development of a new underground metallurgical coal mine. Our investment of approximately $30.0 million included a conveyor belt to transfer coal from the mine portal directly to the preparation plant as well as an extensive entry system to access the main reserve body. The mine produced approximately 650,000 tons of coal for the year ended December 31, 2007 and approximately 383,000 tons of coal for the six months ended June 30, 2008. We also control or manage proven and probable coal reserves that are currently undeveloped of approximately (1) 102.4 million tons in the Taylorville field located in the Illinois Basin, (2) 16.7 million tons in the Leesville field located in Northern Appalachia, (3) 15.3 million tons in the Bolt field in Central Appalachia and (4) 13.8 million tons in the Springdale field located in Northern Appalachia. These reserves can be developed and produced over time as industry and regional conditions permit.

•: We have a proven track record of successful acquisitions. Since our predecessor's inception in 2003, we have completed numerous asset acquisitions with a total purchase price of approximately $212.9 million. Through these acquisitions and other coal lease transactions we have significantly increased our proven and probable coal reserves and non-reserve coal deposits. The members of our senior management team have, on average, 24 years of coal industry and related
experience and have a demonstrated track record of acquiring, building and operating coal businesses profitably and safely throughout the United States. The acquisitions consummated by our management team have consisted of high quality coal reserves and union-free operations, with limited reclamation and legacy liabilities. We believe we have a disciplined acquisition strategy that is focused on acquiring selected assets at attractive valuations, while limiting to the extent possible the assumption of debt and reclamation and employee-related liabilities.
•: We have an attractive blend of short-term and longer-term sales contracts as well as uncommitted coal to sell on the spot market. As of August 7, 2008, we had sales commitments for approximately 99%, 77% and 36% of our estimated coal production of approximately 8.6 million tons (including purchased coal to supplement our production), 8.7 million tons and 9.2 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. We believe our short-term and longer-term sales commitments provide us with a reliable revenue base in the near term, while at the same time our uncommitted position enables us to sell coal in the current strong coal pricing market environment.
•: Our mining activities are strategically located. Our mining operations are located near many major power plants and on or near coal-hauling railroads in the eastern United States, including the CSX Rail, the NS Rail and the OHC Rail. Additionally, certain of our mines are located within economical trucking distance to the Big Sandy River and/or the Ohio River where coal can be transported by barge. Cost and availability of transportation are critical marketing factors because our customers generally pay the transportation costs for the delivery of coal, and these costs represent a significant portion of a customer's total cost of delivered coal. We believe the geographic location of our mines and the multiple transportation options available to us provide us with a transportation cost advantage compared to many of our competitors.
•: We offer a variety of high quality steam and metallurgical coal that meet our customers' needs. Our customers and end users, which include electric utilities in the United States and domestic and international steel producers, demand a variety of coal types and characteristics. The majority of our steam coal production in Central Appalachia also meets the specifications of both the OTC and NYMEX markets. In addition, the substantial planned increase in the number of electrical generating plants utilizing pollution control devices has created and we expect will continue to create an expanding market for the coal that we produce in Central and Northern Appalachia.

•: We have vertically integrated many of our operations to control operating costs. We have recently vertically integrated substantially all of our trucking, reclamation and drilling and blasting activities. The integration of these activities has lowered our cost and significantly lessened our dependence on certain third-party service providers. The vertical integration helps us to maintain our low cost structure and maximize profitability.
•: We have a strong credit profile. As a result of our prudent acquisition strategy and conservative financial management, we believe that our capital structure after this offering will provide us significant financial flexibility to pursue our strategic goals, including (1) pursuing acquisitions, (2) investing in our existing operations and (3) managing our operations through periods of difficult coal market conditions. We believe that compared to other publicly traded U.S. coal producers, we have relatively low levels of outstanding debt, legacy liabilities, reclamation liabilities and postretirement employee obligations. In addition, we sell a majority of our coal to a number of customers with an investment-grade credit rating.

Our History

Rhino Energy LLC, our predecessor, was formed in April 2003 by Wexford Funds. Please read "—Our Sponsor." Since our inception, our strategy has been to acquire coal reserves and properties with relatively long lives and which could be developed with low risk at a reasonable cost. We have accomplished this through a series of property purchases and leases and by avoiding the assumption of significant legacy liabilities.

In May 2003, we made our first acquisition, which we refer to as Tug River. The acquisition included approximately 20.6 million tons of surface and underground proven and probable coal reserves and approximately 0.7 million tons of non-reserve coal deposits and equipment in Pike County, Kentucky that are serviced by the NS Rail. These assets were purchased free of legacy liabilities associated with inactive properties. In May 2003, we purchased additional assets in Pike County from Lodestar Energy Inc. These assets included approximately 5.0 million tons of underground proven and probable coal reserves and approximately 0.5 million tons of non-reserve coal deposits and equipment.

In May 2003, we acquired three coal leases from BLM and an operating underground mine, the McClane Canyon mine, located in Colorado near Grand Junction. This acquisition also included a long-term contract with Xcel Energy Inc.'s ("Xcel") Cameo power plant located east of Grand Junction. At the present time, we produce approximately 250,000 tons per year from the McClane Canyon mine.

In February 2004, we acquired leases covering approximately 5.9 million tons of surface proven and probable coal reserves and approximately 7.6 million tons of non-reserve coal deposits in Pike County, Kentucky, adjacent to the Tug River properties, from Pompey Coal Corporation and Berkeley Energy Corporation. This acquisition also included a long-term lease from Appalachian Land Company and a unit train loading facility on the NS Rail, which we refer to as the Jamboree loadout. The acquisition of the Jamboree loadout, consistent with our business strategy, allowed us to build a large block of contiguous surface reserves that could be serviced from a single shipping location.

In April 2004, we acquired control of approximately 18.8 million tons of surface and underground proven and probable coal reserves and approximately 6.6 million tons of non-reserve coal deposits in Mingo County, West Virginia, from H&L Construction Co., Inc. and Little Boyd Coal Co., Inc. These properties, which are located across the Tug River from our existing properties, brought our total proven and probable coal reserves in the Tug River area to approximately 45.3 million tons. Coal from these properties is also shipped through the Jamboree loadout. The mobile mining equipment included in this acquisition was sold to a contract miner who is currently mining this property for us.

In April 2004, we also acquired coal assets from subsidiaries of American Electric Power Company, Inc., AEP Coal, Inc. and certain of its affiliates ("AEP") in eastern Kentucky, Ohio and Pennsylvania. In this transaction, we acquired only active mining areas and did not assume any legacy liabilities related to AEP's inactive mining areas. The acquisition included approximately 18.4 million tons of surface and underground proven and probable coal reserves and approximately 11.5 million tons of non-reserve coal deposits in Kentucky and approximately 50.0 million tons of underground proven and probable coal reserves and approximately 43.7 million tons of non-reserve coal deposits in Ohio and Pennsylvania and a substantial amount of infrastructure. In Kentucky, this infrastructure included the Rob Fork preparation plant and unit loadout facility on the CSX Rail and six underground mines and two surface mines, collectively referred to as the Rob Fork mining complex. The Ohio assets included an underground mine that was mined out in 2007, and the Nelms preparation plant near Cadiz, Ohio. The Ohio assets also included the Hopedale mine which was shut in the 1980s and subsequently reopened by us in September 2005. The Hopedale mine has approximately 17.1 million tons of underground proven and probable coal reserves and approximately 23.2 million tons of non-reserve coal deposits and an expected reserve life of at least ten years at its planned production rate.

In December 2004, we acquired leases for approximately 7.5 million tons of surface proven and probable coal reserves and 9.6 million tons of non-reserve coal deposits near our Bevins Branch mine from Millers Creek Resources, Inc., Prater Creek Coal Corporation and Alma Land Company. We also leased an additional approximately 1.0 million tons of surface proven and probable coal reserves and approximately 3.0 million tons of non-reserve coal deposits from Elk Horn Properties at Bevins Branch mine. These transactions extended the expected life of the Bevins Branch mine by approximately ten years, based on current production rates. Subsequent to the AEP acquisition, we leased approximately 2.2 million tons of surface proven and probable coal reserves from various lessors which extended the life of our Three Mile mine by three years.

In March 2005, we leased approximately 9.2 million tons of underground proven and probable coal reserves of high volatile metallurgical coal from Big Sandy Company L.P. The acquisition of these reserves allowed us to increase our participation in the metallurgical coal market. These reserves are accessed from a mine portal adjacent to the Rob Fork facility and therefore require no trucking costs from mine to the plant.

In June 2005, we acquired the assets of Christian County Coal Company which consisted primarily of 237.5 acres of surface property rights (165 owned acres) and two mineral leases covering approximately 21,000 acres. The assets contain approximately 102.4 million tons of underground proven and probable coal reserves and approximately 22.9 million tons of non-reserve coal deposits. These undeveloped reserves are located near Taylorville in Christian County, Illinois. Subsequent to the initial acquisition, we have acquired additional surface properties and continue to develop permitting and construction plans.

In November 2005, we acquired approximately 1.8 million tons of surface proven and probable coal reserves and approximately 0.7 million tons of non-reserve coal deposits and assumed control of a surface mining operation near Pikeville, Kentucky from M&D Pipeline Inc.

In December 2007, we acquired the assets of Sands Hill Coal Company, which included control of 6,000 acres containing approximately 11.4 million tons of proven and probable coal reserves and approximately 3.9 million tons of non-reserve coal deposits located in Jackson, Vinton and Gallia Counties in Ohio. This acquisition also included approximately 21.6 million tons of high quality proven and probable limestone reserves that are mined in conjunction with the coal seams and approximately 3.7 million tons of non-reserve limestone deposits.

In February 2008, we acquired approximately 30,000 acres containing approximately 7.2 million tons of proven and probable coal reserves and approximately 0.2 million tons of non-reserve coal

deposits located in Letcher, Pike and Knott Counties in Kentucky from CONSOL of Kentucky, Inc. In addition, the acquisition included approximately 14,627 acres of surface property, as well as a 950 tons-per-hour preparation plant and unit train loadout facility on the CSX Rail.

In February 2008, we entered into a lease with West Virginia Mid-Vol, Inc. covering approximately 15.3 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits located in Raleigh County in West Virginia.

In May 2008, we entered into a joint venture which acquired a then inactive metallurgical coal operation covering approximately 5.8 million tons of proven and probable metallurgical coal reserves located in Raleigh and Wyoming Counties, West Virginia from Peachtree Ridge Mining Company, Inc. In connection with its formation, the joint venture acquired the February 2008 Raleigh County lease. The joint venture controls approximately 21.1 million tons of proven and probable reserves and approximately 24.6 million tons of non-reserve coal deposits. We hold a 51% membership interest in the joint venture and serve as the manager.

Our Sponsor

Our sponsor is Wexford, a SEC registered investment advisor with approximately $7.0 billion of assets under management. Rhino Energy LLC, our predecessor, was formed in 2003 by Wexford Funds. Rhino Energy Holdings LLC, which is owned by certain Wexford Funds, will contribute 100% of the ownership interests in Rhino Energy LLC to us. In connection with this offering, Rhino Energy Holdings LLC and certain Wexford Funds will contribute 100% of the ownership interests in Rhino Energy LLC to us in exchange for an aggregate of shares of our common stock. The Wexford Funds will then contribute their shares of our common stock to Rhino Energy Holdings LLC in exchange for ownership interests in Rhino Energy Holdings LLC. Rhino Energy Holdings LLC, as the selling stockholder, will sell shares of our common stock, representing % of our outstanding common stock, to the public in this offering.

After this offering, Rhino Energy Holdings LLC will own approximately % and the public will own approximately % of our outstanding common stock. Certain of our directors are Wexford Partners. Please read "Certain Relationships and Related Party Transactions" for more information.

Coal Operations

Mining Operations

As of June 30, 2008, we operated three mining complexes located in Central Appalachia (Tug River, Rob Fork and Deane), two mining complexes located in Northern Appalachia (Hopedale and Sands Hill) and one mine located in the Western Bituminous region. 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 facilities include five active preparation plants and/or loadouts, each of which receive, blend, process and ship coal that is produced from one or more of our active surface and underground mines, none of which contributed more than 18% to our total production for the year ended December 31, 2007 or 20% for the six months ended June 30, 2008. All of our preparation plants are modern plants that have both coarse and fine coal cleaning circuits. Our joint venture acquired the Eagle mining complex in Central Appalachia in May 2008. The complex is in the process of redevelopment and commenced operations in August 2008.

Our surface mines include area mining, mountaintop removal and contour mining. These operations use truck and wheel loader equipment fleets along with large production tractors. Our underground mines include drift and slope operations utilizing 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

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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.

Central Appalachia. As of June 30, 2008, we operated three mining complexes located in Central Appalachia consisting of nine active underground mines, four of which are company-operated with the remaining five being contractor-operated. In addition, we operate six company-operated surface mines, and we have one contractor-operated surface mine. For the year ended December 31, 2007, these mines produced an aggregate of approximately 5.3 million tons of steam coal and approximately 0.3 million tons of metallurgical coal; and, for the six months ended June 30, 2008, approximately 3.7 million tons of steam coal and approximately 0.5 million tons of metallurgical coal. As of October 31, 2007, we controlled approximately 70.8 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits in Central Appalachia. The Deane mining complex added approximately 7.2 million tons of proven and probable coal reserves and approximately 0.2 million tons of non-reserve coal deposits as of the acquisition date, February 8, 2008. The Bolt field added approximately 15.3 million tons of proven and probable coal reserves and approximately 24.6 million tons of non-reserve coal deposits as of the lease date, February 15, 2008. The Eagle mining complex added approximately 5.8 million tons of proven and probable coal reserves, all of which is high quality metallurgical coal, as of the acquisition date, May 13, 2008, and commenced operations in August 2008.

The following table provides summary information regarding our mining complexes in Central Appalachia as of June 30, 2008.

			Number and Type of Active Mines(1)			Tons Produced for the
Mining Complex (Location)	Preparation Plants and Loadouts	Transportation to Customers	Company- Operated Mines	Contractor- Operated Mines	Total Mines	Year Ended December 31, 2007	Six Months Ended June 30, 2008
						(in millions)
Tug River (KY, WV)	Jamboree(2)	NS, Truck, Barge	3S	1S	4S	2.3	1.0
Rob Fork (KY)	Rob Fork	CSX, Truck, Barge	3U; 3S	2U	5U; 3S	3.3	1.6
Deane (KY)	Rapid Loader	CSX, Truck	1U	3U	4U	n/a	0.2
Eagle (WV)(3)	Rocklick	CSX, NS, Truck	n/a	n/a	n/a	n/a	—

Total			4U; 6S	5U; 1S	9U; 7S	5.6	2.8

(1): Numbers indicate the number of active mines at the mining complex. U = Underground mine; S = Surface mine.
(2): Includes only a loadout facility.
(3): Owned by a joint venture in which we have a 51% membership interest and serve as the manager. The mining complex has two underground mines that are in the process of redevelopment but as of June 30, 2008 were inactive. The mining complex commenced operations in August 2008. 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.

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Tug River Mining Complex. The following map outlines the mines and loadout facility that comprise our Tug River mining complex:

Our Tug River mining complex consists of property in Kentucky and West Virginia that borders the Tug River. As of October 31, 2007, the Tug River mining complex included approximately 36.3 million tons of proven and probable coal reserves and approximately 7.0 million tons of non-reserve coal deposits.

Our Tug River mining complex produces coal from three company-operated surface mines and one contractor-operated surface mine. Coal production from these mines is delivered by truck to the Jamboree loadout for blending and loading. The Jamboree facility is located on the NS Rail and is a modern unit train loadout with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in less than four hours. Jamboree loadout is used primarily to process surface mined coal which is sold as steam coal to electric utilities.

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Rob Fork Mining Complex. The following map outlines the mines, preparation plant and loadout facility that comprise our Rob Fork mining complex:

Our Rob Fork mining complex is located in eastern Kentucky and, as of October 31, 2007, included approximately 34.5 million tons of proven and probable coal reserves and approximately 17.6 million tons of non-reserve coal deposits.

Our Rob Fork mining complex produces coal from three company-operated surface mines, two contractor-operated underground mines and three company-operated underground mines. Between 2006 and 2007, in an effort to enhance production at our Rob Fork mining complex, we completed development of a new underground metallurgical coal mine. Our investment of approximately

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$30.0 million included a conveyor belt to transfer coal from the mine portal directly to the preparation plant as well as an extensive entry system to access the main reserve body. As of June 30, 2008, the mine accounted for approximately 0.8 million tons per year of metallurgical coal production with an expected reserve life of approximately ten years. The Rob Fork mining complex located on the CSX Rail consists of a modern 700 tons-per-hour preparation plant utilizing heavy media circuitry and is capable of cleaning coarse and fine coal size fractions combined with a unit train loadout with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in less than four hours. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers' needs.

Deane Mining Complex. The following map outlines the mines, preparation plant and loadout facility that comprise our Deane mining complex:

Our Deane mining complex is located in eastern Kentucky and, as of the acquisition date, included approximately 7.2 million tons of proven and probable coal reserves and approximately 0.2 million tons of non-reserve coal deposits. We expect to produce approximately 0.5 million tons of coal from the Deane mining complex for the year ending December 31, 2008 and 1.0 million tons of coal for the year ending December 31, 2009.

Our Deane mining complex produces steam coal from one company-operated underground mine and three contractor-operated underground mines. The infrastructure consists of a 950 tons-per-hour preparation plant and a loadout facility, utilizing heavy media circuitry and is capable of cleaning coarse and fine coal size fractions combined with a unit train loadout with batch weighing equipment

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capable of loading in excess of 10,000 tons into railcars in less than 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.

Eagle Mining Complex. The following map outlines the mines, preparation plant and loadout facility that comprise our joint venture's Eagle mining complex:

We have a 51% membership interest in and manage the Eagle mining complex which is located in Raleigh and Wyoming Counties, West Virginia. The Eagle mining complex includes two underground mines and approximately 5.8 million tons of high-quality proven and probable metallurgical coal reserves. Our joint venture acquired the Eagle mining complex in May 2008. The mines are permitted, bonded and in the process of redevelopment. The mining complex commenced operations in August 2008. Raw coal is trucked to a facility owned by our joint venture partner to be sized, washed and shipped by truck or rail. We expect the mining complex to produce approximately 0.6 million tons of metallurgical coal for the year ended December 31, 2009.

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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, 2007, these mines produced an aggregate of approximately 1.3 million tons of steam coal and, for the six months ended June 30, 2008, approximately 1.1 million tons of steam coal. As of October 31, 2007, we controlled approximately 47.6 million tons of proven and probable coal reserves and approximately 50.3 million tons of non-reserve coal deposits in Northern Appalachia. The Sands Hill mining complex added approximately 11.4 million tons of proven and probable coal reserves and approximately 3.9 million tons of non-reserve coal deposits as of the acquisition date, December 14, 2007. We also control non-reserve coal deposits of approximately (1) 10.6 million tons in the Leesville field and (2) 16.5 million tons in the Springdale field.

The following table provides summary information regarding our mining complexes in Northern Appalachia as of June 30, 2008:

			Number and Type of Active Mines(1)			Tons Produced for the
Mining Complex (Location)	Preparation Plants and Loadouts	Transportation to Customers	Company- Operated Mines	Contractor- Operated Mines	Total Mines	Year Ended December 31, 2007	Six Months Ended June 30, 2008
						(in millions)
Hopedale (OH)	Nelms	OHC, Truck, Barge	1U	—	1U	1.3	0.8
Sands Hill (OH)	Sands Hill(2)	Truck, Barge	2S	—	2S	<0.1	0.3

Total			1U; 2S	—	1U; 2S	1.3	1.1

(1): Numbers indicate the number of active mines at the mining complex. U = Underground mine; S = Surface mine.
(2): Includes only a preparation plant.

Hopedale Mining Complex. The Hopedale mine is an underground mine located in Hopedale, Ohio about five miles northeast of Cadiz, Ohio. As of October 31, 2007, the Hopedale mining complex included approximately 17.1 millions of proven and probable coal reserves and approximately 23.2 million tons of non-reserve coal deposits. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the OHC Rail 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 1.3 million tons and 0.8 million tons of steam coal for the year ended December 31, 2007 and the six months ended June 30, 2008, respectively.

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The following map outlines the mine and the preparation plant and loadout facility that comprise our Hopedale mining complex:

Sands Hill Mining Complex. In December 2007, we acquired the assets of Sands Hill Coal Company which included two surface mines located near Hamden, Ohio. These two mines are expected to produce approximately 0.7 million tons of steam coal and approximately 0.7 million tons of high quality aggregate limestone for the year ending December 31, 2008 and approximately 0.8 million tons of steam coal and approximately 1.2 million tons of high quality aggregate limestone for the year ending December 31, 2009. The Sands Hill mines produced approximately 0.3 million tons of steam coal and approximately 0.4 million tons of high quality limestone aggregate for the six months ended June 30, 2008. As of December 14, 2007, these two mines included approximately 11.4 millions of proven and probable coal reserves, approximately 3.9 million tons of non-reserve coal deposits, approximately 21.6 million tons of proven and probable limestone reserves and approximately 3.7 million tons of non-reserve limestone deposits A river-front barge on the Ohio River with a capacity of approximately 1,000 tons-per-hour is accessible from the Sands Hill mining complex. The acquisition also included a 260 tons-per-hour preparation plant.

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The following map outlines the mines and preparation plant that comprise our Sands Hill mining complex:

Western Bituminous Region. We operate an underground mine in Colorado in the Western Bituminous region. The McClane Canyon mine is located near Loma, Colorado and is on property leased from the BLM. We currently produce and sell from the McClane Canyon mine approximately 0.3 million tons of coal per year to Xcel's Cameo power plant, located east of Grand Junction, Colorado. The current contract with Xcel will expire December 31, 2008. We plan to renew this contract through October 31, 2010; however, Xcel has announced that it plans to close its Cameo power plant.

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In addition to the active McClane Canyon mine, we currently control three nearby federal leases consisting of approximately 8,780 acres, two of which have the potential to support a future underground coal mining operation, with expected production of 6.0 million to 8.0 million tons of coal per year, with procurement of an adjacent federal leasehold. We expect the permitting process and leasehold procurement to last approximately four to five years. We are currently in an exploration process to define the volume, quality, and mineability of the coal reserve.

The following map outlines the McClane Canyon mine and loadout facility:

Trucking

In February 2007, we initiated the first major step of our vertical integration strategy with the introduction of Rhino Trucking. The primary goal of integrating the trucking operations was to provide our Kentucky coal operations with dependable, safe coal hauling to our preparation plants and loadout facilities and reduce third-party trucking costs. From an initial fleet of two trucks, as of June 30, 2008, our Kentucky fleet included 40 trucks and hauled approximately 60% of our production tons that must be transported by truck. In addition to the mining operation, the Sands Hill acquisition also provided an opportunity to expand the reach of our trucking operations into the southeastern Ohio region to transport coal to our customers where rail is not available. As of June 30, 2008, our Sands Hill fleet included 18 trucks.

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Reclamation

While we are committed to minimizing our environmental impact during the mining process, there is always some degree of environmental impact when the mining activity is completed. To minimize the long-term environmental impact of our mining activities, we plan and monitor each phase of our mining projects as well as the post-mining reclamation efforts. As of June 30, 2008, we had approximately $20.7 million in letters of credit pledged to secure the performance of our reclamation obligations. In addition to providing surety bonds, we have also made a significant investment to complete the required reclamation activities in a timely and professional manner to cause the bond to be released and to eliminate our long-term liability. In August 2007, we established a new operating group to integrate mine related construction, site and roadway maintenance and post-mining reclamation. Since then, we have been able to efficiently supply the majority of these services internally that were previously outsourced.

Drilling and Blasting

Historically, we had contracted to a third party the majority of our drilling and blasting activities at our company-operated surface mines. In 2007, we began performing those services in-house, resulting in cost savings of approximately $2.1 million for the year ended December 31, 2007.

Coal Reserves and Non-Reserve Coal Deposits

Our coal reserve and non-reserve coal deposit estimates are based on geological data assembled and analyzed by our staff of geologists and engineers and economic data such as cost of production, projected sale price as well as other data concerning permitability and advances in mining technology. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or sales of coal properties will also change theses estimates. 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 reserves and our non-reserve coal deposits. The most recent review of our coal reserves and non-reserve coal deposits other than reserves at the Eagle mining complex was completed as of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007) and covered all of our coal reserves and non-reserve coal deposits we controlled as of such date. The results verified our estimates, with minor adjustments and included an in-depth review of our procedures and controls. Our coal reserves of approximately 256.2 million tons and our non-reserve coal deposits of approximately 126.5 million tons as of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; and the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007) were confirmed by Marshall Miller. The coal reserves of approximately 5.8 million tons at the Eagle mining complex as of the acquisition date, May 13, 2008, were confirmed by Boyd.

Coal Reserves

"Reserves" are defined by the SEC Industry Guide 7 as that part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. Industry

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Guide 7 divides reserves between "proven (measured) reserves" and "probable (indicated) reserves" which are defined as follows:

•: "Proven (measured) reserves." Reserves for which (1) 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 (2) 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.
•: "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.

As of October 31, 2007 (except for information regarding the Deane mining complex, which is as of the acquisition date, February 8, 2008; the Bolt field, which is as of the lease date, February 15, 2008; the Sands Hill mining complex, which is as of the acquisition date, December 14, 2007; and the Eagle mining complex, which is as of the acquisition date, May 13, 2008), we owned 20.5% of our coal reserves and leased 79.5% of our reserves from various third-party landowners. The majority of our leases has 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 coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine those reserves.

The following table provides information as of October 31, 2007, except as otherwise indicated, on the location of our operations and the type, amount and ownership of the coal reserves:

			Proven and Probable Coal Reserves(1)
				Total Tons		Total Tons		Total Tons
			Total Tons	Total Tons		Total Tons		Total Tons
Region			Total Tons	Assigned(2)	Unassigned(2)	Owned	Leased	Steam(3)	Metallurgical(3)
			(in million tons)
Central Appalachia
	Tug River Complex (KY, WV)		36.3	35.6	0.7	—	36.3	32.8	3.5
	Rob Fork Complex (KY)		34.5	32.1	2.4	7.3	27.2	25.7	8.8
	Deane Complex (KY)(4)		7.2	7.2	—	6.7	0.5	7.2	—
	Eagle Complex (WV)(4)(5)		5.8	5.8	—	—	5.8	—	5.8
	Bolt Field (WV)(4)(5)		15.3	15.3	—	—	15.3	—	15.3

		Total Central Appalachia	99.1	96.0	3.1	14.0	85.1	65.7	33.4

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Northern Appalachia
	Hopedale Complex (OH)		17.1	11.7		5.4		9.2		7.9		17.1		—
	Sands Hill Complex (OH)(4)		11.4	11.4		—		—		11.4		11.4		—
	Leesville Field (OH)		16.7	—		16.7		16.7		—		16.7		—
	Springdale Field (PA)		13.8	—		13.8		13.8		—		13.8		—

		Total Northern Appalachia	59.0	23.1		35.9		39.7		19.3		59.0		—

Illinois Basin
	Taylorville Field (IL)		102.4	—		102.4		—		102.4		102.4		—
Western Bituminous
	McClane Canyon Mine (CO)		1.5	1.5		—		—		1.5		1.5		—

Total			262.0	120.6		141.4		53.7		208.3		228.6		33.4

Percentage of total				46.0	%	54.0	%	20.5	%	79.5	%	87.3	%	12.7	%

(1): The proven and probable coal reserves are reported as recoverable coal reserves, which is the portion that could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield.
(2): Assigned reserves mean coal reserves that have been committed by us to operating mine shafts, mining equipment and plant facilities and so can be mined without a significant capital expenditure for mine development. Unassigned reserves represent coal reserves that have not been committed and that would require new mineshafts, mining equipment or plant facilities before operations could begin in the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin.
(3): 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. Some of the reserves in the metallurgical category can also be used as steam coal.
(4): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, which is as of February 15, 2008; the Sands Hill mining complex is as of the acquisition date, December 14, 2007; and the Eagle mining complex is as of the acquisition date, May 13, 2008.
(5): Owned by a joint venture in which we have a 51% membership interest and serve as the manager.

The following table provides information on particular characteristics of our coal reserves as of October 31, 2007, except as otherwise indicated:

			As Received Basis(1)						Proven and Probable Coal Reserves
										Sulfur Content
Region			% Ash		% Sulfur			SO2/mm Btu		Sulfur Content
Region			% Ash		% Sulfur		Btu/lb.	SO2/mm Btu	Total	<1%	1-1.5%	>1.5%	Unknown
									(in million tons)
Central Appalachia
	Tug River Complex (KY, WV)		10.77	%	1.23	%	12,808	1.96	36.3	22.0	8.4	5.6	0.3
	Rob Fork Complex (KY)		6.42	%	1.13	%	13,341	1.69	34.5	21.8	2.9	7.4	2.4
	Deane Complex (KY)(2)		5.99	%	1.55	%	13,196	2.35	7.2	—	—	7.2	—
	Eagle Complex (WV)(2)(3)		n/a		n/a		n/a	n/a	5.8	n/a	n/a	n/a	n/a
	Bolt Field (WV)(2)(3)		3.87	%	0.57	%	14,094	0.82	15.3	15.3	—	—	—

		Total Central Appalachia	7.28	%	1.11	%	13,246	1.70	99.1	59.1	11.3	20.2	2.7

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Northern Appalachia
	Hopedale Complex (OH)		6.64	%	2.18	%	13,026	3.35	17.1	—		—		17.1		—
	Sands Hill Complex (OH)(2)		11.76	%	3.59	%	11,830	6.03	11.4	—		—		11.4		—
	Leesville Field (OH)		6.21	%	2.21	%	13,152	3.36	16.7	—		—		16.7		—
	Springdale Field (PA)		6.63	%	1.72	%	13,443	2.55	13.8	—		—		13.8		—

		Total Northern Appalachia	7.50	%	2.35	%	12,928	3.68	59.0	—		—		59.0		—

Illinois Basin
	Taylorville Field (IL)		8.43	%	3.83	%	12,084	6.34	102.4	—		—		102.4		—
Western Bituminous
	McClane Canyon Mine (CO)		12.00	%	0.57	%	11,522	0.98	1.5	1.5		—		—		—

Total			7.82	%	2.48	%	12,698	4.01	262.0	60.6		11.3		181.6		2.7

Percentage of total										23.7	%	4.4	%	70.9	%	1.0	%

(1): As received represents an analysis of a sample as received at a laboratory.
(2): Information regarding the Deane mining complex is as of the acquisition date, February 8, 2008; the Bolt field is as of the lease date, which is as of February 15, 2008; the Sands Hill mining complex is as of the acquisition date, December 14, 2007; and the Eagle mining complex is as of the acquisition date, May 13, 2008. Particular characteristics of our coal reserves at the Eagle mining complex are currently unavailable.
(3): Owned by a joint venture in which we have a 51% membership interest and serve as the manager.

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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The following table provides information as of October 31, 2007, except as otherwise indicated, on our non-reserve coal deposits:

	Non-Reserve Coal Deposits
		Total Tons
	Total Tons	Total Tons
Region	Total Tons	Owned		Leased
	(in million tons)
Central Appalachia(1)	49.4	7.4		42.0
Northern Appalachia(2)	54.2	40.7		22.9
Illinois Basin	22.9	—		22.9
Western Bituminous	—	—		—

Total	126.5	48.1		78.4

Percentage of total		38.0	%	62.0	%

(1): Includes information regarding the Deane mining complex as of its acquisition date, February 8, 2008; and the Bolt field as of its lease date, February 15, 2008.
(2): Includes information regarding the Sands Hill mining complex as of its acquisition date, December 14, 2007.

Limestone

Our Sands Hill mining complex, which we acquired on December 14, 2007, includes approximately 21.6 million tons of proven and probable limestone reserves and approximately 3.7 million tons of non-reserve limestone deposits. 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 the mining complex. We believe that our production of limestone will provide us with an additional source of revenues at a low incremental capital cost.

As of December 14, 2007, as confirmed by Marshall Miller, all of our proven and probable limestone reserves were assigned reserves, which are limestone reserves that can be mined without a significant capital expenditure for mine development.

Other Natural Resource Assets

Customers

General

Our primary customers for our steam coal are electric utilities, a majority of which have investment grade credit ratings, and the metallurgical coal we produce is sold for end use by domestic and international steel producers. For the year ended December 31, 2007, 97% of our coal sales consisted of steam coal and the remaining 3% consisted of metallurgical coal and for the six months ended June 30, 2008, 88% of our sales consisted of steam coal and the remaining 12% consisted of metallurgical coal. 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. We derived 91% of our total revenues from coal sales to our ten largest customers for the year ended December 31, 2007, with affiliates of our top four customers accounting for 68% of our sales: Constellation Energy Group, Inc. (24%); Progress Energy Inc. (17%); American Electric Power Company, Inc. (14%); and Duke Energy Corp. (13%). For the six months ended June 30, 2008, we derived 70% of our total revenues from sales to our ten largest customers, with affiliates of our top two customers accounting for 36% of our total sales: American Electric Power Company, Inc. (23%) and Constellation Energy

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Group, Inc. (13%). 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

As of August 7, 2008, we had sales commitments of approximately 14.3 million tons from the second half of 2008 through 2010. Affiliates of all of our top ten customers are parties to multiple coal supply contracts with us. Our sales commitments total 8.5 million tons, 6.7 million tons and 3.3 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. These sales commitments represent approximately 99%, 77% and 36% of our planned production of 8.6 million tons (including purchased coal to supplement our production), 8.7 million tons and 9.2 million tons for the years ending December 31, 2008, 2009 and 2010, respectively. For the year ended December 31, 2007 and the six months ended June 30, 2008, approximately 74% and 45%, respectively, of our aggregate sales were made under long-term contracts. We expect to continue selling a significant portion of our coal under long-term agreements.

Quality and volumes for the coal are stipulated in coal supply agreements, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply agreements 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 agreements 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.

Transportation

We ship coal to our customers by rail, truck or barge. The majority of our coal is transported to customers by either the CSX Rail or the NS Rail in eastern Kentucky and by the OHC Rail in Ohio. In addition, in southeastern Ohio, we use our own trucking operations to transport coal to our customers where rail is not available. Please read "—Coal Operations—Trucking." We use third-party trucking to transport coal to our customers in Colorado. 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. For the year ended December 31, 2007 and the six months ended June 30, 2008, substantially all of our coal sales tonnage was shipped by rail.

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

For the year ended December 31, 2007 and the six months ended June 30, 2008, we spent $108.4 million and $65.8 million, respectively, to obtain goods and services in support of our mining operations, excluding capital expenditures. Principal supplies used in our business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance

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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., Booth Energy Group, CONSOL Energy Inc., Foundation Coal Holdings, Inc., International Coal Group, Inc., James River Coal Company, Massey Energy Company, Murray Energy Corporation, Patriot Coal Corp. and TECO Energy, Inc.

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

Regulation and Laws

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

•: employee health and safety;
•: mine permits and other licensing requirements;
•: air quality standards;
•: water quality standards;
•: storage of petroleum products and substances that are regarded as hazardous under applicable laws or which, if spilled, could reach waterways or wetlands;
•: plant and wildlife protection;
•: reclamation and restoration of mining properties after mining is completed;
•: the discharge of materials into the environment;
•: storage and handling of explosives;
•: wetlands protection;
•: surface subsidence from underground mining;
•: the effects, if any, that mining has on groundwater quality and availability; and
•: legislatively mandated benefits for current and retired coal miners.

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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 legislation 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 do occur from time to time. 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, 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 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 mining operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. All requirements imposed by any of these authorities may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. Future legislation and administrative regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Legislation and regulations, as well as future interpretations 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.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Regulations also 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. The permitting process for certain mining operations has extended over several years and we cannot assure you that we will not experience difficulty in obtaining mining permits in the future.

Mine Health and Safety Laws

Stringent safety and health standards have been imposed by federal legislation since 1969 when the Coal Mine Health and Safety Act of 1969 was adopted. The Federal Mine Safety and Health Act of 1977, and regulations adopted pursuant thereto, significantly expanded the enforcement of health and

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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 MSHA monitors compliance with these federal laws and regulations. Most of 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. Our competitors in all of the areas in which we operate are subject to these same laws and regulations.

Our nonfatal days lost incidence rate was 32.8% below the industry average for the year ended December 31, 2007. Nonfatal 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 nonfatal days lost time incidence rate for all operations for the year ended December 31, 2007 was 2.18 as compared to the national average of 3.24 for the same period, as reported by the MSHA. For the six months ended June 30, 2008, our nonfatal days lost incidence rate was 2.39, 19.2% below the industry average of 2.96, based on preliminary data from MSHA.

In addition, for the year ended December 31, 2007 our average MSHA violations per inspection day was 0.54, as compared to the national average of 1.27 violations per inspection day, 57.4% below the national average.

These statistics demonstrate our commitment to providing a safe work environment and we have received industry-wide recognition for our safety record. For example, in February 2008, the Colorado Division of Reclamation, Mining and Safety and The Colorado Mining Association presented the Medium Underground Coal Mine Award to our McClane Canyon operation in Colorado for achieving an impressive reduction in their nonfatal days lost from 21.42 in 2004 to zero in 2007.

Mining accidents in the past years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices.

In 2006, MSHA promulgated new emergency rules on mine safety that address mine safety equipment, training, and emergency reporting requirements. The U.S. Congress enacted the Mine Improvement and New Emergency Response Act of 2006 (the "MINER Act"), which was signed into law on June 15, 2006. The MINER Act significantly amends the Federal Mine Safety and Health Act of 1977, 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. MSHA published final rules implementing the MINER Act to revise both the emergency rules and MSHA's existing civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations.

Implementing and complying with these state and federal laws and regulations could adversely affect our results of operations and financial position.

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

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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. 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 are also liable under state statutes for black lung and are covered through either insurance policies or state programs.

Congress and state legislatures regularly consider various items of black lung legislation, which, if enacted, could adversely affect our business, results of operations and financial position.

Workers' Compensation

We are required to compensate employees for work-related injuries. The states in which we operate consider changes in workers' compensation laws from time to time. 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

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. The act 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. Federal law and some states impose on mine operators the responsibility 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 before 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. The Abandoned Mine Lands tax was set to expire on June 30, 2006, but the program was extended until September 30, 2021. We have accrued 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.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. 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

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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.

Air Emissions

The Federal Clean Air Act ("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. 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 EPA laws and regulations 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, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal's share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations.

The 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 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. Additionally, in March 2005, EPA issued the final Clean Air Interstate Rule ("CAIR"), which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010, respectively. 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 D.C. Circuit Court of Appeals vacated CAIR in its entirety. It is unclear if EPA will seek appellate review of this decision, or if EPA will pursue other regulatory options including an amended or entirely new rule to address the emissions that are leading to the non-attainment with the CAA in the various eastern states.

In March 2005, EPA finalized the Clean Air Mercury Rule ("CAMR"), which establishes 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 D.C. Circuit Court of Appeals vacated the rule for further consideration by the U.S. EPA. While the future of the CAMR 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.

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EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. For example, in December 2004, EPA designated specific areas in the United States as in "non-attainment" with the new national ambient air quality standard for fine particulate matter. In March 2007, EPA published final rules addressing how states would implement plans to bring applicable non-attainment regions into compliance with the new air quality standard. Under EPA's final rule, states have until April 2008 to submit their implementation plans to EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, our mining operations and customers could be affected when the new standards are implemented by the applicable states.

In June 2005, EPA announced final amendments to its regional haze program originally developed in 1999 to improve visibility in national parks and wilderness areas. As part of the new rules, affected states must develop implementation plans 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 new standards are implemented by the applicable states.

The Department of Justice, on behalf of EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA. 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.

Carbon Dioxide Emissions

The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls for developed nations to reduce their emissions of greenhouse gases to five percent below 1990 levels by 2012. Carbon dioxide, which is a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005 for those nations that ratified the treaty.

In 2001, the United States withdrew its support for the Kyoto Protocol. There has been increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions and the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. By comparison, many states and regional organizations have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of regional greenhouse gas cap and trade programs. Many of these state-level measures have focused on emissions from coal-fired electric generating facilities. For example, ten Northeastern states have begun implementing a regional cap-and-trade program to begin on January 1, 2009, which is designed to stabilize and reduce greenhouse gas emissions from fossil fuel-fired power plants. Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) under CAA even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA's definition of "air pollutant" may also result in future regulation of greenhouse gas emissions from stationary sources under certain CAA programs. For instance, the Court's decision has influenced another lawsuit that was filed in the U.S. Court of Appeals for the District of Columbia Circuit, New York State, et al. v. EPA, involving a challenge to EPA's decision not to regulate carbon dioxide from power plants and other stationary sources under its February 27, 2006 new source performance standard for new electric

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utility steam generating units. The D.C. Circuit has remanded the issue related to the regulation of greenhouse gas emissions raised in New York State back to EPA for further regulatory consideration in light of the Supreme Court's holding in Massachusetts.

The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental organizations for concerns related to greenhouse gas emissions from the new plants. In October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant's projected emissions of carbon dioxide. State regulatory authorities in Florida and North Carolina have also rejected the construction of new coal-fired 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-fired power plants without limits on greenhouse gas emissions have been appealed to EPA's Environmental Appeals Board.

While higher prices for natural gas and oil, and improved efficiencies and new technologies for coal-fired electric power generation have helped to increase demand for our coal, it is possible that future federal and state initiatives to control and put a price on carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, which could have a material adverse effect on our business, financial condition and results of operations.

Clean Water Act

The Federal Clean Water Act ("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 ("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 or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into jurisdictional waters of the United States. Surface coal mining operators obtain such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills.

Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. The U.S. Army Corps of Engineers ("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. Nationwide Permit 21 authorizes the disposal of dredged or fill material from surface coal mining activities into the waters of the United States. A July 2004 decision by the U.S. District Court for the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the Corps from issuing further permits pursuant to Nationwide Permit 21. While this decision was vacated by the U.S. Court of Appeals for the Fourth Circuit in November 2005, it has been remanded to the District Court for the Southern District of West Virginia for further proceedings. Moreover, a similar lawsuit has been filed in the U.S. District Court for the Eastern District of Kentucky that seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the Corps. The plaintiffs have sought to amend their claims also to enjoin permits issued under Nationwide Permit 49 (Coal Remining Activities) and Nationwide Permit 50 (Underground Coal Mining Activities). We currently utilize certain of these Nationwide Permit authorizations, and these court cases have created uncertainty regarding our ability to utilize these types of permits in the future for the disposal of dredged or fill material.

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Individual CWA Section 404 permits for valley fill surface mining activities are also subject to legal uncertainties. On June 15, 2006, the U.S. Supreme Court decided the combined cases of Rapanos v. United States and Carabell v. U.S. Army Corps of Engineers, which concerned the geographic extent of the Corps regulatory jurisdiction over "waters of the United States" under the CWA. Rapanos addressed the question of whether the Corps' regulatory geographic jurisdiction under the CWA extends to wetlands that are adjacent to tributaries of navigable-in-fact waters. In the plurality opinion, four justices held that the lower courts should determine "whether the ditches or drains near each wetland are 'waters' in the ordinary sense of containing a relatively permanent flow; and (if they are) whether the wetlands in question are 'adjacent' to these 'waters' in the sense of possessing a continuous surface connection." While concurring in the plurality result, the concurrence announced a different jurisdictional test, concluding that the lower courts should determine "whether the specific wetlands at issue possess a significant nexus with navigable waters." On June 5, 2007, the EPA and Corps issued a joint guidance memorandum interpreting Rapanos, stating their position that CWA jurisdiction would exist if either test were met. Because our mining activities can affect hydrologic features that may be subject to CWA regulatory jurisdiction, continued uncertainty about the precise geographic extent of the Corps' regulatory jurisdiction under the CWA could impose additional time and cost burdens on our operations, potentially adversely affecting our ability to obtain permits and produce coal.

Plaintiff environmental groups have also recently challenged the Corps' decision to issue individual CWA Section 404 permits for certain surface coal mining activities. On March 23, 2007, in the case Ohio Valley Environmental Coalition v. U.S. Army Corps of Engineers, the U.S. District Court for the Southern District of West Virginia rescinded permits authorizing the construction of valley fills at a number of separate surface coal mining operations, finding that the Corps had issued the permits arbitrarily and capriciously in violation of the National Environmental Policy Act and the CWA. On June 13, 2007, the District Court issued a declaratory judgment indicating that the mining companies in the case were also required to obtain separate CWA Section 402 permit authorizations for discharges into the stream segments located between the toes of their valley fills and their respective sediment pond embankments. Both decisions have been appealed to the U.S. Court of Appeals for the Fourth Circuit. In December 2007, plaintiff environmental groups brought a similar suit against the issuance of a different surface coal mine permit in the U.S. District Court for the Eastern District of Kentucky, alleging identical violations. The Corps has voluntarily suspended its permit in that case for agency re-evaluation. Although permits for our mining operations are not presently joined to either case, it is possible that we may be unable to obtain or may experience delays in securing, utilizing or renewing additional CWA Section 404 individual permits for surface mining operations due to agency or court decisions stemming from these cases.

Total Maximum Daily Load ("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 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

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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. On March 31, 2006, the U.S. District Court for the Western District of Kentucky granted summary judgment in favor of the EPA and various intervening defendants, upholding the EPA's approval of Kentucky's antidegradation policy. The plaintiffs subsequently appealed the district court's decision to the U.S. Court of Appeals for the Sixth Circuit. An unfavorable decision on the merits by the Sixth Circuit could result in the elimination of the alternative implementation methodology for coal mining discharges or other provisions of Kentucky's antidegradation rules. Such an outcome 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 ("CERCLA"), or the "Superfund" law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Some products used by coal companies in operations generate waste containing hazardous substances. We are not aware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

The federal Resource Conservation and Recovery Act ("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 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.

In 1993 and 2000, EPA declined to impose hazardous waste regulatory controls under subtitle C of RCRA on the disposal of certain coal combustion by-products ("CCB"), including the practice of using CCB as mine fill. In its 2000 regulatory determination, EPA said that the disposal of CCB should be regulated under subtitle D as non-hazardous solid waste, by modifying SMCRA regulations or by a combination of both. The Department of the Interior's Office of Surface Mining Reclamation and Enforcement ("OSM") issued an advanced notice of proposed rulemaking on March 14, 2007 seeking comment on the development of rules for the disposal of CCB in active and abandoned mines. On August 29, 2007, EPA published in the Federal Register a Notice of Data Availability ("NODA") of analyses of the disposal of CCB in landfills and surface impoundments that have become available since EPA's RCRA regulatory determination in 2000. The NODA, however, is not a proposed rule nor does it include a timeframe for issuing a proposed rule. Meanwhile, residents in Maryland have filed a class action lawsuit against an energy company for alleged harms caused by their exposure to CCB disposed of in a landfill by the company. The plaintiffs allege common law tort claims against the company for disposing of the CCB without adequate controls and seek compensatory, punitive and equitable relief. 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

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associated with new requirements applicable to CCB handling or disposal could increase our customers' operating costs and potentially reduce their ability to purchase coal.

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

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 30, 2010, subject to us having two consecutive five-year renewal options.

Employees

To carry out our operations, our subsidiaries employed approximately 1,000 full-time employees as of June 30, 2008. 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. Wexford will provide certain advisory and administrative support, including legal services and assistance with financing transactions, to us pursuant to an administrative services agreement that we will enter into upon the consummation of this offering. Please read "Certain Relationships and Related Party Transactions—Administrative Services Agreement."

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we do not believe that we are a party to any litigation that will have a material adverse impact on our financial condition or results of operations. We are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us. We maintain insurance policies with insurers in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

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MANAGEMENT

Directors and Executive Officers

The following table shows information for our directors and executive officers upon the consummation of this offering:

Name	Age	Position
Mark D. Zand*	54	Chairman of the Board and member of the executive, compensation and nominating and corporate governance committees
Nicholas R. Glancy	53	President, Chief Executive Officer and Director and member of the executive committee
Richard A. Boone	54	Senior Vice President and Chief Financial Officer
David G. Zatezalo	53	Chief Operating Officer
Christopher N. Moravec	52	Senior Vice President—Business Development
Thomas Hanley	53	Senior Vice President—Administration
Jay L. Maymudes*	47	Director and member of the compensation and nominating and corporate governance committees
Arthur H. Amron*	51	Director and member of the nominating and corporate governance committee
Kenneth A. Rubin*	53	Director
Joseph M. Jacobs*	55	Director nominee
John P. McCarty	63	Director nominee and member of the audit committee
Eugene D. Aimone	64	Director nominee and member of the audit and compensation committees
Mark L. Plaumann	52	Director nominee and member of the audit committee

*: Wexford Partner

Mark D. Zand. Mr. Zand is a partner of Wexford. Mr. Zand joined Wexford 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's coal investments since their inception.

Nicholas R. Glancy. Mr. Glancy joined Rhino Energy LLC in October 2005 and became President in October 2006 and Chief Executive Officer in March 2007. Prior to serving as President of Rhino Energy LLC, Mr. Glancy acted as Senior Vice President and General Counsel of Rhino Energy LLC. Prior to joining Rhino Energy LLC, he served as a founding member of Sawyer & Glancy, PLLC, focusing on mineral law matters since 1997.

Richard A. Boone. Mr. Boone has been employed 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.

David G. Zatezalo. Mr. Zatezalo has been employed with Rhino Energy LLC as Chief Operating Officer since March 2007, in which role he is responsible for the operations of several subsidiaries of Rhino Energy LLC. Prior to joining Rhino Energy LLC in April 2004, Mr. Zatezalo served as President of AEP's various Appalachian Mining Operations and as General Manager of Windsor Coal Company. From 1995 to 1998 he served as General Manager of the Cliff Collieries and Manager of

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Underground Development in the Bowen Basin of Queensland for BHP Australia Coal. Mr. Zatezalo is a professional engineer registered in West Virginia and Ohio. Additionally, Mr. Zatezalo serves as Chairman of the Ohio Coal Association.

Christopher N. Moravec. Mr. Moravec has been employed as Senior Vice President of Business Development of Rhino Energy LLC since March 2007. 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. In this capacity, he directly managed a commercial loan portfolio and directed the bank's efforts in serving as an intermediary on behalf of coal industry clients to arrange syndicated financings, access private and public debt securities, and act as an agent in various merger and acquisition transactions.

Thomas Hanley. Mr. Hanley has been employed with Rhino Energy LLC since September 2007 as its Senior Vice President of Administration. Prior to joining Rhino Energy LLC, he was a vice president with Wexford where his main areas of focus were in evaluation, planning and optimization within the transportation and operations sector since September 2002.

Jay L. Maymudes. Mr. Maymudes is a partner of Wexford. He joined Wexford in 1994 and became a partner in 1997 and serves as Wexford's Chief Financial Officer. Mr. Maymudes is responsible for the financial, tax and reporting requirements of Wexford and all of its private investment partnerships and its trading activities. Mr. Maymudes is a Certified Public Accountant.

Arthur H. Amron. Mr. Amron is the General Counsel and a partner of Wexford. He joined Wexford 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.

Kenneth A. Rubin. Mr. Rubin is a partner of Wexford. He joined Wexford in 1996 and became a partner in 2001. Mr. Rubin focuses on both private and public equity investing and also has responsibility for select tax, corporate and legal matters.

Joseph M. Jacobs. Mr. Jacobs co-founded Wexford in 1994 and serves as its President. From 1982 to 1994, Mr. Jacobs was employed by Bear Stearns & Co., Inc., where he attained the position of Senior Managing Director. Mr. Jacobs is a director of several privately-held companies in which Wexford has an investment.

John P. McCarty. Mr. McCarty founded Lexington Capital Advisors, Inc., a financial consulting and real estate development firm, in August 1989 and serves as its President. In March 2007, Mr. McCarty became a founding member of McCarty-Strong Global, LLC, a business development and financial consulting firm. From October 2004 to November 2006, Mr. McCarty served as a Commissioner of New Business Development for the Commonwealth of Kentucky.

Eugene D. Aimone. Mr. Aimone has over 20 years experience in the coal industry with Black Beauty Coal Company and was a Principal of Black Beauty Resources, LLC. Since the sale of Black Beauty Resources, LLC in 2004, Mr. Aimone has been involved as an investor in various private business ventures. From 1994 to 2004, he served as Sr. Vice President of Marketing and Reserve Acquisition for Black Beauty Resources, LLC, in which capacity he was responsible for marketing and sales, transportation logistics, coal reserve identification and acquisition and coal price determination.

Mark L. Plaumann. Mr. Plaumann is currently a managing member of Greyhawke Capital Advisors LLC, which he co-founded in 1998. From 1995 to 1998, Mr. Plaumann was a Senior Vice President of Wexford. He was formerly a Managing Director of Alvarez and Marsal, Inc., the President of Healthcare Management Inc. and a Senior Manager at Ernst & Young LLP.

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Board of Directors

Even though most companies listed on The New York Stock Exchange are required to have a majority of "independent," as defined under the independence standards established by The New York Stock Exchange and SEC rules, directors serving on the board of directors of the listed company, The New York Stock Exchange does not require a controlled company like us to have a majority of independent directors on the board of directors. A "controlled company" is defined as a listed company of which more than 50% of the voting power is held by an individual, a group or another company under The New York Stock Exchange rules.

Upon the consummation of this offering, we will have nine directors. We are generally required to have at least three independent directors serving on the board at all times. John P. McCarty, Eugene D. Aimone and Mark L. Plaumann are "independent" under the standards established by The New York Stock Exchange and the SEC rules.

At each annual meeting of stockholders, directors will be elected to hold office until the next annual meeting.

In addition, our bylaws will provide that the authorized number of directors may be changed by a resolution duly adopted by the board of directors. Vacancies and newly created directorships may be filled by the affirmative vote of a majority of our directors then in office.

Our board of directors will have an executive committee, an audit committee, a compensation committee and a nominating and corporate governance committee.

Executive Committee. Our executive committee will initially consist of Messrs. Zand and Glancy. Upon completion of this offering our executive committee will operate pursuant to a written charter. The executive committee will exercise the powers and authority of the board of directors to direct our business and affairs in intervals between meetings of the board.

Audit Committee. Our audit committee will initially consist of Messrs. McCarty, Aimone and Plaumann. Upon consummation of this offering, we expect our board of directors to determine that Mr. McCarty is an "audit committee financial expert" within the meaning of the SEC rules. Upon completion of this offering, our audit committee will operate pursuant to a written charter. This committee will oversee, review, act on and report to our board of directors 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 will oversee our compliance programs relating to legal and regulatory requirements.

Compensation Committee. Our compensation committee will initially consist of Messrs. Zand, Maymudes and Aimone. Upon completion of this offering, our compensation committee will operate pursuant to a written charter. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans.

Nominating and Corporate Governance Committee. Our nominating and corporate governance committee will initially consist of Messrs. Zand, Amron and Maymudes. Upon the completion of this offering our nominating and corporate governance committee will operate pursuant to a written charter. The committee is appointed by our board of directors (1) to assist the board by identifying individuals qualified to become board members, and to recommend to the board the director nominees for the next annual meeting of shareholders; (2) to develop and recommend to the board the corporate governance guidelines; (3) to lead the board in its annual review of the board's compensation and performance; and (4) to recommend to the board director nominees for each committee.

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Executive Officer Compensation

Pre-Offering

Compensation for each of the following executive officers was determined pursuant to employment agreements with Rhino Energy LLC. Except for Mr. Hanley, who joined in September 2007 as Senior Vice President—Administration, the following table sets forth the historical annual compensation paid by Rhino Energy LLC for the following executive officers for 2006 and 2007:

Name and Principal Position with Rhino Energy LLC	Year	Salary($)		Bonus($)		All Other Compensation($)		Total($)
Nicholas R. Glancy President, Chief Executive Officer and Director(1)	2007 2006	$ $	349,999 250,000	$ $	723,333 706,666	$ $	1,756 810	$ $	1,075,088 956,666
Richard A. Boone Senior Vice President and Chief Financial Officer(2)	2007 2006	$ $	225,179 206,923	$ $	77,628 47,100	$ $	75,255 828	$ $	378,062 254,851
David G. Zatezalo Chief Operating Officer(3)	2007 2006	$ $	286,154 194,423	$ $	120,000 20,192	$	15,553 —	$ $	421,707 214,615
Christopher N. Moravec Senior Vice President—Business Development(4)	2007 2006	$	176,308 n/a	$	103,000 n/a	$	99,901 n/a	$	379,209 n/a

(1): With respect to "Bonus($)," the 2006 bonus includes a $666,666 fixed bonus and the 2007 bonus includes a $583,333 fixed bonus, each awarded pursuant to the terms of Mr. Glancy's employment agreement.
(2): With respect to "All Other Compensation($)," the amount includes $73,306 for moving expense reimbursement.
(3): With respect to "Bonus($)," the 2006 bonus represents the fixed bonus awarded pursuant to the terms of Mr. Zatezalo's employment agreement. With respect to "All Other Compensation($)," the amount includes $13,058 for moving expense reimbursement.
(4): With respect to "Bonus($)," the 2007 bonus includes a $35,000 sign-on bonus. With respect to "All Other Compensation($)," the amount includes $99,033 for moving expense reimbursement.

Post-Offering

Following the offering, we expect that our named executive officers will consist of Messrs. Glancy, Boone, Zatezalo, Moravec and Hanley. The compensation for our named executive officers is determined pursuant to employment agreements between such executive officer and us. Please read "—Employment Agreements."

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The following table sets forth the expected annual compensation for our named executive officers upon the consummation of this offering:

Name and Principal Position	Salary		Bonus
Nicholas R. Glancy President and Chief Executive Officer(1)	$	385,000	0% to 40% of salary
Richard A. Boone Senior Vice President and Chief Financial Officer	$	228,000	0% to 40% of salary
David G. Zatezalo Chief Operating Officer	$	325,000	0% to 40% of salary
Christopher N. Moravec Senior Vice President—Business Development(2)	$	240,000	0% to 40% of salary
Thomas Hanley Senior Vice President—Administration	$	220,000	0% to 40% of salary

(1): Mr. Glancy is also entitled to a fixed bonus of $566,666 in November 2008 in addition to the discretionary bonus.
(2): Mr. Moravec is also entitled to fixed bonuses of $250,000 in March 2009 and $350,000 in March 2010 in addition to the discretionary bonus.

The following named executive officers will each receive a one-time cash bonus in the amount set out beside each name, payable within 30 days of completion of our initial public offering: Mr. Glancy ($250,000), Mr. Boone ($100,000), Mr. Zatezalo ($100,000), Mr. Moravec ($150,000) and Mr. Hanley ($100,000).

In connection with this offering, the following named executive officers will each receive a grant of restricted stock under the Rhino Resources, Inc. Long-Term Incentive Plan, which we refer to as the "long-term incentive plan," in the number of shares set out beside each name: Mr. Glancy ( ), Mr. Boone ( ), Mr. Zatezalo ( ), Mr. Moravec ( ) and Mr. Hanley ( ). The restricted stock will vest in one-third increments over a three-year period, subject to earlier vesting upon a change of control or upon a termination without cause or due to death or disability. In addition, the restricted stock will include any dividends we declare. Mr. Glancy will also be entitled to shares of unrestricted stock, which are not subject to forfeiture. The grants will be made within three business days of the closing of the initial public offering. Please read "—Long-Term Incentive Plan."

Compensation Discussion and Analysis

Except for the base salary, Mr. Glancy's fixed bonus of $566,666 in November 2008 and Mr. Moravec's fixed bonuses of $250,000 in March 2009 and $350,000 in March 2010 provided for in the employment agreements, all other compensation for the named executive officers for services rendered to us will be determined by our compensation committee. Our "named executive officers" will include our Chief Executive Officer, our Chief Financial Officer and the three other most highly compensated executive officers, which will consist of those executive officers identified above. The compensation committee will seek 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. Once established after the offering, we believe it is likely that the compensation committee will examine the compensation practices of our peer companies. We believe that our peer companies include Alliance Resource Partners LP, Alpha Natural Resources, Inc., International Coal Group, Inc., James River Coal

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Company and Patriot Coal Corp. Changes may occur from time to time in the composition of this peer group to reflect mergers, acquisitions, initial public offerings and similar events. We believe that the compensation committee will also review compensation data from the coal industry as it believes that the competition for executive talent is broader than just the peer companies. In addition, the compensation committee may review and, in certain cases, participate in, various relevant compensation surveys and consult with compensation consultants with respect to determining compensation for the named executive officers. We expect that our Chief Executive Officer, Mr. Glancy, will provide periodic recommendations to the compensation committee regarding the compensation of other named executive officers.

The primary elements of our compensation program will be a combination of annual cash and long-term equity-based compensation. The principal elements of compensation for the named executive officers are expected to be the following:

•: base salary;
•: bonus awards;
•: long-term incentive plan awards; and
•: other benefits.

Base Salary. To the extent not provided for in the existing employment agreements, our compensation committee will establish base salaries for the named executive officers based on various factors including the amounts it considers necessary to attract and retain the highest quality executives, the responsibilities of the named executive officers and market data such as publicly available market data for the peer companies listed above as reported in their filings with the SEC. The compensation committee will review the base salaries on an annual basis. As part of its review, the compensation committee may review the compensation of executives in similar positions with similar responsibility in the peer companies listed above and in companies in the coal industry with which we believe we generally compete for executives.

As indicated below, each of Messrs. Glancy, Boone, Zatezalo, Moravec and Hanley recently entered into an employment agreement with us in contemplation of our initial public offering. The employment agreements provide for an annual base salary in the amount set out beside each name: Mr. Glancy ($385,000), Mr. Boone ($228,000), Mr. Zatezalo ($325,000), Mr. Moravec ($240,000) and Mr. Hanley ($220,000). These initial base salary amounts were determined based upon the scope of each executive's responsibilities as well as the added responsibilities the executives will have following this offering that are typical of executives in publicly traded corporations, taking into account competitive market compensation paid by similar companies for comparable positions.

Bonus Awards. In addition to the one-time cash bonus upon the consummation of this offering, our compensation committee may also award discretionary bonus awards to the named executive officers. We intend to use discretionary bonus awards for achieving financial and operational goals and for achieving individual performance objectives. Pursuant to the employment agreements of our named executive officers, such discretionary bonuses will be up to 40% of the annual salary for each respective named executive officer. Mr. Glancy is also entitled to a fixed bonus of $566,666 in November 2008 in addition to the discretionary bonus. Mr. Moravec is also entitled to fixed bonuses of $250,000 in March 2009 and $350,000 in March 2010 in addition to the discretionary bonus.

Long-Term Incentive Plan Awards. We intend to adopt a long-term incentive plan for our employees, consultants and directors and those of our affiliates who perform services for us. Each of Messrs. Glancy, Boone, Zatezalo, Moravec and Hanley will be eligible to participate in this plan. The long-term incentive plan provides for the grant of restricted stock, stock options, stock appreciation

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rights and substitute awards. For a more detailed description of this plan, please read "—Long-Term Incentive Plan."

In connection with our initial public offering, the following named executive officers will each receive a grant of restricted stock under the long-term incentive plan in the number of shares set out beside each name: Mr. Glancy ( ), Mr. Boone ( ), Mr. Zatezalo ( ), Mr. Moravec ( ) and Mr. Hanley ( ). The restricted stock will vest in one-third increments over a three-year period, subject to earlier vesting upon a change of control or upon a termination without cause or due to death or disability. In addition, the restricted stock will include any dividends we declare. Mr. Glancy will also be entitled to shares of unrestricted stock, which are not subject to forfeiture. Please read "—Long-Term Incentive Plan."

Other Benefits. The employment agreements for each of the named executive officers provide that the named executive officer is eligible to participate in our 401(k) plan. Please read "—401(k) Plan" for additional information. Additional benefits and perquisites for our named executive officers may include payment of premiums for supplemental life insurance, long-term disability insurance and automobile fringe benefits.

Our compensation committee will determine the mix of compensation, both among short-term and long-term compensation and cash and non-cash compensation, to establish structures 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 long-term incentive plan and the other benefits that will be available to the named executive officers will accomplished our overall compensation objectives. We believe this mix of compensation provides 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

Each of Messrs. Glancy, Boone, Zatezalo, Moravec and Hanley will have an employment agreement with us. These agreements have termination dates ranging from December 31, 2009 through May 31, 2011 and provide for a base salary, a discretionary bonus (and fixed bonuses in the case of Messrs. Glancy and Moravec), a bonus upon the consummation of this offering, as described above in "—Executive Officer Compensation—Post-Offering," and participation in certain benefit plans.

In each case, the agreement provides that the employer may terminate the agreement at any time "for cause" as defined therein. In the event of termination for cause or voluntary resignation, the employee will no longer have any right to any benefits which would otherwise have accrued after such termination.

In addition, each employee, other than Mr. Hanley, has agreed not to directly or indirectly engage in the business of coal mining or coal marketing in Central Appalachia, Northern Appalachia, the Illinois Basin or western Colorado for up to one year following the date of termination for cause or his voluntary resignation.

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Potential Payments upon a Change of Control or Termination

The following table shows potential payments to the named executive officers under existing employment agreements for various scenarios involving termination of employment of each such named executive officer:

Name		Termination without Cause		Disability		Death		Resignation with Good Reason
Nicholas R. Glancy
	Severance(1)	$	385,000	$	385,000	$	385,000	$	385,000
	LTIP Award(2)	$	2,500,000	$	2,500,000	$	2,500,000	$	2,500,000
Richard A. Boone
	Severance(1)	$	228,000	$	228,000	$	228,000	$	228,000
	LTIP Award(2)	$	700,000	$	700,000	$	700,000	$	700,000
David G. Zatezalo
	Severance(1)	$	325,000	$	325,000	$	325,000	$	325,000
	LTIP Award(2)	$	1,100,000	$	1,100,000	$	1,100,000	$	1,100,000
Christopher N. Moravec
	Bonus(3)	$	120,000	$	—	$	—	$	—
	LTIP Award(2)	$	500,000	$	500,000	$	500,000	$	500,000
Thomas Hanley
	Severance(4)	$	110,000	$	110,000	$	—	$	110,000
	LTIP Award(2)	$	700,000	$	700,000	$	700,000	$	700,000

(1): Each of Messrs. Glancy, Boone and Zatezalo would be entitled to a lump sum severance payment equal to a year's salary upon termination of his employment other than for "cause," "disability" (such terms as defined below) or death, or if he voluntarily resigns for "good reason" (as defined below) under the employment agreements currently in place. Under such employment agreements, "cause" is defined as the executive officer's (a) failure to perform substantially his duties (other than any such failure resulting from incapacity due to disability) within ten days after written notice, (b) conviction of, or plea of guilty or no contest to a felony or a misdemeanor involving dishonesty or moral turpitude, (c) engaging in any illegal conduct, gross misconduct or other material breach of the employment agreement or (d) engaging in any act of dishonesty or fraud involving us or any of our affiliates. "Disability" is defined as the inability of the executive officer to perform his normal duties as a result of any physical or mental injury or ailment for (a) any consecutive 45 day period or (b) any 90 days (whether or not consecutive) during any 365 calendar day period. "Good reason" is defined as (a) the assignment to the executive officer of any duties inconsistent in any material aspect with those of the office to which the executive officer is assigned, (b) a reduction in the base salary, (c) a reduction in the executive officer's benefit and retirement plans or (d) any purported termination of the executive officer's employment under the employment agreement other than for "cause," "disability" or death.
(2): In connection with our initial public offering, the following named executive officers will each receive a grant of restricted stock under the long-term incentive plan in the number of shares set out beside each name: Mr. Glancy ( ), Mr. Boone ( ), Mr. Zatezalo ( ), Mr. Moravec ( ) and Mr. Hanley ( ). The restricted stock is subject to earlier vesting upon a change of control or due to termination without cause, death or disability or voluntary resignation with good reason (as such terms are defined in the grant agreement). In connection with our initial public offering, Mr. Glancy will receive a grant of shares of unrestricted stock under the long-term incentive plan. The dollar values of the LTIP awards were calculated based on the assumed initial public price of $ per share.

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(3): Mr. Moravec would be entitled to the accrued portion of his fixed bonus if he is terminated without "cause" (as defined below) under the employment agreement between Mr. Moravec and Rhino Energy LLC. In addition, Mr. Moravec would be entitled to a lump sum severance payment equal to six month's salary and six months of health insurance coverage at no premium cost to him. If such termination without "cause" takes place within 18 months after a "change of control" (as defined below), Mr. Moravec would be entitled to a one-time bonus of $375,000. Under the employment agreement, "cause" is defined where Mr. Moravec (a) committed an act of dishonesty against or fraud upon Rhino Energy LLC, (b) breached his obligations under the employment agreement and failed to cure such breach within five days after written notice, (c) has been indicted for or convicted of a crime involving moral turpitude or (d) materially failed or neglected to diligently perform his duties under the employment agreement. A "change of control" is defined as (a) a sale by Rhino Energy LLC of substantially all of its assets, unless such transaction results in such assets being owned or controlled by Wexford and/or its affiliates, either directly or indirectly, or (b) a sale of the ownership interest in Rhino Energy LLC by all entities affiliated with Wexford and constituting more than a 50% interest in Rhino Energy LLC, unless such transaction occurs through a public offering of securities or results in at least 51% of such ownership interests being owned or controlled by Wexford and/or its affiliates, either directly or indirectly.
(4): Mr. Hanley would be entitled to severance payments equal to six month's salary if he is terminated without "cause" or "disability" (such terms as defined below) or if he terminates his employment for "good reason" (as defined below) under the employment agreement between Mr. Hanley and Rhino Energy LLC. In addition, Mr. Hanley would have been entitled to health insurance coverage for six months at no premium cost to him. "Cause" is defined as (a) the indictment or conviction of Mr. Hanley of any felony or of a misdemeanor involving an act of fraud or dishonesty or of a crime of moral turpitude, (b) the commission of any act of fraud or dishonesty in the performance of his duties for or on behalf of Rhino Energy LLC, (c) any material breach by Mr. Hanley of any other term of the employment agreement, after ten business days notice and opportunity to cure or (d) the inability or failure of Mr. Hanley to devote his full business time and attention to the services to be provided by Mr. Hanley. "Disability" is defined as Mr. Hanley being unable or unwilling to perform his principal functions due to a physical or mental impairment, but only if such inability has lasted or is reasonably expected to last for at least 60 consecutive calendar days of any 12 month period. "Good reason" is defined as any material breach by Rhino Energy LLC of any term or provision of the employment agreement after ten business days' notice and opportunity to cure.

Director Compensation

Our employees who also serve as directors will not receive additional compensation. Directors who are not our employees will receive (1) a $30,000 annual cash retainer, (2) $1,500 for each board of directors or committee meeting attended in person and (3) $750 for each board of directors or committee meeting participated in telephonically. The chair of the audit committee of our board of directors will receive an additional $10,000 annual cash retainer. In addition, each director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Long-Term Incentive Plan

Our board of directors will adopt the long-term incentive plan for our employees, consultants, executive officers and directors who perform services for us. The long-term incentive plan will consist of the following components: restricted stock, stock options, performance award, phantom shares, stock

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payment, stock appreciation rights and other stock-based awards. The long-term incentive plan will limit the number of shares that may be delivered pursuant to awards to % of the outstanding common stock on the effective date of the initial public offering of our common stock. Shares withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan will be administered by our board of directors or a committee thereof, which we refer to as the plan administrator.

The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any shares of our common stock for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of shares that may be granted, subject to stockholder approval as required by the exchange upon which our common stock is listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. The plan will expire when shares are no longer available under the plan for grants or, if earlier, its termination by the plan administrator.

Restricted Stock

A restricted stock grant is an award of common stock that vests over a period of time and that during such time is subject to forfeiture. The plan administrator may determine to make grants of restricted stock under the plan to participants containing such terms as the plan administrator shall determine. The plan administrator will determine the period over which restricted stock granted to participants will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives. In addition, the restricted stock will vest upon a change of control of our company, as defined in the plan, unless provided otherwise by the plan administrator. Dividends made on restricted stock may or may not be subjected to the same vesting provisions as the restricted stock. If a grantee's employment, consulting or membership on the board of directors terminates for any reason, the grantee's restricted stock will be automatically forfeited unless, and to the extent that, the plan administrator or the terms of the award agreement provide otherwise.

We intend the restricted stock under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common stock. Therefore, plan participants will not pay any consideration for our common stock they receive, and we will receive no remuneration for the restricted stock.

Stock Options

The long-term incentive plan will permit the grant of options covering our common stock. The plan administrator may make grants under the plan to participants containing such terms as the plan administrator shall determine. Stock options will have an exercise price that may not be less than the fair market value of our common stock on the date of grant. In general, stock options granted will become exercisable over a period determined by the plan administrator. In addition, the stock options will become exercisable upon a change of control of our company, unless provided otherwise by the plan administrator. If a grantee's employment, consulting or membership on the board of directors terminates for any reason, the grantee's unvested stock options will be automatically forfeited unless, and to the extent, the option agreement, an employment agreement or the plan administrator provides otherwise.

Upon exercise of a stock option, we will acquire shares of common stock on the open market or from any other person or we will directly issue common stock or use any combination of the foregoing, in the plan administrator's discretion. If we issue new shares upon exercise of the stock options, the total number of shares outstanding will increase. The availability of stock options is intended to furnish

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additional compensation to plan participants and to align their economic interests with those of common stockholders.

Performance Award

A performance award is denominated as a cash amount at the time of grant and gives the grantee the right to receive all or part of such award upon the achievement of specified financial objectives, length of service or other specified criteria. The plan administrator will determine the period over which certain specified financial objectives or other specified criteria must be met. The performance award may be paid in cash, shares or a combination of cash and shares. If a grantee's employment, consulting or membership on the board of directors terminates for any reason, the grantee's performance award will be automatically forfeited unless, and to the extent that, the plan administrator or the terms of the award agreement provide otherwise.

Phantom Shares

A phantom share is a notional share of our common stock that entitles the grantee to receive a common share upon the vesting of the phantom share or, in the discretion of the plan administrator, cash equivalent to the value of a share of our common stock. The plan administrator may determine to make grants of phantom shares under the plan to participants containing such terms as the plan administrator shall determine. The plan administrator will determine the period over which phantom shares granted to participants will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives. In addition, the phantom shares will vest upon a change of control of our company, unless provided otherwise by the plan administrator. If a grantee's employment, consulting or membership on the board of directors terminates for any reason, the grantee's phantom shares will be automatically forfeited unless, and to the extent that, the plan administrator or the terms of the award agreement provide otherwise.

Upon the vesting of phantom shares, we will acquire shares of common stock on the open market or from any other person or we will directly issue common stock or use any combination of the foregoing, in the plan administrator's discretion. If we issue new shares upon vesting of the phantom shares, the total shares outstanding will increase. The plan administrator, in its discretion, may grant tandem dividend equivalent rights with respect to phantom shares that entitle the holder to receive cash equal to any cash dividends made on common stock while the phantom shares are outstanding.

We intend the issuance of any common shares upon vesting of the phantom shares under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common stock. Therefore, plan participants will not pay any consideration for the common stock they receive, and we will receive no remuneration for the shares.

Stock Payment

The plan administrator, in its discretion, may also grant to participants common stock that is not subject to forfeiture.

Stock Appreciation Rights

The long-term incentive plan will permit the grant of stock appreciation rights. A stock appreciation right is an award that, upon exercise, entitles participants to receive the excess of the fair market value of our common stock on the exercise date over the exercise price established for the stock appreciation right. Such excess will be paid in cash or shares of our common stock. The plan administrator may determine to make grants of stock appreciation rights under the plan to participants containing such terms as the plan administrator shall determine. Stock appreciation rights will have an

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exercise price that may not be less than the fair market value of our common stock on the date of grant. In general, stock appreciation rights granted will become exercisable over a period determined by the plan administrator. In addition, the stock appreciation rights will become exercisable upon a change in control of our company, unless provided otherwise by the plan administrator. If a grantee's employment, consulting or membership on the board of directors terminates for any reason, the grantee's unvested stock appreciation rights will be automatically forfeited unless, and to the extent that, the grant agreement, an employment agreement or plan administrator provides otherwise.

Upon exercise of a stock appreciation right, we will acquire shares of common stock on the open market or in a private transaction or we will directly issue common stock or use any combination of the foregoing, in the plan administrator's discretion. If we issue new shares upon exercise of the stock appreciation rights, the total number of shares outstanding will increase. The availability of stock appreciation rights is intended to furnish additional compensation to plan participants and to align their economic interests with those of common stockholders.

Other Stock-Based Awards

The plan administrator, in its discretion, may also grant to participants an award denominated or payable in, referenced to, or otherwise based on or related to the value of our common stock.

401(k) Plan

Rhino Energy LLC, CAM Mining LLC and McClane Canyon Mining LLC are included under the CAM Mining LLC 401(k) Plan (the "401(k) Plan"), with Hopedale Mining LLC, Rhino Coalfield Services LLC and Sands Hill Mining LLC having separate 401(k) Plans. The companies use the 401(k) Plan to assist their eligible employees in saving for retirement on a tax-deferred basis. The 401(k) Plan permits all eligible employees to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. A discretionary employer matching contribution may also be made to the plan for those eligible employees who meet certain conditions and subject to certain limitations under federal law. The employer matching contribution percentage, if any, will be determined each year. Employee contributions are subject to annual dollar limitations, which are periodically adjusted by the cost of living index. The 401(k) Plan is intended to be tax-qualified under section 401(a) of the Internal Revenue Code so that contributions to the plan, and income earned on plan contributions, are not taxable to employees until withdrawn from the plan, and so that contributions, if any, will be deductible when made.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND THE SELLING STOCKHOLDER

The following table sets forth the beneficial ownership of common stock of Rhino Resources, Inc. that will be issued and outstanding upon the consummation of this offering and the related transactions and held by

•: beneficial owners of 5% or more of our common stock;
•: each director, director nominee and executive officer;
•: all of our directors, director nominees and executive officers as a group; and
•: Rhino Energy Holdings LLC, the selling stockholder.

The following table does not include any shares that may be purchased in this offering, including in the directed share program. Please read "Underwriting" for a description of the directed share program.

						Common Stock to be Beneficially Owned After this Offering(1)
	Common Stock Beneficially Owned Prior to the Offering			Common Stock Offered		Assuming the Underwriters' Option is Not Exercised			Assuming the Underwriters' Option is Exercised in Full
Name of Beneficial Owner	Common Stock Beneficially Owned Prior to the Offering			Assuming the Underwriters' Option is Not Exercised	Assuming the Underwriters' Option is Exercised in Full	Assuming the Underwriters' Option is Not Exercised			Assuming the Underwriters' Option is Exercised in Full
Name of Beneficial Owner	Number	Percentage		Assuming the Underwriters' Option is Not Exercised	Assuming the Underwriters' Option is Exercised in Full	Number	Percentage		Number	Percentage
Rhino Energy Holdings LLC(2)(3)		100	%					%			%
Charles E. Davidson(2)(3)		100	%					%			%
Joseph M. Jacobs(2)(3)		100	%					%			%
Wexford(2)(3)		100	%					%			%
Mark D. Zand(3)	—	—	%	—	—	—	—	%	—	—	%
Nicholas R. Glancy(4)	—	—	%	—	—			%			%
Richard A. Boone(4)	—	—	%	—	—			%			%
David G. Zatezalo(4)	—	—	%	—	—			%			%
Christopher N. Moravec(4)	—	—	%	—	—			%			%
Thomas Hanley(4)	—	—	%	—	—			%			%
Jay L. Maymudes(3)	—	—	%	—	—	—	—	%	—	—	%
Arthur H. Amron(3)	—	—	%	—	—	—	—	%	—	—	%
Kenneth A. Rubin(3)	—	—	%	—	—	—	—	%	—	—	%
John P. McCarty(5)	—	—	%	—	—	—	—	%	—	—	%
Eugene D. Aimone(6)	—	—	%	—	—	—	—	%	—	—	%
Mark L. Plaumann(7)
All directors and executive officers as a group (13 persons)		100	%					%			%

*: Less than 1%.
(1): Includes shares of restricted and unrestricted common stock issued to management under our long-term incentive plan.
(2): Shares shown as beneficially owned by Charles E. Davidson, Joseph M. Jacobs and Wexford reflect shares owned of record by Rhino Energy Holdings LLC. Wexford serves as manager for Rhino Energy Holdings LLC and as such may be deemed to share beneficial ownership of the shares beneficially owned by Rhino Energy Holdings LLC, but disclaims such beneficial ownership. Messrs. Davidson and Jacobs, as the managing members of Wexford, may be deemed to share beneficial ownership of the shares beneficially owned by Rhino Energy Holdings LLC for which Wexford serves as manager, but disclaim such beneficial ownership.
(3): The address for this person or entity is 411 West Putnam Avenue, Greenwich, Connecticut 06830.
(4): The address for this person is 424 Lewis Hargett Circle, Suite 250, Lexington, Kentucky 40503. Shares shown as beneficially owned by this person consist of restricted and/or unrestricted common stock issued under our long-term incentive plan.
(5): The address for this person is 444 East Main Street, Suite 102, Lexington, Kentucky 40507.
(6): The address for this person is 250 Cross Point Boulevard, Evansville, Indiana 47715.
(7): The address for this person is 340 Pemberwick Road, 1st Floor, Greenwich, Connecticut 06831.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In connection with this offering, we will enter into the following transactions and contractual arrangements with our officers, directors and principal stockholders. Although we have not historically had formal policies and procedures regarding the review and approval of related party transactions, all transactions outside of the ordinary course of business between us and any of our officers, directors and principal stockholders will be approved by our board of directors. Our board of directors will adopt a written policy that will require our audit committee to review on an annual basis all transactions with related parties, or in which a related party has a direct or indirect interest, and to determine whether to ratify or approve the transaction after consideration of the related party's interest in the transaction and other material facts. We believe that the terms of these arrangements and agreements will be at least as favorable as they would have been had we contracted with an unrelated third party.

Ownership Interests of Rhino Energy Holdings LLC, Wexford Funds and the Wexford Partners

In connection with this offering, Rhino Energy Holdings LLC and certain Wexford Funds will contribute 100% of the ownership interests in Rhino Energy LLC to us in exchange for an aggregate of shares of our outstanding common stock. The Wexford Funds will then contribute their shares of our common stock to Rhino Energy Holdings LLC in exchange for ownership interests in Rhino Energy Holdings LLC. Rhino Energy Holdings LLC, as the selling stockholder, will sell shares of our common stock, representing % of our outstanding common stock, to the public in this offering. After this offering, Rhino Energy Holdings LLC will own shares of our outstanding common stock, representing approximately % of our outstanding common stock (or shares, representing approximately % of our outstanding common stock, if the underwriters exercise their option to purchase additional shares in full).

The Wexford Partners, which include Mark D. Zand, Jay L. Maymudes, Arthur H. Amron, Kenneth A. Rubin and Joseph M. Jacobs, own interests in the Wexford Funds.

Wexford has advised us that following the closing of the offering it and the investment funds it manages will not enter into any transaction with us unless the transaction is approved by the disinterested members of our board of directors. Our bylaws provide that any interested party transaction between us, on the one hand, and Rhino Energy Holdings LLC, Wexford and their affiliates, on the other hand must be approved by a majority of our directors not otherwise affiliated with Wexford or any of its affiliates.

Proceeds to Rhino Energy Holdings LLC

Rhino Energy Holdings LLC will receive approximately $ million in net proceeds from the sale of shares to the public as the selling stockholder in this offering (based on an assumed initial offering price of $ per share). We will pay all the offering expenses of Rhino Energy Holdings LLC, excluding the underwriting discounts. Rhino Energy Holdings LLC has informed us that it intends to distribute the net proceeds it receives from the sale of our common stock to Wexford Funds. Accordingly, the Wexford Partners may indirectly receive proceeds from this offering.

Administrative Services Agreement

Upon the closing of this offering, we will enter into an administrative services agreement with Wexford. Under this agreement, Wexford will provide us with certain advisory and administrative support, including legal services and assistance with financing transactions. The fee charged by Wexford will be determined either (1) based on the time expended by its employees on our matters and the actual out-of-pocket expenses incurred by Wexford on our behalf or (2) as we and Wexford otherwise agree. This agreement is not the result of arm's-length negotiations and may not have been effected on terms at least as favorable to the parties to this agreement as could have been obtained from

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unaffiliated third parties. However, going forward, transactions under the administrative services agreement will be governed by our bylaws as an interested party transaction.

Registration Rights Agreement

We will enter into a registration rights agreement with Rhino Energy Holdings LLC. Under the registration rights agreement, Rhino Energy Holdings LLC will have the right, in certain circumstances after the consummation of this offering, to require us to register for sale some or all of the shares of common stock held by Rhino Energy Holdings LLC. Subject to the terms and conditions of the registration rights agreement, Rhino Energy Holdings LLC will have the right to make three such "demands" for registration, one of which may require a shelf registration statement. In addition, in connection with registered offerings by us after the consummation of this offering, whether pursuant to a "demand" registration or otherwise, Rhino Energy Holdings LLC will have the ability to exercise certain "piggyback registration rights" and have some or all of its shares included in the registration statement. Notwithstanding the foregoing, no registration statement may be filed during the lock-up period following the date of this prospectus, as described under "Shares Eligible for Future Sale—Sale of Restricted Shares and Lock-Up Agreements." We will bear all costs of registration pursuant to the registration rights provided in the registration rights agreement. Transactions under the registration rights agreement may be subject to our bylaws as an interested party transaction.

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DESCRIPTION OF OUR CAPITAL STOCK

The following description of material terms of our capital stock and certain provisions of our certificate of incorporation and bylaws, each of which will be in effect on the completion of this offering, are summaries and are qualified by reference to the certificate of incorporation and bylaws, forms of which have been filed as exhibits to the registration statement, of which this prospectus forms a part.

Authorized Capital

Our authorized capital stock consists of:

•: 500,000,000 shares of common stock, par value $0.01 per share; and
•: 10,000,000 shares of preferred stock, par value $0.01 per share.

Common Stock

Upon the completion of this offering, we expect that there will be shares of common stock issued and outstanding (including shares of unrestricted stock and excluding shares of restricted stock).

Voting Rights

Each holder of common stock will be entitled to one vote per share on all matters to be voted on by stockholders except those matters on which a separate class of stockholders vote by class to the exclusion of the shares of common stock. Generally, matters to be voted on by stockholders must be approved by the vote of a majority (or, in the case of election of directors and routine matters, a plurality) of our outstanding common stock. Except as otherwise required by the Delaware General Corporation Law (the "DGCL"), our certificate of incorporation or the voting rights granted to any preferred stock we subsequently issue, the holders of outstanding shares of common stock and preferred stock entitled to vote thereon, if any, will vote as one class with respect to all matters to be voted on by our stockholders.

Dividend Rights

Subject to preferences that may apply to shares of preferred stock outstanding at the time, the holders of outstanding shares of our common stock are entitled to receive dividends out of funds legally available if our board of directors, in its discretion, determines to declare dividends and only then at the times and in the amounts that our board of directors may determine.

No Preemptive or Similar Rights

Holders of common stock do not have any preemptive, subscription or conversion rights.

Right to Receive Liquidation Distributions

Upon our dissolution, liquidation or winding-up, the assets legally available for distribution to our stockholders are distributable ratably among the holders of our common stock, subject to prior satisfaction of all outstanding debts and liabilities and the preferential rights and payment of liquidation preferences, if any, on any outstanding shares of preferred stock.

Preferred Stock

Our board of directors will be authorized, without further stockholder approval except as may be required by applicable The New York Stock Exchange rules, to issue from time to time up to an aggregate of 10,000,000 shares of preferred stock in one or more series and to fix or alter the

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designations, preferences, rights and any qualifications, limitations or restrictions of the shares of each such series thereof, including the dividend rights, dividend rates, conversion rights, voting rights, terms of redemption (including sinking fund provisions), redemption price or prices, liquidation preferences and the number of shares constituting any series or designations of such series. No shares of preferred stock are presently outstanding and we have no present plans to issue any shares of preferred stock.

Stock Awards Under the Long-Term Incentive Plan

We will issue shares of restricted stock and shares of unrestricted stock to management under our long-term incentive plan within three business days of the closing of the initial public offering. Please read "Management—Executive Officer Compensation—Compensation Discussion and Analysis—Long-Term Incentive Plan Awards," "Management—Long-Term Incentive Plan" and "Shares Eligible for Future Sale."

Anti-Takeover Effects of Certain Provisions of Delaware Law, the Certificate of Incorporation and the Bylaws

Some provisions of the DGCL and our certificate of incorporation and bylaws could make the following transactions more difficult:

•: acquisition of our company by means of a tender offer, a proxy contest or otherwise; and
•: removal of our incumbent officers and directors.

These provisions, summarized below, are expected to discourage and prevent coercive takeover practices and inadequate takeover bids. These provisions are designed to encourage persons seeking to acquire control of our company to first negotiate with our board of directors. They are also intended to provide our management with the flexibility to enhance the likelihood of continuity and stability if our board of directors determines that a takeover is not in the best interests of our stockholders. These provisions, however, could have the effect of discouraging attempts to acquire us, which could deprive our stockholders of opportunities to sell their shares of common stock at prices higher than prevailing market prices.

Election and Removal of Directors.

Our certificate of incorporation and our bylaws will contain provisions that establish specific procedures for appointing and removing members of the board of directors. In addition, our certificate of incorporation and bylaws will provide that vacancies and newly created directorships on the board of directors may be filled only by a majority of the directors then serving on the board (except as otherwise required by law or by resolution of the board).

Undesignated Preferred Stock

The authorization of undesignated, or "blank check," preferred stock will make it possible for our board of directors to issue preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of our company. Please read "—Preferred Stock."

Requirements for Advance Notification of Stockholder Nominations and Proposals

Our bylaws will establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors or a committee of the board of directors. Please read "—Advance Notice Requirements for Stockholder Proposals and Director Nominations."

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No Cumulative Voting

Under Delaware law, cumulative voting for the election of directors is not permitted unless a corporation's certificate of incorporation authorizes cumulative voting. Our certificate of incorporation and bylaws will not provide for cumulative voting in the election of directors. Cumulative voting allows a minority stockholder to vote a portion or all of its shares for one or more candidates for seats on the board of directors. Without cumulative voting, a minority stockholder will not be able to gain as many seats on our board of directors based on the number of shares of our stock the stockholder holds as the stockholder would be able to gain if cumulative voting were permitted. The absence of cumulative voting makes it more difficult for a minority stockholder to gain a seat on our board of directors to influence our board's decision regarding a takeover. Further, after this offering Rhino Energy Holdings LLC will own shares of our outstanding common stock, representing approximately % of our outstanding common stock (or shares, representing approximately % of our outstanding common stock, if the underwriters exercise their option to purchase additional shares in full), making it impossible for a minority stockholder to gain any seat on our board of directors.

These and other provisions could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions that stockholders may otherwise deem to be in their best interests.

Advance Notice Requirements for Stockholder Proposals and Director Nominations

Our bylaws will provide that stockholders seeking to bring business before an annual meeting of stockholders, or to nominate candidates for election as directors at an annual meeting of stockholders, must provide timely notice thereof in writing. To be timely, a stockholder's notice must be delivered to the company secretary between the 120^th day and the 90^th day before the anniversary of the preceding year's annual meeting. If, however, the date of the meeting is advanced more than 30 days before, or delayed more than 70 days after, the anniversary of the annual meeting, notice must be delivered between the 120^th day before the meeting and the later of the 90^th day before the meeting or the 10^th day after we publicly announce the date of the meeting. Our bylaws also will specify certain requirements as to the form and content of a stockholder's notice. These provisions may preclude stockholders from bringing matters before an annual meeting of stockholders or from making nominations for directors at an annual meeting of stockholders.

Authorized but Unissued Shares

The authorized but unissued shares of common stock and preferred stock are available for future issuance without stockholder approval, except as may be required by applicable New York Stock Exchange rules. These additional shares may be used for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans.

Corporate Opportunities

Our certificate of incorporation will provide for the allocation of certain corporate opportunities between us, on the one hand, and Rhino Energy Holdings LLC, Wexford and their affiliates, on the other hand. Specifically:

•: None of Rhino Energy Holdings LLC, Wexford and their affiliates (whether or not they are also a director, officer or employee of Rhino Resources, Inc. except as provided below) will have any duty to refrain from engaging directly or indirectly in any investments, business activities or lines of business.

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•: We will renounce any interest or expectancy that we may have in any potential transaction or opportunity for Rhino Energy Holdings LLC, Wexford or their respective affiliates, as applicable, on the one hand, and us, on the other hand, and therefore none of Rhino Energy Holdings LLC, Wexford or their affiliates will have any duty to communicate or offer any corporate opportunity to us and will be entitled to pursue or acquire any opportunity. Notwithstanding the prior sentence, we are not renouncing any interest or expectancy in any corporate opportunity that is offered to an affiliate of Rhino Energy Holdings LLC or Wexford who is also one of our directors, officers, or employees, if (i) such opportunity is expressly offered to such party solely in, and as a direct result of, his or her capacity as our director, officer or employee; (ii) we would be permitted to undertake the opportunity under our certificate of incorporation, and (iii) we have sufficient financial resources to undertake the opportunity, as determined by our board of directors.

Amendments to Certificate of Incorporation or Bylaws

The affirmative vote of the holders of at least a majority of our issued and outstanding common stock, voting as a single class, is generally required to amend or repeal our certificate of incorporation. In addition, under the DGCL, an amendment to our certificate of incorporation that would alter or change the powers, preferences or special rights of the common stock so as to affect them adversely also must be approved by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class. Subject to our bylaws, our board of directors may from time to time make, amend, supplement or repeal our bylaws by vote of a majority of our board of directors.

Registration Rights

We will enter into a registration rights agreement with Rhino Energy Holdings LLC. For more information on the registration rights agreement, please read "Certain Relationships and Related Party Transactions—Registration Rights Agreement."

Transfer Agent and Registrar

American Stock Transfer and Trust Company will serve as registrar and transfer agent for our common stock.

Listing

We have been approved to list our common stock on The New York Stock Exchange under the symbol "RNO."

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SHARES ELIGIBLE FOR FUTURE SALE

Before this offering, there has been no public market for our common stock, and we cannot assure you that a significant public market for our common stock will develop or be sustained after this offering. Sales of significant amounts of our common stock in the public market after this offering, or the perception that such sales could occur, could adversely affect the prevailing market price of our common stock and could impair our future ability to raise capital through the sale of our equity securities.

Sale of Restricted Shares and Lock-Up Agreements

In connection with the completion of this offering, we expect that there will be shares of common stock issued and outstanding, which includes the shares of unrestricted stock to be issued to management but excludes the shares of restricted stock to be issued to management. Please read "—Stock Awards Under the Long-Term Incentive Plan."

Of the shares of common stock to be outstanding upon completion of this offering, shares of common stock offered pursuant to this offering will be freely tradable without restriction or further registration under federal securities laws, except to the extent shares of common stock are purchased in this offering by our affiliates, as that term is defined in Rule 144 under the Securities Act of 1933.

We, all of our executive officers and directors and Rhino Energy Holdings LLC, will agree with the underwriters not to offer, sell, dispose of or hedge any shares of our common stock or securities convertible into or exchangeable for shares of our common stock, subject to specified limited exceptions and extensions described elsewhere in this prospectus, during the period continuing through the date that is 180 days (subject to extension) after the date of this prospectus, except with the prior written consent of , on behalf of the underwriters. , in its sole discretion on behalf of the underwriters, may release any of the securities subject to these lock-up agreements at any time without notice. The lock-up period may be extended in the circumstances described under "Underwriting."

Rule 144

Our common stock sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act of 1933, except that any common stock held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act of 1933 or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•: 1% of the total number of the securities outstanding; or
•: the average weekly reported trading volume of our common stock for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale, and who has beneficially owned shares of our common stock for at least six months, would be entitled to sell those shares under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted shares for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those shares without regard to any of the conditions of Rule 144.

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Registration Rights

Stock Awards Under the Long-Term Incentive Plan

We will file a registration statement on Form S-8 under the Securities Act of 1933 covering shares of our common stock that may be issued under our long-term incentive plan. Accordingly, shares of our common stock registered under such registration statement will be available for sale in the open market upon exercise by the holders (if applicable), subject to vesting restrictions, Rule 144 limitations applicable to our affiliates and the contractual lock-up provisions described above.

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CERTAIN U.S. FEDERAL TAX CONSIDERATIONS
FOR NON-U.S. HOLDERS

The following is a general discussion of certain U.S. federal income and estate tax consequences of the ownership and disposition of our common stock by a non-U.S. holder. As used in this discussion, the term "non-U.S. holder" means a beneficial owner of our common stock that is not, for United States federal income tax purposes:

•: an individual who is a citizen or resident of the United States;
•: a corporation (including any entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;
•: an estate whose income is subject to U.S. federal income taxation regardless of its source; or
•: a trust, if a U.S. court is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have authority to control all substantial decisions of the trust, or if it has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.

An individual may be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, instead of a nonresident, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in that calendar year. For purposes of the 183-day calculation, all of the days present in that calendar year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year are counted. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens.

This discussion does not consider:

•: U.S. state or local or non-U.S. tax consequences;
•: all aspects of U.S. federal income and estate taxes or specific facts and circumstances that may be relevant to a particular non-U.S. holder's tax position, including the fact that, in the case of a non-U.S. holder that is an entity treated as a partnership for U.S. federal income tax purposes, the U.S. tax consequences of holding and disposing of our common stock may be affected by certain determinations made at the partner level;
•: the tax consequences for the stockholders, partners or beneficiaries of a non-U.S. holder;
•: special tax rules that may apply to particular non-U.S. holders, such as financial institutions, insurance companies, tax-exempt organizations, U.S. expatriates, broker-dealers, and traders in securities; or
•: special tax rules that may apply to a non-U.S. holder that holds our common stock as part of a "straddle," "hedge," "conversion transaction," "synthetic security" or other integrated investment.

The following discussion is based on provisions of the U.S. Internal Revenue Code of 1986, as amended, existing and proposed Treasury Regulations and administrative and judicial interpretations, all as of the date of this prospectus, and all of which are subject to change, retroactively or prospectively. The following summary assumes that a non-U.S. holder holds our common stock as a capital asset.

If you are considering the purchase of our common stock, you are urged to consult your own tax advisors regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.

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Distributions on Common Stock

Cash distributions on our common stock generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. If any such distribution exceeds our current and accumulated earnings and profits, the excess will be treated as a non-taxable return of capital to the extent of your tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. Dividends paid to non-U.S. holders of our common stock that are not effectively connected with the non-U.S. holder's conduct of a U.S. trade or business will be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable income tax treaty.

A non-U.S. holder that wishes to claim the benefit of an applicable income tax treaty will be required to comply with certain certification requirements, which generally can be met by providing a properly executed Internal Revenue Service Form W-8BEN. However,

•: in the case of common stock held by a foreign partnership, the certification requirement will generally be applied to the partners of the partnership and the partnership will be required to provide certain information;
•: in the case of common stock held by a foreign trust, the certification requirement will generally be applied to the trust or the beneficial owners of the trust depending on whether the trust is a "foreign complex trust," "foreign simple trust" or "foreign grantor trust" as defined in the U.S. Treasury Regulations; and
•: look-through rules will apply for tiered partnerships, foreign simple trusts and foreign grantor trusts.

A non-U.S. holder that is a foreign partnership or a foreign trust is urged to consult its own tax advisor regarding its status under the Treasury Regulations and the certification requirements applicable to it. A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for refund with the Internal Revenue Service.

Dividends that are effectively connected with a non-U.S. holder's conduct of a trade or business in the United States and, if an income tax treaty applies, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons (as defined in the Internal Revenue Code). In that case, we will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements. In addition, a "branch profits tax" may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a foreign corporation that are effectively connected with its conduct of a trade or business in the United States.

Gain on Disposition of Common Stock

A non-U.S. holder generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:

•: the gain is effectively connected with the non-U.S. holder's conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States;
•: the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements; or

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•: we are or have been a "U.S. real property holding corporation" for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock.

A non-corporate non-U.S. holder described in the first bullet point above will be subject to tax on the net gain realized from the sale under regular graduated U.S. federal income tax rates in the same manner as if it were a U.S. person. If a non-U.S. holder that is a foreign corporation is described in the first bullet point above, it will be subject to tax on its net gain in the same manner as if it were a U.S. person and may also be subject to the branch profits tax at a rate of 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty. An individual non-U.S. holder described in the second bullet point above will be subject to a flat 30% tax on the gain derived from the sale or other disposition, which may be offset by U.S. source capital losses, even though the individual is not considered a resident of the United States.

Generally, a corporation is a U.S. real property holding corporation, or USRPHC, if the fair market value of its U.S. real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we are a USRPHC for U.S. federal income tax purposes. However, the tax relating to the disposition of stock in a USRPHC generally will not apply to a non-U.S. holder that actually or by application of constructive ownership rules owned 5% or less of our common stock at all times during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock, provided that our common stock was considered to be "regularly traded on an established securities market." If a non-U.S. holder actually or constructively owned more than 5% of our common stock at any time during the applicable period or our stock were not considered to be "regularly traded on an established securities market," any gain recognized by the non-U.S. holder on the sale or other disposition would be treated as effectively connected with a U.S. trade or business and would be subject to U.S. federal income tax at regular graduated U.S. federal income tax rates in much the same manner as applicable to United States persons.

U.S. Federal Estate Tax

Common stock owned or treated as owned by an individual who is a non-U.S. holder for U.S. federal estate tax purposes at the time of death will be included in the individual's gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise, and therefore may be subject to U.S. federal estate tax.

Information Reporting and Backup Withholding Tax

We must report annually to the Internal Revenue Service and to you the amount of dividends paid to you and any tax withheld with respect to those dividends, regardless of whether withholding is required. Copies of the information returns may also be made available to the tax authorities in the country in which you reside under the provisions of an applicable income tax treaty. U.S. backup withholding tax is imposed at a current rate of 28% on certain payments to persons that fail to furnish the information required under the U.S. information reporting requirements. You will be exempt from this backup withholding tax if you properly provide a Form W-8BEN certifying that you are a not a U.S. person or otherwise meet documentary evidence requirements for establishing that you are not a U.S. person or you otherwise establish an exemption.

The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S. information reporting, but not backup withholding, will generally apply to

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a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that:

•

is a U.S. person;

•

is a foreign person that derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the United States;

•

is a "controlled foreign corporation" for U.S. tax purposes; or

•

is a foreign partnership, if at any time during its tax year:

•: one or more of its partners are U.S. persons who in the aggregate hold more than 50% of the income or capital interests in the partnership; or
•: the foreign partnership is engaged in a U.S. trade or business,

unless the broker has documentary evidence in its files that you are a non-U.S. person and certain other conditions are met, or you otherwise establish an exemption.

If you receive payments of the proceeds of a sale of our common stock to or through a U.S. office of a broker, the payment is subject to both U.S. backup withholding and information reporting unless you properly provide a Form W-8BEN certifying that you are a non-U.S. person or you otherwise establish an exemption.

Backup withholding is not an additional tax. You generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability by timely filing a properly completed claim for refund with the Internal Revenue Service.

THE FOREGOING DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF STATE, LOCAL OR FOREIGN TAX LAWS AND TAX TREATIES.

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UNDERWRITING

is acting as the representative of the underwriters and as book-running manager of this offering. Under the terms of an underwriting agreement, which is filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us and the selling stockholder the respective number of shares of our common stock shown opposite its name below:

Underwriters			Number of Shares

	Total

The underwriting agreement provides that the underwriters' obligation to purchase the common stock depends on the satisfaction of the conditions contained in the underwriting agreement including:

•: the obligation to purchase all of the common stock offered hereby (other than those shares covered by their option to purchase additional shares as described below), if any of the common stock is purchased;
•: the representations and warranties made by us and the selling stockholder to the underwriters are true;
•: there is no material change in our business or the financial markets; and
•: we and the selling stockholder deliver customary closing documents to the underwriters.

The following table summarizes the underwriting discounts we and the selling stockholder will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us and the selling stockholder for our common stock.

			No Exercise		Full Exercise
Per share
	Total

The representative of the underwriters has advised us that the underwriters propose to offer the common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per share. After the offering, the representative may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be $2.0 million (excluding the underwriting discounts). We will pay all offering expenses of the selling stockholder, excluding the underwriting discounts.

The selling stockholder has granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of shares at the public offering price less underwriting discounts. This option may be exercised if the underwriters sell more than shares in connection with this offering. To the extent that this

151

option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter's underwriting commitment in the offering as indicated in the table at the beginning of this section.

At our request, the underwriters will reserve up to shares, or % of the shares of common stock offered by this prospectus for sale, at the initial public offering price, to our directors, officers, and employees. The number of shares of common stock available for sale to the general public will be reduced to the extent these individuals purchase such reserved shares. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. We have agreed to indemnify in connection with the directed share program, including for the failure of any participant to pay for its shares.

We, our executive officers and directors, have agreed, without the prior written consent of not to directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of our common stock (including, without limitation, shares that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the Securities and Exchange Commission and shares of our common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common stock, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of our common stock, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of our common stock or other securities, in cash or otherwise, (3) cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of our common stock or securities convertible, exercisable or exchangeable into our common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:

•: during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or
•: prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by .

The restrictions described in this paragraph do not apply to:

•: the issuance and sale of our common stock by us to the underwriters pursuant to the underwriting agreement; or
•: the issuance and sale of our common stock, restricted stock and options under our existing employee benefits plans, including sales pursuant to "cashless-broker" exercises of options to purchase shares of our common stock in accordance with such plans as consideration for the exercise price and withholding taxes applicable to such exercises.

in its sole discretion, may release our common stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release shares of common stock and other securities from lock-up agreements, will consider, among other factors, the holder's reasons for requesting the release, the number of shares of our common stock and other securities for which the release is being

152

requested and market conditions at the time. However, has informed us that, as of the date of this prospectus, there are no agreements between and any party that would allow such party to transfer any shares of our common stock, nor does have any intention at this time of releasing any of our common stock subject to the lock-up agreements, prior to the expiration of the lock-up period.

We, the selling stockholder and our subsidiaries have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933 and to contribute to payments that the underwriters may be required to make for these liabilities.

In order to facilitate the offering of the common stock, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common stock. Specifically, the underwriters may sell more shares than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of shares available for purchase by the underwriters under the over-allotment option. The underwriters can close out a covered short sale by exercising the over-allotment option or purchasing shares in the open market. In determining the source of shares to close out a covered short sale, the underwriters will consider, among other things, the open market price of shares compared to the price available under the over-allotment option. The underwriters may also sell shares in excess of the over-allotment option, creating a naked short position. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in this offering. As an additional means of facilitating this offering, the underwriters may bid for, and purchase, shares of common stock in the open market to stabilize the price of the common stock. These activities may raise or maintain the market price of the common stock above independent market levels or prevent or retard a decline in the market price of the common stock. The underwriters are not required to engage in these activities and may end any of these activities at any time.

Neither we, the selling stockholder nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we, the selling stockholder nor any of the underwriters make representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us, the selling stockholder or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

We have been approved to list our common stock on The New York Stock Exchange under the symbol "RNO."

153

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares offered by them.

If you purchase shares of our common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Pricing of the Offering

Prior to this offering, there has been no public market for our common stock. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common stock, the representatives will consider:

•: the history and prospects for the industry in which we compete;
•: our financial information;
•: the ability of our management and our business potential and earning prospects;
•: the prevailing securities markets at the time of this offering; and
•: the recent market prices of, and the demand for, publicly traded common stock of generally comparable corporations.

European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•: to any legal entity that is authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;
•: to any legal entity that has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;
•: to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representative; or
•: in any other circumstances that do not require the publication of a prospectus pursuant to Article 3 of the Prospectus Directive,

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

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VALIDITY OF OUR COMMON STOCK

The validity of our common stock will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. Certain legal matters in connection with our common stock offered hereby will be passed upon for the underwriters by .

EXPERTS

The consolidated financial statements of Rhino Energy LLC (the "Company") as of December 31, 2006 and 2007, and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 included in this prospectus and the related consolidated financial statement schedule included elsewhere in this registration statement have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein and elsewhere in this registration statement (which report regarding the consolidated financial statements expresses an unqualified opinion and includes explanatory paragraphs concerning the adoption of SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R), and a change in the Company's fiscal year end). Such consolidated financial statements and consolidated financial statement schedule have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The statements of financial position of Rhino Resource Partners, L.P. as of December 31, 2006 and 2007, included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such statements of financial position are so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The information appearing in this prospectus concerning estimates of our proven and probable coal reserves, non-reserve coal deposits, proven and probable limestone reserves and non-reserve limestone deposits for the Tug River mining complex, Rob Fork mining complex, Deane mining complex, Bolt field, Hopedale mining complex, Sands Hill mining complex, Leesville field, Springdale field, Taylorville field and McClane Canyon mine was prepared by Marshall Miller and has been included herein upon the authority of this firm as an expert.

The information appearing in this prospectus concerning estimates of the proven and probable coal reserves for the Eagle mining complex was prepared by Boyd and has been included herein upon the authority of this firm as an expert.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common stock. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and our common stock offered in this prospectus, you may desire to review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates or from the SEC's web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC's website as provided above. Our website on the Internet will be located at http://www.rhinoresources.com, and we expect to make our periodic

155

reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our stockholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our stockholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "will," "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

We do not undertake any responsibility to release publicly any revisions to these forward-looking statements to take into account events or circumstances that occur after the date of this prospectus. Additionally, we do not undertake any responsibility to update you on the occurrence of any unanticipated events which may cause actual results to differ from those expressed or implied by the forward-looking statements contained in this prospectus.

The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

•: market demand for coal, electricity and steel;
•: future economic or capital market conditions;
•: weather conditions or catastrophic weather-related damage;
•: our production capabilities;
•: the consummation of financing, acquisition or disposition transactions and the effect thereof on our business;
•: our plans and objectives for future operations and expansion or consolidation;
•: our relationships with, and other conditions affecting, our customers;
•: timing of reductions in customer coal inventories;
•: long-term coal supply arrangements;
•: inherent risks of coal mining beyond our control;
•: environmental laws, including those directly affecting our coal mining and production, and those affecting our customers' coal usage;
•: competition in coal markets;
•: railroad and other transportation performance and costs;
•: our assumptions concerning economically recoverable coal reserve estimates;
•: employee workforce factors;
•: regulatory and court decisions;
•: future legislation and changes in regulations, governmental policies or taxes;
•: changes in post-retirement benefit obligations;
•: our liquidity, results of operations and financial condition; and
•: other factors, including those discussed in "Risk Factors."

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INDEX TO FINANCIAL STATEMENTS

RHINO RESOURCES, INC.
	UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
		Introduction	F-2
		Unaudited Pro Forma Consolidated Statement of Financial Position as of June 30, 2008	F-3
		Unaudited Pro Forma Consolidated Statement of Operations for the Six Months Ended June 30, 2008	F-4
		Unaudited Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 2007	F-5
		Notes to Unaudited Pro Forma Consolidated Financial Statements	F-6
RHINO ENERGY LLC
	CONSOLIDATED FINANCIAL STATEMENTS
*Interim Financial Statements*
		Condensed Consolidated Statement of Financial Position (Unaudited) as of June 30, 2008	F-10
		Condensed Consolidated Statements of Operations (Unaudited) for the Six Months Ended June 30, 2007 and 2008	F-11
		Condensed Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2007 and 2008	F-12
		Notes to the Unaudited Historical Condensed Consolidated Financial Statements	F-13
*Annual Financial Statements*
		Report of Independent Registered Public Accounting Firm	F-23
		Consolidated Statements of Financial Position as of December 31, 2006 and 2007	F-24
		Consolidated Statements of Operations for the Year Ended March 31, 2006, the Nine Months Ended December 31, 2006 and the Year Ended December 31, 2007	F-25
		Consolidated Statements of Members' Equity for the Year Ended March 31, 2006, the Nine Months Ended December 31, 2006 and the Year Ended December 31, 2007	F-26
		Consolidated Statements of Cash Flows for the Year Ended March 31, 2006, the Nine Months Ended December 31, 2006 and the Year Ended December 31, 2007	F-27
		Notes to Consolidated Financial Statements	F-28
RHINO RESOURCE PARTNERS, L.P.
	STATEMENTS OF FINANCIAL POSITION
*Interim Financial Statement*
		Statement of Financial Position (Unaudited) as of June 30, 2008	F-48
		Notes to Unaudited Statement of Financial Position	F-49
*Annual Financial Statements*
		Report of Independent Registered Public Accounting Firm	F-50
		Statements of Financial Position as of December 31, 2006 and 2007	F-51
		Notes to Statements of Financial Position	F-52

F-1

RHINO RESOURCES, INC.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Introduction

Rhino Resources, Inc. (the "Company") will own and operate the business of Rhino Energy LLC and its subsidiaries effective with the contribution of the ownership interests in Rhino Energy LLC from Rhino Energy Holdings LLC and certain investment funds managed by the Company's sponsor, Wexford Capital LLC (the "Wexford Funds"). The contribution of the business of Rhino Energy LLC to the Company will be recorded at historical cost as it is considered to be a reorganization of entities under common control. The unaudited pro forma consolidated financial statements for the Company have been derived from the historical consolidated statements of financial position and operations of Rhino Energy LLC set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical consolidated statements of financial position and operations and related notes contained therein. The unaudited pro forma consolidated financial statements should be read in conjunction with the notes accompanying such financial statements and with the historical consolidated statements of financial position and operations and related notes set forth elsewhere in this prospectus.

The accompanying unaudited pro forma consolidated financial statements reflect:

•: the contribution by Rhino Energy Holdings LLC and certain Wexford Funds of 100% of the ownership interests in Rhino Energy LLC to the Company in exchange for an aggregate of shares of the Company's common stock;
•: the issuance by the Company to the public of shares of our common stock;
•: the issuance of shares of restricted stock and shares of unrestricted stock to be issued to management under the Company's long-term incentive plan;
•: the use of approximately $ million of the net proceeds to repay outstanding indebtedness under the credit facility, a portion of which was used to finance the acquisitions of the Sands Hill and Deane mining complexes and the Company's investment in the joint venture that acquired the Eagle mining complex and the Bolt field, leaving approximately $ million of outstanding indebtedness under the credit facility and approximately $ million of total indebtedness on a pro forma basis as of June 30, 2008;
•: the payment of the estimated underwriting discount and offering expenses of approximately $ million; and
•: the provision for income taxes under the Company's corporate holding company structure.

The unaudited pro forma consolidated statement of financial position as of June 30, 2008 assumes the offering and related transactions occurred as of June 30, 2008. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2007 and the six months ended June 30, 2008 assume that the offering and related transactions occurred on January 1, 2007.

The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma consolidated financial information.

F-2

RHINO RESOURCES, INC.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF FINANCIAL POSITION

AS OF JUNE 30, 2008

			Rhino Energy LLC Historical			Pro Forma Adjustments			Rhino Resources, Inc. Pro Forma
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	1,153,088		$		(a)	$
								(b)
								(c)
	Accounts receivable			33,563,345
	Advance royalties, current portion			1,198,717
	Inventories			9,972,833
		Prepaid expenses and other		8,093,695			—

		Total current assets		53,981,678			—

PROPERTY, PLANT AND EQUIPMENT:
	At cost, including coal properties, mine development and contract costs			334,175,898			—
	Less accumulated depreciation, depletion and amortization			(83,968,511	)		—

	Net property, plant and equipment			250,207,387			—
	Advance royalties, net of current portion			2,867,463			—
	Investment in unconsolidated affiliate			16,056,742			—
	Other non-current assets			2,530,390

TOTAL			$	325,643,660		$	—		$

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
	Accounts payable		$	21,901,923		$	—		$
	Accrued expenses and other			19,060,910				(d)
	Current portion of long-term debt			6,904,865			—
	Current portion of asset retirement obligations			974,503			—
	Current portion of postretirement benefits			91,785			—

	Total current liabilities			48,933,986
NON-CURRENT LIABILITIES
	Long-term debt			83,423,701				(c)
	Asset retirement obligations			51,846,466			—
	Other non-current liabilities			916,655			—
	Deferred tax liabilities			—				(g)
	Postretirement benefits			4,942,749			—

	Total non-current liabilities			141,129,571

	Total liabilities			190,063,557
MEMBERS' EQUITY:
	Members' investment			23,158,642				(e)		—
	Retained earnings			111,833,085				(e)		—
	Accumulated other comprehensive income			588,376				(e)		—

	Total members' equity			135,580,103						—

Stockholders' equity:
	Preferred stock, par value $0.01 per share, 10,000,000 shares authorized, no shares issued and outstanding at June 30, 2008						—			—
	Common stock, par value $0.01 per share, 500,000,000 shares authorized, shares issued and outstanding at June 30, 2008			—				(e)
	Additional paid-in capital			—				(e)
	Retained earnings			—				(e)
	Accumulated other comprehensive income			—				(e)

		Total stockholders' equity		—

TOTAL			$	325,643,660		$	—		$

See notes to unaudited pro forma consolidated financial statements.

F-3

RHINO RESOURCES, INC.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2008

		Rhino Energy LLC Historical			Pro Forma Adjustments			Rhino Resources, Inc. Pro Forma
REVENUES:
Coal revenues		$	211,219,336		$	—		$
Freight and handling revenues			4,072,658			—
Other revenues			7,727,147			—

Total revenues			223,019,141			—

	COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			172,489,899			—
Freight and handling costs			4,132,216			—
Depreciation, depletion and amortization			17,247,375			—
Selling, general and administrative			8,814,617				(h)
(Gain) loss on retirement of advance royalties			7,998
(Gain) loss on sale of assets			(376,192	)		—

Total costs and expenses			202,315,913

INCOME (LOSS) FROM OPERATIONS			20,703,228
INTEREST AND OTHER INCOME (EXPENSE)
Interest expense			(2,557,172	)			(f)
Interest income			100,542			—
Equity in net income (loss) of unconsolidated affiliate			(38,480	)
Other—net			—			—

	Total interest and other expenses		(2,495,110	)

INCOME BEFORE INCOME TAXES			18,208,118
INCOME TAX EXPENSE			—				(g)

NET INCOME		$	18,208,118		$			$

PRO FORMA EARNINGS PER SHARE
Earnings per share, basic								$
Earnings per share, diluted								$
Weighted average shares outstanding, basic
Weighted average shares outstanding, diluted

See notes to unaudited pro forma consolidated financial statements.

F-4

RHINO RESOURCES, INC.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2007

		Rhino Energy LLC Historical			Pro Forma Adjustments			Rhino Resources, Inc. Pro Forma
REVENUES:
Coal revenues		$	394,078,915		$	—		$
Freight and handling revenues			4,052,430			—
Other revenues			5,320,452			—

	Total revenues		403,451,797			—

COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			318,520,554			—
Freight and handling costs			4,020,747			—
Depreciation, depletion and amortization			30,749,773			—
Selling, general and administrative			15,370,333				(h)
(Gain) loss on retirement of advance royalties			(115,277	)		—
(Gain) loss on sale of assets			(944,303	)		—

Total costs and expenses			367,601,827

INCOME (LOSS) FROM OPERATIONS			35,849,970
INTEREST AND OTHER INCOME (EXPENSE)
Interest expense			(5,579,224	)			(f)
Interest income			316,710			—
Other—net			—			—			—

	Total interest and other expenses		(5,262,514	)

INCOME BEFORE INCOME TAXES			30,587,456
INCOME TAX (BENEFIT) EXPENSE			(126,308	)			(g)

NET INCOME		$	30,713,764		$			$

PRO FORMA EARNINGS PER SHARE
Earnings per share, basic								$
Earnings per share, diluted								$
Weighted average shares outstanding, basic
Weighted average shares outstanding, diluted

See notes to unaudited pro forma consolidated financial statements.

F-5

RHINO RESOURCES, INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEAR ENDED DECEMBER 31, 2007 AND AS OF AND

FOR THE SIX MONTHS ENDED JUNE 30, 2008

1. ORGANIZATION AND BASIS OF PRESENTATION

The unaudited pro forma consolidated financial information is derived from the historical consolidated statements of financial position and operations of Rhino Energy LLC.

The unaudited pro forma consolidated financial statements reflect:

•: the contribution by Rhino Energy Holdings LLC and certain Wexford Funds of 100% of the ownership interests in Rhino Energy LLC to the Company in exchange for an aggregate of shares of the Company's common stock;
•: the issuance by the Company to the public of shares of our common stock;
•: the issuance of shares of restricted stock and shares of unrestricted stock to be issued to management under the Company's long-term incentive plan;
•: the use of approximately $ million of the net proceeds to repay outstanding indebtedness under the credit facility, a portion of which was used to finance the acquisitions of the Sands Hill and Deane mining complexes and the Company's investment in the joint venture that acquired the Eagle mining complex and the Bolt field, leaving approximately $ million of outstanding indebtedness under the credit facility and approximately $ million of total indebtedness on a pro forma basis as of June 30, 2008;
•: the payment of the estimated underwriting discount and offering expenses of approximately $ million; and
•: the provision for income taxes under the Company's corporate holding company structure.

Upon the consummation of this offering, the Company anticipates incurring incremental selling, general and administrative expenses related to becoming a publicly traded corporation (e.g., the increased accounting support services, filing annual and quarterly reports with the SEC, increased audit fees, investor relations, directors' fees, directors' and officers' insurance, legal fees, stock exchange listing fees and registrar and transfer agent fees) in an annual amount of approximately $3.0 million. The unaudited pro forma consolidated financial statements do not reflect this $3.0 million in incremental selling, general and administrative expenses.

2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

(a): Reflects the gross proceeds to Rhino Resources, Inc. of $ million for the issuance and sale of shares of common stock at an assumed initial public offering price of $ per share, representing the midpoint of the offering price range. Each $1.00 increase or decrease in the assumed public offering price of $ per share would increase or decrease total stockholders' equity by approximately $ million, assuming that the number of shares offered by the Company, as set forth on the cover page of this prospectus, remains the same, and after deducting underwriting discounts and estimated offering expenses payable by the Company. The estimated proceeds assume that the underwriters do not exercise their option to purchase additional shares of common stock in this offering.

F-6

RHINO RESOURCES, INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEAR ENDED DECEMBER 31, 2007 AND AS OF AND

FOR THE SIX MONTHS ENDED JUNE 30, 2008

2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS (Continued)

(b): Reflects the payment of the estimated underwriting discount and offering expenses of $ million.
(c): Reflects repayment of approximately $ million of the outstanding indebtedness under the credit facility. At June 30, 2008, there was $80.0 million of indebtedness under the credit facility, which is a senior secured credit facility incurred for working capital needs and the acquisitions of coal properties, mining equipment and other capital needs.
(d): Reflects a $700,000 one-time cash bonus payment to executive officers payable within 30 days of completion of the initial public offering.
(e): Reflects the elimination of members' interest converted into common stock. The calculation of additional paid-in capital, assuming an initial public offering price of $ per share and the sale of shares of common stock, is as follows:

		As of June 30, 2008
Capital contribution		$
Par value
Historical members' investment
Stock compensation expense adjustment(1)

Pro forma additional paid-in capital		$

(1): Reflects the net of tax expense for shares of unrestricted common stock issued to management. The estimated effective tax rate at June 30, 2008 was %.

The calculation of retained earnings is as follows:

		As of June 30, 2008
Retained earnings		$
Deferred liabilities
Underwriters' discount and other expenses
Accrued expenses
Stock compensation expense(1)

Pro forma retained earnings		$

(1): Reflects the net of tax expense for shares of unrestricted common stock issued to management. The estimated effective tax rate at June 30, 2008 was %.

F-7

RHINO RESOURCES, INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEAR ENDED DECEMBER 31, 2007 AND AS OF AND

FOR THE SIX MONTHS ENDED JUNE 30, 2008

2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS (Continued)

(f): Reflects net change in interest expense as a result of the repayment of borrowing under the credit facility of $ million. The individual components of the net change in interest expense are as follows:

	Year Ended December 31, 2007		Six Months Ended June 30, 2008
Pro forma commitment interest on the unused portion of the credit facility(1)	$		$
Pro forma interest on revolving credit facility(2)
Less: Historical interest expense for the credit facility and for commitment fee on the unused portion of the credit facility		4,064,593		1,857,679

Pro forma interest expense adjustment	$		$

(1): For the year ended December 31, 2007, reflects pro forma commitment fee at % on estimated unused portion of the credit facility in the amount of $ million as of January 1, 2007. For the six months ended June 30, 2008, reflects pro forma commitment fee at % on estimated unused portion of the credit facility in the amount of $ million as of January 1, 2008 then increased to $ million as of March 1, 2008, respectively. The credit facility was increased from $125.0 million to $200.0 million in February 2008.
(2): For the year ended December 31, 2007, reflects pro forma interest rate of % on the estimated outstanding balance on the revolving credit facility in the amount of $ million as of January 1, 2007. An increase or decrease in pro forma interest rate of 1.0% would have increased or decreased, respectively, pro forma net interest expense by approximately $ million. For the six months ended June 30, 2008, reflects pro forma interest rate of % on estimated outstanding balance on the revolving credit in the amount of $ million as of January 1, 2008. An increase or decrease in pro forma interest rate of 1.0% would have increased or decreased, respectively, pro forma net interest expense by approximately approximately $ million.

(g): Reflects the pro forma unaudited income tax adjustments that represent the tax effects that would have been reported had the Company been subject to U.S. federal, state and local income taxes as a corporation. Pro forma income tax expense is based upon the statutory income tax rate of 38.6% applied to pro forma net income as adjusted for estimated permanent differences occurring during the period. Pro forma income tax expense does not consider potential alternative minimum tax. Pro forma tax expense could have differed had the Company been subject to the United States federal, state and local income taxes for all periods presented.
(h): Reflects the compensation costs for shares of common stock awarded to management. In connection with the closing of the offering, the Company will issue shares of

F-8

RHINO RESOURCES, INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

FOR THE YEAR ENDED DECEMBER 31, 2007 AND AS OF AND

FOR THE SIX MONTHS ENDED JUNE 30, 2008

2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS (Continued)

unrestricted and shares of restricted stock to management under the Company's long-term incentive plan. The restricted stock will vest over a three-year period from the date of closing.

We value stock grants using the Black-Scholes valuation model, which employs certain key assumptions:

Expected life (years)		3.0
Expected volatility		45%
Risk-free interest rate		3.0%
Expected annual dividend		0.35%

We estimate volatility using peer group volatility data. The dividend yield is calculated on the annualized dividend payment of $ per share and the estimated stock price at the date of offering. The expected term is based on the long-term incentive plan. The risk-free interest rate is estimated based on the yield on the Treasury rate. We have assumed a 0% forfeiture rate, since the shares are granted to limited senior management members, and the shares will vest over a three-year period with forfeitable dividend rights.

3. PRO FORMA EARNINGS PER SHARE

Pro forma basic earnings per share is determined by dividing the pro forma net income by the weighted average number of shares of common stock outstanding. Diluted earnings per share is computed by dividing pro forma net income by the weighted average number of shares of common stock outstanding plus the number of restricted shares of common stock that would have been vested during the periods. The number of shares of common stock outstanding and restricted shares of common stock are assumed to have been and at January 1, 2007. The restricted shares of common stock will vest over a three year period and will include forfeitable dividends rights. The treasury stock method is applied in calculating the diluted earnings per share. The earnings per share calculations assume that the underwriters will not exercise their option to purchase additional shares.

F-9

RHINO ENERGY LLC

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

AS OF JUNE 30, 2008

		June 30, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	1,153,088
Accounts receivable, net of allowance for doubtful accounts ($0 as of June 30, 2008)			33,563,345
Inventories			9,972,833
Advance royalties, current portion			1,198,717
Prepaid expenses and other			8,093,695

	Total current assets		53,981,678
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and contract costs			334,175,898
Less accumulated depreciation, depletion and amortization			(83,968,511	)

Net property, plant and equipment			250,207,387
ADVANCE ROYALTIES, net of current portion			2,867,463
INVESTMENT IN UNCONSOLIDATED AFFILIATE			16,056,742
OTHER NON-CURRENT ASSETS			2,530,390

TOTAL		$	325,643,660

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable		$	21,901,923
Accrued expenses and other			19,060,910
Current portion of long-term debt			6,904,865
Current portion of asset retirement obligations			974,503
Current portion of postretirement benefits			91,785

	Total current liabilities		48,933,986
NON-CURRENT LIABILITIES:
Long-term debt			83,423,701
Asset retirement obligations			51,846,466
Other non-current liabilities			916,655
Postretirement benefits			4,942,749

	Total non-current liabilities		141,129,571

	Total liabilities		190,063,557

COMMITMENTS AND CONTINGENCIES (NOTE 8)
MEMBERS' EQUITY:
Members' investment			23,158,642
Accumulated other comprehensive income (loss)			588,376
Retained earnings			111,833,085

	Total members' equity		135,580,103

TOTAL		$	325,643,660

See notes to unaudited condensed consolidated financial statements.

F-10

RHINO ENERGY LLC

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

		Six Months Ended June 30,
		2007			2008
REVENUES
Coal sales		$	190,296,985			211,219,336
Freight and handling revenues			950,803			4,072,658
Other revenues			2,253,251			7,727,147

	Total revenues		193,501,039			223,019,141
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			152,408,166			172,489,899
Freight and handling costs			956,603			4,132,216
Depreciation, depletion and amortization			14,326,390			17,247,375
Selling, general and administrative			7,146,598			8,814,617
(Gain) loss on retirement of advance royalties			(125,277	)		7,998
(Gain) loss on sale of assets			(797,553	)		(376,192	)

	Total costs and expenses		173,914,927			202,315,913
INCOME FROM OPERATIONS			19,586,112			20,703,228
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense			(3,121,608	)		(2,557,172	)
Interest income			185,320			100,542

	Total interest and other income (expense)		(2,936,288	)		(2,456,630	)
INCOME BEFORE INCOME TAXES			16,649,824			18,246,598
INCOME TAX (BENEFIT)			(119,472	)		—
EQUITY IN NET INCOME (LOSS) OF UNCONSOLIDATED AFFILIATE			—			(38,480	)

NET INCOME		$	16,769,296			18,208,118

Other comprehensive income			—			—

NET COMPREHENSIVE INCOME		$	16,769,296			18,208,118
PRO FORMA NET INCOME AND EARNINGS PER SHARE:
Income before income taxes		$			$
Pro forma income tax expense

Pro forma net income		$			$

Pro forma earnings per share, basic and diluted		$			$
Pro forma weighted average shares outstanding, basic and diluted

See notes to unaudited condensed consolidated financial statements.

F-11

RHINO ENERGY LLC

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

		Six Months Ended June 30,
		2007			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	16,769,296		$	18,208,118
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			14,326,390			17,247,375
Accretion on asset retirement obligations			877,007			1,217,980
Accretion on interest-free debt			176,993			282,779
Amortization of advance royalties			441,270			115,653
Equity in net loss of unconsolidated affiliate			—			38,480
(Gain) loss on retirement of advance royalties			(125,277	)		7,998
(Gain) loss on sale of assets			(797,553	)		(376,192	)
Changes in assets and liabilities:
Accounts receivable			3,389,643			7,854,485
Inventories			(5,806,743	)		(2,385,248	)
Advance royalties			(1,133,254	)		(591,431	)
Prepaid expenses and other assets			(2,266,179	)		(4,343,254	)
Accounts payable			2,634,672			7,436,397
Accrued expenses and other liabilities			2,530,091			1,960,867
Asset retirement obligations			(4,565,664	)		(1,608,142	)
Postretirement benefits			462,706			286,244

	Net cash provided by operating activities		26,913,398			45,352,109

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment			(5,637,972	)		(26,989,817	)
Proceeds from sales of property, plant, and equipment			1,360,437			2,733,100
Principal payments received on note receivable			824,612			1,867,112
Changes in restricted cash			510,974			—
Acquisitions of coal companies and coal properties			—			(14,669,673	)
Investment in unconsolidated affiliate			—			(16,095,222	)

	Net cash used in investing activities		(2,941,949	)		(53,154,500	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit			65,092,000			78,350,000
Repayments on line of credit			(85,742,000	)		(67,350,000	)
Repayments on long-term debt			(2,280,782	)		(5,159,364	)
Proceeds from issuance of long-term debt			1,610,524			—
Distributions to members			—			(468,552	)

	Net cash (used in) provided by financing activities		(21,320,258	)		5,372,084

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS			2,651,191			(2,430,307	)
CASH AND CASH EQUIVALENTS—Beginning of period			379,956			3,583,395

CASH AND CASH EQUIVALENTS—End of period			3,031,147			1,153,088

See notes to unaudited condensed consolidated financial statements.

F-12

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

1. BASIS OF PRESENTATION

Unaudited Interim Financial Information—The accompanying unaudited interim financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. The condensed consolidated statement of financial position as of June 30, 2008, condensed consolidated statements of operations for the six months ended June 30, 2007 and 2008 and the condensed consolidated statements of cash flows for the six months ended June 30, 2007 and 2008 are unaudited, but include all adjustments (consisting of normal recurring adjustments) which the Company considers necessary for a fair presentation of the financial position, operating results and cash flows for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the year or any future period. These unaudited interim financial statements should be read in conjunction with the audited financial statements included in this registration statement.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Note Receivable—Included in prepaid expenses and other assets and other non-current assets is a note receivable of $1,739,728 resulting from a sale of equipment to KAPO Mining, LLC. This note receivable bears interest at a fixed rate of 7%. In February 2008, the note was revised and the Company is due quarterly principal payments of $214,200 and monthly interest payments on the outstanding balance through November 2009. The Company is due a final payment of $449,669, plus accrued interest, in December 2009.

Restricted Cash—Included in prepaid expenses and other current assets is restricted cash, representing cash serving as collateral for reclamation obligations and margins on coal futures contracts.

Derivative Financial Instruments—During the six months ended June 30, 2008, the Company used futures contracts to manage the risk of fluctuations in the sales price of coal. The Company did not use derivative financial instruments for trading or speculative purposes. The Company recorded the derivative financial instruments as either assets or liabilities, at fair value, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities and SFAS No. 149, Amendment on Statement 133 on Derivative Instruments and Hedging Activities. Changes in fair value are recorded as adjustments to the assets and liabilities being hedged in current earnings, as the derivative financial instruments did not qualify for hedge accounting.

Sales Contract Liability—In connection with certain acquisitions in 2004, the Company acquired certain contracts with sales prices that are below its production cost. The Company recognized a liability for these contracts equal to the present value of the difference between the Company's cost and the contract amount in accordance with SFAS No. 141, Business Combinations. The Company amortized this liability as sales were made under these sales contracts. Such amortization is included within depreciation, depletion and amortization.

F-13

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

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

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 Company's ability to exercise significant influence over the operating and financial policies of the investee and whether the Company is determined to be the primary beneficiary. Equity investments are recorded at original cost and adjusted periodically to recognize the Company'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 Company resumes accounting for the investment under the equity method when the entity subsequently reports net income and the Company'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.

Recent Accounting Pronouncements—In September 2006, the FASB issued SFAS No. 157, Fair Value Measures ("SFAS No. 157"), which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosure on fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. Adoption of SFAS No. 157 did not have a material impact on the Company's financial position, results of operations or cash flows; however, adoption did result in additional information being included in the footnotes accompanying the condensed consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115 ("SFAS No. 159"). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. The fair value option may be applied on an instrument by instrument basis with certain exceptions. The election is irrevocable and must be applied to entire instruments and not to portions of instruments. For the Company, the election to apply the standard and measure certain financial instruments at fair value was effective prospectively beginning January 1, 2008. The adoption of SFAS No. 159 did not have a material impact on the Company's financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (Revised), Business Combinations ("SFAS No. 141R") and SFAS No. 160, Noncontrolling Interests in Combined Financial Statements ("SFAS No. 160"). SFAS No. 141R and SFAS No. 160 revise the method of accounting for a number of aspects of business combinations, including acquisition costs, contingencies (including contingent assets, contingent liabilities and contingent purchase price), the impacts of partial and step-acquisitions (including the valuation of net assets attributable to non-acquired minority interests), and post acquisition exit activities of acquired businesses. SFAS No. 141R and SFAS No. 160 will be effective for the Company on January 1, 2009.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133 ("SFAS No. 161"). SFAS No. 161 requires enhanced disclosures about an entity's derivative and hedging activities and thereby improves the transparency of financial reporting. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the effect that adoption of SFAS No. 161 will have on its consolidated financial statements.

F-14

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

3. ASSET RETIREMENT OBLIGATIONS

The changes in the Company's asset retirement obligations for the six months ended June 30, 2007 and 2008 were as follows:

	Six Months Ended June 30,
	2007			2008
Balance at beginning of period (including current portion)	$	30,168,469		$	36,387,399
Accretion expense		877,007			1,217,980
Additions resulting from property additions		2,599,900			16,823,731
Adjustments to the liability from annual recosting and other		(4,565,664	)		(1,608,141	)
Liabilities settled		—			—

Balance at end of period		29,079,712			52,820,969
Current portion of asset retirement obligation		4,766,327			(974,503	)

Long-term portion of asset retirement obligation	$	24,313,385		$	51,846,466

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of June 30, 2008 consisted of the following:

	June 30, 2008
Note receivable	$	856,800
Restricted cash		663,960
Deferred offering costs		1,478,759
Other prepaid expenses		754,315
Prepaid insurance		3,439,365
Prepaid leases		326,676
Supply inventory		157,749
Deposits		46,290
Rebates receivable		369,781

Total	$	8,093,695

F-15

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of June 30, 2008 are summarized by major classification as follows:

	Useful Lives	June 30, 2008
Land and land improvements		$	19,192,445
Mining and other equipment and related facilities	2-20 Years		163,254,085
Mine development costs	1-15 Years		38,778,479
Coal properties	1-15 Years		86,569,043
Construction work in process			26,381,846

Total			334,175,898
Less accumulated depreciation, depletion and amortization			(83,968,511	)

Net		$	250,207,387

Depreciation expense for mining and other equipment and related facilities for the six months ended June 30, 2007 and 2008 was $9,636,358 and $12,361,236, respectively. Depletion expense for coal properties for the six months ended June 30, 2007 and 2008 was $1,755,820 and $1,901,566, respectively. Amortization expense for mine development costs for the six months ended June 30, 2007 and 2008 was $2,085,702 and $2,367,746, respectively.

6. OTHER NON-CURRENT ASSETS

Other non-current assets as of June 30, 2008 consisted of the following:

	June 30, 2008
Note receivable	$	571,983
Debt issuance costs—net		1,236,813
Deferred expenses		101,052
Deposits and other		620,542

Total	$	2,530,390

Debt issuance costs were $2,543,566 as of June 30, 2008. Accumulated amortization of debt issuance costs were $1,306,753 as of June 30, 2008.

F-16

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

7. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of June 30, 2008 consisted of the following:

	June 30, 2008
Payroll, bonus and vacation expense	$	4,384,323
Non income taxes		3,307,577
Royalty expenses		2,602,708
Accrued interest		344,736
Health claims		2,649,193
Workers' compensation and pneumoconiosis		1,581,650
Other		4,190,723

Total	$	19,060,910

8. DEBT

Debt as of June 30, 2008 consisted of the following:

	June 30, 2008
Revolving line of credit with PNC Bank, N.A.	$	80,000,000
Note payable to H&L Construction Co., Inc.		6,990,590
Capital lease obligation with Applied Financial		599,059
Other notes payable		2,738,917

Total		90,328,566
Less current portion of long-term debt		(6,904,865	)

Long term debt	$	83,423,701

Revolving line of credit with PNC Bank, N.A.—Borrowings under the line of credit bear interest which varies depending upon the grouping of the borrowings within the line of credit. At June 30, 2008 the Company had borrowed $80,000,000 at a variable interest rate of LIBOR plus 1.25% (3.64% at June 30, 2008). In addition, the Company had outstanding letters of credit of $22,780,530 at a fixed interest rate of 1.25% at June 30, 2007. The maximum amount available on the line of credit with PNC is $200,000,000. The credit agreement is to expire in February 2013. At June 30, 2008, the Company had not used $97,219,470 of the borrowing availability. As part of the agreement, the Company is required to pay a commitment fee of 0.25% on the unused portion of the borrowing availability. Borrowings on the line of credit are collateralized by all the unsecured assets of the Company.

In May 2008, the Company amended the credit agreement with PNC to exclude CAM-Colorado from certain restrictions generally applicable to subsidiaries under the credit facility. The maximum availability under the credit facility remains at $200,000,000. The expiration of the credit agreement remains February 2013.

The revolving credit commitment requires the Company to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans,

F-17

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

8. DEBT (Continued)

investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Company was in compliance with all restrictive provisions as of June 30, 2008.

Note payable to H&L Construction Co., Inc.—The note payable to H&L Construction Co., Inc. is a non-interest bearing note. The Company has recorded a discount for imputed interest at a rate of 6.5% on this note. The Company is amortizing this discount over the life of the note using the effective interest method. The note payable matures in April 2009 and is secured by mineral rights purchased by the Company from H&L Construction Co., Inc.

Capital Lease Obligation with Applied Financial—Borrowings under the capital lease with Applied Financial are to be paid back in 48 equal installments of $30,104, with final payment due in March 2010.

9. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of June 30, 2008, the Company had commitments under sales contracts to deliver annually scheduled base quantities of 8.4 million, 6.4 million, 3.3 million, 1.4 million and 1.4 million tons of coal to 35 customers in 2008, 18 customers in 2009, 8 customers in 2010, 2 customers in 2011 and 2 customers in 2012, respectively. Certain 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 June 30, 2008, the Company had 4.7 million gallons remaining on a commitment to purchase diesel fuel at fixed prices ranging from $2.00 to $4.10 per gallon through October 2009.

Leases—The Company leases various mining, transportation and other equipment under operating leases. Lease expense for the six months ended June 30, 2007 and 2008 was approximately $5,983,191 and $4,269,441, respectively.

The Company also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Total royalty expense for the six months ended June 30, 2007 and 2008 was approximately $10,645,019 and $11,400,116, respectively.

10. FAIR VALUE MEASUREMENTS

Effective January 1, 2008, the Company adopted SFAS No. 157, Fair Value Measures ("SFAS No. 157"), which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. SFAS No. 157 applies whenever other statements require or permit assets or liabilities to be measured at fair value. SFAS No. 157 requirements for certain non-financial assets and liabilities were permitted to be deferred until the first quarter of 2009 in accordance with FSP 157-2, Effective Date of FASB Statement No. 157. At the time of the partial adoption of SFAS No. 157, there were no nonfinancial assets or nonfinancial liabilities that

F-18

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

10. FAIR VALUE MEASUREMENTS (Continued)

were measured at fair value on a nonrecurring basis. SFAS No. 157 establishes the following fair value hierarchy that prioritizes the inputs used to measure fair value:

•: Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.
•: Level 2—Inputs other than Level 1 that are based on observable market data, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets, quoted prices for identical assets or liabilities in inactive markets, inputs that are observable that are not prices and inputs that are derived from or corroborated by observable markets.
•: Level 3—Developed from unobservable data, reflecting an entity's own assumptions.

In February 2008, the Company entered into futures contracts to sell 240,000 tons of coal at a weighted averaged price of $83.25 per ton. During the three months ended June 30, 2008, the Company settled all remaining futures contracts. These contracts were Level 2 liabilities under SFAS No. 157, and the impact of the settlement of these contracts was immaterial to the Company.

11. MAJOR CUSTOMERS

The Company had receivables or revenues from the following major customers that in the six months ended June 30, 2007 and 2008 equaled or exceeded 10% of total revenues:

	June 30, 2007 Receivable Balance		Six Months Ended June 30, 2007 Sales		June 30, 2008 Receivable Balance		Six Months Ended June 30, 2008 Sales
Customer A	$	4,409,615	$	26,398,594	$	6,859,512	$	46,951,611
Customer B	$	6,030,927	$	52,087,639	$	2,701,202	$	28,691,690
Customer C	$	4,970,953	$	31,321,246		n/a		n/a
Customer D	$	2,986,885	$	28,730,403		n/a		n/a
Customer E	$	622,878	$	22,220,637		n/a		n/a

12. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

The statement of cash flows for the six months ended June 30, 2007 is exclusive of (1) $5,403,720 of property additions financed through long-term debt borrowings and other assumed liabilities; and (2) $2,599,900 of non-cash additions to asset retirement obligations and mineral rights.

The statement of cash flows for the six months ended June 30, 2008 is exclusive of (1) $251,435 of property additions financed through long-term debt borrowings and other assumed liabilities; and (2) $16,823,731 of non-cash additions to asset retirement obligations and mineral rights.

F-19

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

13. SELECTED QUARTERLY FINANCIAL DATA

A summary of our quarterly operating results during the six months ended June 30, 2007 and 2008 is as follows:

	Quarter Ended
	March 31, 2007		June 30, 2007		March 31, 2008		June 30, 2008
Total revenues	$	101,551,710	$	91,949,329	$	111,002,892	$	112,016,249
Income from operations	$	11,141,725	$	8,444,387	$	12,738,632	$	7,964,596
Net income	$	9,495,000	$	7,274,296	$	11,263,224	$	6,944,894

14. SEGMENT INFORMATION

The Company changed the presentation of its reporting business segments and retrospectively restated its segment disclosures in its financial statements for year ended December 31, 2007 to report Sands Hill as a separate reporting business segment as its assets exceeded 10% of the combined assets of all operating segments as of December 31, 2007 and June 30, 2008. The Sands Hill operating segment, which was acquired in December 2007, was previously reported under the Other reporting business segment.

Effective April 1, 2008, The Company's interest in Rhino Eastern LLC, the joint venture that acquired the Eagle mining complex and the Bolt field, was also added as a separate reporting business segment. The Company acquired a 51% interest in the joint venture in May 2008 and the results of operations for the joint venture were immaterial for the six months ended June 30, 2008. The mining complex has two underground mines that are in the process of redevelopment but as of June 30, 2008 were inactive. The mining complex commenced operations in August 2008.

Reportable segment financial conditions and results of operations as of and for the six months ended June 30, 2007 are as follows:

	Central Appalachia		Northern Appalachia		Sands Hill		Other			Total Segments
Total assets	$	141,358,366	$	27,728,428	$	—	$	84,328,434		$	253,415,228
Total revenues	$	162,487,027	$	25,957,636	$	—	$	5,056,376		$	193,501,039
Depreciation, depletion and amortization	$	11,586,360	$	1,991,249	$	—	$	748,781		$	14,326,390
Interest expense	$	2,385,682	$	410,737	$	—	$	325,189		$	3,121,608
Net income (loss)	$	12,891,462	$	4,375,567	$	—	$	(497,733	)	$	16,769,296

The Other segment includes revenue, depreciation, depletion and amortization, interest and net income from the Company's Colorado operation and other ancillary businesses. Total assets in the Other segment consists of intercompany receivables and payables between the Company and its subsidiaries, and assets related to the Company's Colorado operation and other ancillary businesses.

F-20

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

14. SEGMENT INFORMATION (Continued)

Reportable segment financial condition and results of operations as of and for the six months ended June 30, 2008 are as follows:

	Central Appalachia		Rhino Eastern			Northern Appalachia		Sands Hill			Other		Total Segments
Total assets	$	152,691,810	$	16,056,742		$	27,283,570	$	33,080,720		$	96,530,818	$	325,643,660
Total revenues	$	166,943,541	$	—		$	33,334,247	$	16,819,277		$	5,922,076	$	223,019,141
Depreciation, depletion and amortization	$	12,125,422	$	—		$	2,364,244	$	1,305,354		$	1,452,355	$	17,247,375
Interest expense	$	1,646,422	$	—		$	373,027	$	233,342		$	304,381	$	2,557,172
Net income (loss)	$	12,828,793	$	(38,480	)	$	7,333,015	$	(2,007,973	)	$	92,763	$	18,208,118

The Other segment includes revenues, depreciation, depletion and amortization, interest and net income from the Company's operations in Colorado and Illinois, and other ancillary businesses. Total assets in the Other segment consists of intercompany receivables and payables between the Company and its subsidiaries, and assets related to the Company's operations in Colorado and other ancillary businesses.

15. ACQUISITIONS

In February 2008, the Company acquired the coal operations of the Deane mining complex, located in Kentucky, to expand its operations in Central Appalachia. This acquisition included several underground mines, surface property, a preparation plant and a unit train load-out. The Company allocated the purchase price to assets and liabilities acquired based upon an initial determination, which is subject to adjustment of their respective fair values in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations ("SFAS No. 141"). The recorded value of the assets and (liabilities) were:

Property, plant and equipment		$	31,498,418
Property taxes			(5,014	)
Asset retirement obligations			(16,823,731	)

	Net assets acquired	$	14,669,673

Total consideration		$	14,669,673

In accordance with SFAS No. 141, results of operations of the Deane mining complex from February 15, 2008 through June 30, 2008 are included in the Company's interim financial statements for the six months ended June 30, 2008. However, pro forma results of operations that give effect to the acquisition as if it had occurred at the beginning of the period are not provided, as the acquisition would not have had a significant impact on the Company's results of operations for the six months ended June 30, 2008.

In May 2008, the Company entered into a joint venture that acquired the Eagle mining complex. This acquisition included an underground mine located in West Virginia, which has approximately

F-21

RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008

15. ACQUISITIONS (Continued)

5.8 million tons of coal reserves. The Company paid 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.

16. UNAUDITED PRO FORMA EARNINGS PER SHARE

Unaudited pro forma earnings per share reflect the provision for income taxes under Rhino Resources, Inc.'s new corporate holding company structure, divided by the common stock to be issued to Rhino Energy Holdings LLC and certain Wexford Funds in exchange for the contribution of their ownership interests in the Company to Rhino Resources, Inc., each of which will occur upon Rhino Resources, Inc.'s initial public offering.

F-22

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Rhino Energy LLC
Lexington, Kentucky

We have audited the accompanying consolidated statements of financial position of Rhino Energy LLC (the "Company") as of December 31, 2006 and 2007, and the related consolidated statements of operations, members' equity, and cash flows for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company 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 Company'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 Company as of December 31, 2006 and 2007, and the results of its operations and its cash flows for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

Effective April 1, 2006, the Company changed its fiscal year end from March 31 to December 31.

As discussed in Note 2 to the consolidated financial statements, the Company adopted the provisions of SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)," effective December 31, 2006.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio
April 10, 2008 (September 10, 2008 as to Note 14)

F-23

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

AS OF DECEMBER 31, 2006 AND 2007

		December 31,
		2006			2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	379,956		$	3,583,395
Accounts receivable, net of allowance for doubtful accounts ($175,242 and $0 as of December 31, 2006 and 2007, respectively)			30,602,922			41,417,830
Inventories			10,520,778			7,587,585
Advance royalties, current portion			618,115			1,205,683
Prepaid expenses and other			2,796,842			5,686,064

	Total current assets		44,918,613			59,480,557
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and contract costs			245,980,208			289,562,564
Less accumulated depreciation, depletion and amortization			(48,924,075	)		(77,905,483	)

Net property, plant and equipment			197,056,133			211,657,081
ADVANCE ROYALTIES, net of current portion			1,706,759			2,392,718
OTHER NON-CURRENT ASSETS			4,512,947			2,461,878

TOTAL		$	248,194,452		$	275,992,234

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable		$	12,994,426		$	14,465,527
Accrued expenses and other			12,819,689			16,850,040
Current portion of long-term debt			10,009,868			10,161,633
Current portion of asset retirement obligations			2,928,607			2,582,646
Current portion of postretirement benefits			97,004			91,785
Current portion of deferred revenue			1,142,924			580,066

	Total current liabilities		39,992,518			44,731,697
NON-CURRENT LIABILITIES:
Long-term debt			78,560,612			73,792,083
Asset retirement obligations			27,239,862			33,804,753
Other non-current liabilities			2,208,249			1,166,656
Postretirement benefits			5,305,853			4,656,507

	Total non-current liabilities		113,314,576			113,419,999

	Total liabilities		153,307,094			158,151,695

COMMITMENTS AND CONTINGENCIES (NOTE 9)
MEMBERS' EQUITY:
Members' investment			32,877,194			23,627,194
Accumulated other comprehensive income (loss)			(901,040	)		588,376
Retained earnings			62,911,204			93,624,968

	Total members' equity		94,887,358			117,840,538

TOTAL		$	248,194,452		$	275,992,234

See notes to consolidated financial statements.

F-24

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED MARCH 31, 2006,

THE NINE MONTHS ENDED DECEMBER 31, 2006 AND

THE YEAR ENDED DECEMBER 31, 2007

		Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
REVENUES
Coal sales		$	351,379,918		$	294,236,719		$	394,078,915
Freight and handling revenues			6,149,211			2,783,314			4,052,430
Other revenues			6,430,783			3,818,504			5,320,452

	Total revenues		363,959,912			300,838,537			403,451,797
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			291,444,675			238,189,687			318,520,554
Freight and handling costs			6,342,513			2,768,079			4,020,747
Depreciation, depletion and amortization			13,744,251			28,471,208			30,749,773
Selling, general and administrative			17,129,442			18,573,026			15,370,333
(Gain) loss on retirement of advance royalties			(236,884	)		2,994,555			(115,277	)
(Gain) loss on sale of assets			(377,219	)		745,818			(944,303	)

	Total costs and expenses		328,046,778			291,742,373			367,601,827
INCOME FROM OPERATIONS			35,913,134			9,096,164			35,849,970
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense			(4,976,175	)		(6,497,958	)		(5,579,224	)
Interest income			412,116			311,660			316,710
Other—net			490,655			272,206			—

	Total interest and other income (expense)		(4,073,404	)		(5,914,092	)		(5,262,514	)
INCOME BEFORE INCOME TAXES			31,839,730			3,182,072			30,587,456
INCOME TAX (BENEFIT) EXPENSE			178,410			124,577			(126,308	)

NET INCOME		$	31,661,320		$	3,057,495		$	30,713,764
Other comprehensive income (loss):
Change in actuarial gain/(loss) under SFAS No. 158			—			(901,040	)		1,489,416

NET COMPREHENSIVE INCOME		$	31,661,320		$	2,156,455		$	32,203,180

PRO FORMA NET INCOME AND EARNINGS PER SHARE:
Income before income taxes		$	31,839,730		$	3,182,072		$	30,587,456
Pro forma income tax expense (benefit)

Pro forma net income		$			$			$

Pro forma earnings per share, basic and diluted		$			$			$
Pro forma weighted average shares outstanding, basic and diluted

See notes to consolidated financial statements.

F-25

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY

FOR THE YEAR ENDED MARCH 31, 2006,

THE NINE MONTHS ENDED DECEMBER 31, 2006 AND

THE YEAR ENDED DECEMBER 31, 2007

	Members' Investment			Accumulated Other Comprehensive Income (Loss)			Retained Earnings		Total
BALANCE—April 1, 2005	$	32,877,194		$	—		$	28,192,389	$	61,069,583
Net income		—			—			31,661,320		31,661,320

BALANCE—March 31, 2006		32,877,194			—			59,853,709		92,730,903
Net income		—			—			3,057,495		3,057,495
Adoption of SFAS No. 158		—			(901,040	)		—		(901,040	)

BALANCE—December 31, 2006		32,877,194			(901,040	)		62,911,204		94,887,358
Distributions to members		(9,250,000	)		—			—		(9,250,000	)
Change in actuarial gain (loss) under SFAS No. 158		—			1,489,416			—		1,489,416
Net income		—			—			30,713,764		30,713,764

BALANCE—December 31, 2007	$	23,627,194		$	588,376		$	93,624,968	$	117,840,538

See notes to consolidated financial statements.

F-26

RHINO ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEAR ENDED MARCH 31, 2006,

THE NINE MONTHS ENDED DECEMBER 31, 2006 AND

THE YEAR ENDED DECEMBER 31, 2007

			Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income			$	31,661,320		$	3,057,495		$	30,713,764
Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation, depletion and amortization			13,744,251			28,471,208			30,749,773
	Accretion on asset retirement obligations			1,685,560			1,412,366			1,756,965
	Accretion on interest-free debt			321,197			255,113			359,817
	Amortization of advance royalties			2,186,767			1,098,453			699,705
	Provision for doubtful accounts			354,449			(282,789	)		(175,242	)
	(Gain) loss on retirement of advance royalties			(236,884	)		2,994,555			(115,277	)
	(Gain) loss on sale of assets			(377,219	)		745,818			(944,303	)
Changes in assets and liabilities:
	Accounts receivable			(15,638,237	)		8,449,841			(10,639,666	)
	Inventories			(2,330,153	)		1,542,261			2,933,193
	Advance royalties			(2,429,220	)		(3,565,157	)		(1,857,955	)
	Prepaid expenses and other assets			(478,784	)		498,588			(1,031,645	)
	Accounts payable			6,801,579			(4,833,180	)		1,471,100
	Accrued expenses and other liabilities			226,883			(3,928,700	)		3,117,347
	Asset retirement obligations			(3,247,648	)		391,351			(5,379,905	)
	Postretirement benefits			648,139			552,256			834,851

		Net cash provided by operating activities		32,892,000			36,859,479			52,492,522

CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant, and equipment			(31,485,479	)		(32,701,306	)		(14,598,735	)
	Proceeds from sales of property, plant, and equipment			669,714			364,425			4,482,154
	Principal payments received on note receivable			115,164			2,012,482			293,498
	Changes in restricted cash			1,088,044			1,496,827			(100,006	)
	Acquisitions of coal companies and coal properties			(5,000,000	)		—			(18,174,465	)

		Net cash used in investing activities		(34,612,557	)		(28,827,572	)		(28,097,554	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Borrowings on line of credit			74,244,218			145,648,104			159,042,000
	Repayments on line of credit			(61,058,062	)		(93,964,924	)		(165,042,000	)
	Proceeds from issuance of long-term debt			1,874,418			2,613,643			1,767,342
	Repayments on long-term debt			(16,181,438	)		(63,437,614	)		(7,708,871	)
	Proceeds from loan payable to related party			88,948			—			—
	Repayments on loan payable to related party			(855,009	)		—			—
	Distributions to members			—			—			(9,250,000	)

		Net cash used in financing activities		(1,886,925	)		(9,140,791	)		(21,191,529	)

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS				(3,607,482	)		(1,108,884	)		3,203,439
CASH AND CASH EQUIVALENTS—Beginning of period				5,096,322			1,488,840			379,956

CASH AND CASH EQUIVALENTS—End of period			$	1,488,840		$	379,956		$	3,583,395

See notes to consolidated financial statements.

F-27

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization—Rhino Energy LLC and its wholly owned subsidiaries (the "Company") produce and market coal from surface and underground mines in Illinois, Kentucky, Ohio, Pennsylvania, West Virginia, and Colorado, with the majority of the Company's sales going to domestic utilities and other coal-related organizations in the United States. The Company was formed in April 2003 and has been built via acquisitions. The Company's direct and indirect wholly owned subsidiaries are as follows: CAM Mining LLC; CAM Kentucky Real Estate LLC; Rhino Northern Holdings LLC; Hopedale Mining LLC; CAM Ohio Real Estate LLC; Springdale Land, LLC; Sands Hill Mining LLC; Clinton Stone LLC; Deane Mining LLC; Reserve Holdings LLC; CAM Coal Trading LLC; Leesville Land, LLC; Taylorville Mining LLC; McClane Canyon Mining LLC; CAM-Colorado LLC; CAM BB LLC; CAM Aircraft LLC; Rhino Coalfield Services LLC; Rhino Trucking LLC; Rhino Services LLC; and Rhino Reclamation Services LLC.

In December 2007, the Company acquired the coal operations of Sands Hill Coal Company, located in Ohio. This acquisition included several surface mines, a stone crusher/screening facility, a coal preparation plant and rights to coal reserves. The Company allocated the purchase price to assets and liabilities acquired based upon an initial determination, which is subject to adjustment, of their respective fair values in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations ("SFAS No. 141"). As the purchase price of the acquisition was less than the fair value of the net assets acquired, the Company proportionately reduced the related value of its property, plant and equipment at discounted fair value. The recorded value of the assets and (liabilities) were:

Property, plant and equipment	$	28,082,303
Receivables		50,186
Inventory		1,610,817
Accrued expenses		(229,707	)
Accounts payable		(2,393,552	)
Asset retirement obligations		(8,945,582	)

Net assets acquired (cash consideration paid)	$	18,174,465

Pro forma results of operations that give effect to the Sands Hill acquisition as if it had occurred at the beginning of the period have not been provided, as the Sands Hill acquisition would not have had a significant impact on the Company's results of operations for the year ended December 31, 2007.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Company Environment and Risk Factors—The Company, in the course of its business activities, is exposed to a number of risks including: fluctuating market conditions of coal, truck and rail

F-28

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

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

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 Company 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 10 for discussion of major customers. The Company does not require collateral or other security on accounts receivable. The credit risk is controlled through credit approvals and monitoring procedures.

Cash and Cash Equivalents—The Company considers all highly liquid investments purchased with 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 Company 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 Company 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 Company has ceased mining or has made a decision not to mine on such property.

Restricted Cash—Included in prepaid expenses and other current assets is restricted cash, representing cash serving as collateral for notes payable and reclamation obligations.

Note Receivable—Included in prepaid expenses and other assets and other non-current assets is a note receivable resulting from a sale of equipment to KAPO Mining, LLC. This note receivable bears interest at a fixed rate of 7%. The Company is due quarterly principal payments of $214,200 and monthly interest payments on the outstanding balance through March 2008. The Company is due a final payment of $1,748,803, plus accrued interest, in April 2008.

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 recoverable reserves. Mine development costs are amortized using the units-of-production method, based on estimated recoverable reserves. Gains or losses arising from sales or retirements are included in current operations.

On March 30, 2005, the FASB ratified the consensus reached by the EITF on Issue 04-06, Accounting for Stripping Costs in the Mining Industry ("EITF 04-06"). EITF 04-06 applies to stripping

F-29

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

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

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 rule, 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. The guidance in EITF 04-06 consensus is effective for fiscal years beginning after December 15, 2005, with early adoption permitted. The Company has recorded stripping costs for all its surface mines incurred during the production phase as variable production costs that are included in the cost of inventory produced. The Company defines 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 EITF 04-06, the Company 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 Company capitalizes only the development cost of the first pit at a mine site that may include multiple pits.

Asset Impairments—The Company follows Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which requires that projected undiscounted 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, discounted cash flows are utilized to determine the fair value of the assets being evaluated. 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. During the nine months ended December 31, 2006, the Company wrote off $5,032,089 and $4,954,425 of mineral rights and mine development costs, respectively, due to shortened mine lives. These amounts are included within depreciation, depletion and amortization. There were no impairment losses recorded during the years ended March 31, 2006 and December 31, 2007.

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—SFAS No. 143, Accounting for Asset Retirement Obligations, addresses asset retirement obligations that result from the acquisition, construction, or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations at fair value when the

F-30

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

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

liability is incurred or acquired. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Company has recorded the asset retirement costs in coal properties.

The Company 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 Company expenses contemporaneous reclamation which is performed prior to final mine closure as part of the cost of operations. 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 Company reviews its end of mine reclamation and closure liability and makes necessary adjustments, including mine plan and permit changes and revisions to cost and production levels to optimize mining and reclamation efficiency. When a mine life is shortened due to a change in the mine plan, mine closing obligations are accelerated, the related accrual is increased and the related asset is reviewed for impairment, accordingly.

The changes in the Company's asset retirement obligations for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007:

	Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Balance at beginning of period (including current portion)	$	19,639,536		$	23,306,129		$	30,168,469
Accretion expense		1,685,560			1,412,366			1,756,965
Additions resulting from property additions		3,020,081			1,540,180			9,841,870
Adjustments to the liability from annual recosting and other		2,783,048			6,268,450			(2,578,714	)
Liabilities settled		(3,822,096	)		(2,358,656	)		(2,801,191	)

Balance at end of period		23,306,129			30,168,469			36,387,399
Current portion of asset retirement obligation		1,875,634			2,928,607			2,582,646

Long-term portion of asset retirement obligation	$	21,430,495		$	27,239,862		$	33,804,753

F-31

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

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

The adjustments to the liability from annual recosting include a change in the discount rate used in the present value calculation of the liability. Changes in the asset retirement obligations for the nine months ended December 31, 2006 and the year ended December 31, 2007 were calculated with a discount rate 2% lower than the rate used for the year ended March 31, 2006. Other recosting adjustments to the liability are made annually based on inflationary cost increases and changes in the expected operating periods of the mines.

Sales Contract Liability—In connection with certain acquisitions in 2004, the Company acquired certain contracts with sales prices that are below its production cost. The Company recognized a liability for these contracts equal to the present value of the difference between the Company's cost and the contract amount in accordance with SFAS No. 141, Business Combinations. The Company amortizes this liability as sales are made under these sales contracts. Such amortization is included within depreciation, depletion and amortization.

Workers' Compensation and Black Lung Benefits—Certain of the Company'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 Company currently utilizes an insurance program and state workers' compensation fund participation to secure its ongoing workers' compensation and black lung obligations, depending on the location of the operation. Premium expense for workers' compensation and black lung benefits is recognized in the period in which the related insurance coverage is provided. For uninsured claims, the Company maintains an accrual for the estimated cost to settle open claims as well as an estimate of the cost of claims that have been incurred but not reported. These estimates take into account valuations from a third party actuary, current and historical trends and changes in the Company's business and workforce. The accruals for self-insurance could be affected if future occurrences and claims are different from assumptions used and historical trends.

Revenue Recognition—Most of the Company'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. Revenues are recognized on coal sales in accordance with the terms of the sales agreement, which is when the coal is shipped to the customer and title has passed. Advance payments received are deferred and recognized in revenue as coal is shipped and title has passed.

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 consist of limestone sales, coal handling, royalties, contract mining and rental income. These revenues are recognized in the period earned or when the service is completed.

Rebates—The Company receives rebates from a railroad transportation company for efficiencies obtained at a coal loadout facility. Rebates are based on a contracted rate per ton and are recorded when earned based upon when coal is shipped by the railroad transportation company. Included in revenues is $1,564,841, $959,103 and $400,648 associated with these rebate programs for the year ended

F-32

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

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

March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively.

Derivative Financial Instruments—During the year ended March 31, 2006 and the nine months ended December 31, 2006, the Company used futures contracts to manage the risk of fluctuations in the sales price of coal. The Company did not use derivative financial instruments for trading or speculative purposes. The Company designated the futures contracts as cash flow hedges and recorded the derivative financial instruments as either assets or liabilities, at fair value, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities and SFAS No. 149, Amendment on Statement 133 on Derivative Instruments and Hedging Activities. Changes in fair value are recorded as adjustments to the assets and liabilities being hedged in accumulated other comprehensive income, or in current earnings, depending on whether the derivative is designated and qualifies for hedge accounting, the type of transactions represented and the effectiveness of the hedge.

The Company did not enter into any new futures contracts during the nine months ended December 31, 2006 and the year ended December 31, 2007. At December 31, 2006 and 2007, the Company had no outstanding futures contracts.

In February 2008, the Company entered into futures contracts to sell 240,000 tons of coal at a weighted average price of $83.25 per ton.

Income taxes—The Company is considered as a partnership for income tax purposes. Accordingly, the members report the Company's taxable income or loss on their tax returns. The provisions for income tax consisted of state income taxes for the year ended March 31, 2006 and for the nine months ended December 31, 2006. This provision was a result of the state of Kentucky instituting a law effective January 1, 2005 that required partnerships to pay state income taxes. This law was rescinded on January 1, 2007, resulting in an income tax benefit for the year ended December 31, 2007.

The provision for income taxes consists of state income taxes for the year ended March 31, 2006 and the nine months ended December 31, 2006. This provision is a result of the state of Kentucky instituting a law effective January 1, 2005, that requires partnerships to pay state and local income taxes. This law was rescinded on January 1, 2007, resulting in an income tax benefit for the year ended December 31, 2007.

Loss Contingencies—In accordance with SFAS No. 5, Accounting for Contingencies, the Company records any 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 Company discloses information concerning loss contingencies for which an unfavorable outcome is more than remote. See Note 9, "Commitments and Contingencies," for a discussion of legal matters.

F-33

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

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

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

Recent Accounting Pronouncements—In June 2006, the Financial Accounting Standards Board ("FASB") issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since the Company is not a taxable entity for federal and state income tax purposes, its adoption of FIN 48 on January 1, 2007 did not have a material impact on its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R) ("SFAS No. 158"). SFAS No. 158 requires the recognition of the funded status of a defined benefit plan in the statement of financial position, requires that changes in the funded status be recognized through comprehensive income, changes the measurement date for defined benefit plan assets and obligations to the entity's fiscal year-end and expands disclosures. The recognition and disclosures under SFAS No. 158 are required as of the end of the fiscal year ending after December 15, 2006, while the new measurement date is effective for fiscal years ending after December 15, 2008. The Company adopted the recognition and disclosure provisions of SFAS No. 158 as of December 31, 2006 on the required prospective basis.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115 ("SFAS No. 159"). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. The fair value option may be applied on an instrument by instrument basis with certain exceptions. The election is irrevocable and must be applied to entire instruments and not to portions of instruments. For the Company, the election to apply the standard and measure certain financial instruments at fair value would be effective prospectively beginning January 1, 2008. The adoption of SFAS No. 159 did not have a material impact on the Company's financial position, results of operations or cash flows.

F-34

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

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

3. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of December 31, 2006 and 2007 consisted of the following:

	December 31, 2006		December 31, 2007
Note receivable	$	856,800	$	2,091,285
Restricted cash		550,928		663,960
Deferred offering costs		—		51,779
Other prepaid expenses		174,068		444,459
Prepaid insurance		714,466		1,444,504
Prepaid leases		169,163		182,743
Supply inventory		—		111,249
Deposits		78,774		45,300
Rebates receivable		252,643		650,785

Total	$	2,796,842	$	5,686,064

F-35

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of December 31, 2006 and 2007 are summarized by major classification as follows:

	Useful Lives	December 31, 2006			December 31, 2007
Land and land improvements		$	14,021,744		$	17,185,007
Mining and other equipment and related facilities	2 - 20 Years		111,555,425			143,124,537
Mine development costs	1 - 15 Years		32,614,869			35,571,195
Coal properties	1 - 15 Years		79,670,199			92,688,622
Construction work in process			8,117,971			993,203

Total			245,980,208			289,562,564
Less accumulated depreciation, depletion and amortization			(48,924,075	)		(77,905,483	)

Net		$	197,056,133		$	211,657,081

Depreciation expense for mining and other equipment and related facilities for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was $12,069,063, $12,770,013 and $20,960,235, respectively. Depletion expense for coal properties for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was $3,117,616, $7,461,467 and $3,611,530, respectively. Amortization expense for mine development costs for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was $2,525,160, $8,036,775 and $4,211,449, respectively.

5. OTHER NON-CURRENT ASSETS

Other non-current assets as of December 31, 2006 and 2007 consisted of the following:

	December 31, 2006		December 31, 2007
Note receivable	$	2,732,593	$	1,204,610
Deposits and other		591,826		285,715
Debt issuance costs—net		1,138,326		911,672
Deferred expenses		37,176		59,881
Other		13,026		—

Total	$	4,512,947	$	2,461,878

Debt issuance costs were $2,207,085 and $2,218,131 as of December 31, 2006 and 2007, respectively. Accumulated amortization of debt issuance costs were $1,068,759 and $1,306,459 as of December 31, 2006 and 2007, respectively.

F-36

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

6. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of December 31, 2006 and 2007 consisted of the following:

	December 31, 2006		December 31, 2007
Payroll, bonus and vacation expense	$	2,577,799	$	3,605,125
Non income taxes		3,527,320		3,064,416
Royalty expenses		2,922,277		2,702,810
Accrued interest		649,919		376,316
Health claims		1,380,858		1,961,410
Coal lease payable		413,000		413,000
Accrued income taxes		296,950		24,279
Workers' compensation and pneumoconiosis		243,518		1,566,298
Other		828,048		3,136,386

Total	$	12,819,689	$	16,850,040

7. DEBT

Debt as of December 31, 2006 and 2007 consisted of the following:

	December 31, 2006			December 31, 2007
Revolving line of credit with PNC Bank, N.A.	$	75,000,000		$	69,000,000
Note payable to H&L Construction Co., Inc.		7,412,003			7,135,638
Capital lease obligation with Applied Financial		1,046,272			732,777
Capital lease obligations with National City Bank		4,385,503			—
Note payable to National City Bank		—			1,093,300
Note payable to Huntington National Bank		—			2,945,375
Other notes payable		726,702			3,046,626

Total		88,570,480			83,953,716
Less current portion of long-term debt		(10,009,868	)		(10,161,633	)

Long term debt	$	78,560,612		$	73,792,083

Revolving line of credit with PNC Bank, N.A.—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, 2007 the Company had borrowed $68,000,000 at a variable interest rate of LIBOR plus 1.00% (5.83% at December 31, 2007) and $1,000,000 at a variable interest rate of Prime (7.25% at December 31, 2007). In addition, the Company had outstanding letters of credit of $18,388,530 at a fixed interest rate of 1.15% at December 31, 2007. The maximum amount available on the line of credit with PNC is $125,000,000. At December 31, 2007, the Company had not used $37,611,470 of the borrowing

F-37

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

7. DEBT (Continued)

availability. As part of the agreement, the Company is required to pay a commitment fee of 0.25% on the unused portion of the borrowing availability. Borrowings on the line of credit are collateralized by all the unsecured assets of the Company.

In February 2008, the Company amended the credit agreement with PNC and increased the maximum availability to $200,000,000. The amended credit agreement is to expire in February 2013.

The revolving credit commitment requires the Company to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Company was in compliance with all restrictive provisions as of December 31, 2007.

Note payable to H&L Construction Co., Inc.—The note payable to H&L Construction Co., Inc. is a non-interest bearing note. The Company has recorded a discount for imputed interest at a rate of 6.5% on this note. The Company is amortizing this discount over the life of the note using the effective interest method. The note payable matures in April 2009. The note is secured by mineral rights purchased by the Company from H&L Construction Co., Inc. with a carrying amount of $13,654,234 at December 31, 2007.

Capital Lease Obligations with National City Bank—Borrowings under the two capital leases with National City Bank are to be paid back in 48 equal installments of $74,586 and $48,960, with final payments due in April 2010. These notes were fully paid during 2007.

Note payable to National City Bank—Borrowing under the note payable to National City Bank bear interest at a variable rate of LIBOR plus 1.35% (6.18% at December 31, 2007) This note is payable in monthly principal and interest installments and matures in February 2010.

Note payable to Huntington National Bank—Borrowings under the note payable to Huntington National Bank bear interest at a fixed rate of 6.80%. This note is payable in monthly principal and interest installments and matures in May 2010.

F-38

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

7. DEBT (Continued)

Principal payments on long-term debt due subsequent to December 31, 2007, are as follows:

2008	$	10,161,633
2009		2,070,776
2010		649,810
2011		—
2012		69,000,000
Thereafter		2,393,552

Total principal payments		84,275,771
Less imputed interest on interest free notes payable		(322,055	)

Total debt	$	83,953,716

8. EMPLOYEE BENEFITS

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

As discussed in Note 2, the Company adopted SFAS No. 158 on December 31, 2006 on the required prospective basis.

Summaries of the changes in benefit obligations and funded status of the plan as of the measurement dates of March 31, 2006 and December 31, 2006 and 2007 are as follows:

	Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Benefit obligation at beginning of period	$	3,442,537		$	4,115,559		$	5,402,857
Changes in benefit obligations:
Service costs		448,800			387,147			535,428
Interest cost		199,339			178,301			292,199
Benefits paid		—			(13,192	)		(15,693	)
Actuarial loss (gain)		24,883			735,042			(1,476,499	)

Benefit obligation at end of period	$	4,115,559		$	5,402,857		$	4,748,292

Fair value of plan assets at end of period	$	—		$	—		$	—

Funded status	$	(4,115,559	)	$	(5,402,857	)	$	(4,748,292	)

F-39

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

8. EMPLOYEE BENEFITS (Continued)

	Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Calculation of net amount recognized:
Funded status at end of period	$	(4,115,559	)	$	(5,402,857	)	$	(4,748,292	)
Unrecognized actuarial loss		165,998			n/a			n/a

Net amount recognized	$	(3,949,561	)	$	(5,402,857	)	$	(4,748,292	)

	Year Ended March 31, 2006			Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Classification of net amount recognized:
Current liability—postretirement benefits	$	(64,025	)	$	(97,004	)	$	(91,785	)
Non-current liability—postretirement benefits		(3,885,536	)		(5,305,853	)		(4,656,507	)

Net amount recognized	$	(3,949,561	)	$	(5,402,857	)	$	(4,748,292	)

	Year Ended March 31, 2006	Nine Months Ended December 31, 2006			Year Ended December 31, 2007
Amount recognized in accumulated other comprehensive income (loss):
Net actuarial gain (loss)	n/a	$	(901,040	)	$	588,376

Weighted Average Assumptions		Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Year Ended December 31, 2007
Discount rate		6.00	%	5.60	%	6.25	%
Expected return on plan assets		n/a		n/a		n/a

	Year Ended March 31, 2006		Nine Months Ended December 31, 2006		Year Ended December 31, 2007
Net periodic benefit cost:
Service costs	$	448,800	$	387,147	$	535,428
Interest cost		199,339		178,301		293,199

Benefit cost	$	648,139	$	565,448	$	828,627

F-40

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

8. EMPLOYEE BENEFITS (Continued)

Actual contributions from January 1, 2007 through December 31, 2007:	$	15,693
Expected benefit payments:
Period
2008	$	91,785
2009		161,882
2010		223,558
2011		326,161
2012		450,218
2013-2017		4,311,257

For measurement purposes, a 9.0% annual rate of increase in the per capita cost of covered health care benefits was assumed, gradually decreasing to 5.0% in 2016 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 Company are not eligible for benefits under the plan.

The expense and liability estimates can fluctuate by significant amounts based upon the assumptions used. As of December 31, 2007, 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
Effect on total service and interest cost components		$	47,037		$	(42,046	)
Effect on postretirement benefit obligation		$	409,396		$	(371,336	)

401(k) Plans—The Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Company 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 Company's discretion. The Company made discretionary contributions of $732,936, $522,960 and $674,596 for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively. Under the Company's remaining defined contribution savings plans, any contributions made by the Company are based on the Company's discretion. The expense under these plans for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, was approximately $1,419,000, $1,043,000 and $1,261,600, respectively.

9. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of December 31, 2007, the Company had commitments under sales contracts to deliver annually scheduled base quantities of 6.9 million, 4.5 million and 2.2 million tons of coal to 23 customers in 2008, 12 customers in 2009, and 4 customers in 2010,

F-41

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

9. COMMITMENTS AND CONTINGENCIES (Continued)

respectively. Certain 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, 2007, the Company had 8.1 million gallons remaining on a commitment to purchase diesel fuel at fixed prices ranging from $1.90 to $2.81 per gallon through May 2009.

Leases—The Company leases various mining, transportation and other equipment under operating leases. Lease expense for the year ended March 31, 2006, the nine months ended December 31, 2006, the year ended December 31, 2007 was approximately $8,099,000, $8,469,000 and $10,423,000, respectively.

The Company also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Total royalty expense for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007 was approximately $20,699,000, $13,882,000 and $20,518,000, respectively.

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 Ending December 31,	Royalties		Leases
2008	$	2,315,000	$	7,788,000
2009		1,902,000		6,128,000
2010		1,902,000		1,135,000
2011		1,526,000		1,123,000
2012		1,402,000		1,127,000
Thereafter		7,010,000		6,143,000

Total minimum royalty and lease payments	$	16,057,000	$	23,444,000

Environmental Matters—Based upon current knowledge, the Company 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 Company 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 Company is involved in various legal proceedings arising in the ordinary course of business. In the opinion of management, the Company is not party to any pending litigation that is likely to have a material adverse effect on the financial condition, results of operations or cash flows of the Company. Management of the Company is not aware of any significant legal or governmental proceedings against or contemplated to be brought against the Company. In addition, the Company maintains insurance policies with insurers in amounts and with coverage and deductibles which management believes are reasonable and prudent.

F-42

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

9. COMMITMENTS AND CONTINGENCIES (Continued)

Guarantees/Indemnifications and Financial Instruments with Off-Balance Sheet Risk —In the normal course of business, the Company 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 Company's consolidated statements of financial position. Management does not expect any material losses to result from these guarantees or off-balance sheet financial instruments. The amount of bank letters of credit outstanding with PNC as of December 31, 2007 was $18,388,530. The bank letters of credit outstanding with PNC reduce the Company's borrowing capacity on its line of credit with PNC. In addition, the Company has outstanding surety bonds with third parties of $49,432,535 as of December 31, 2007, to secure reclamation and other performance commitments.

The line of credit with PNC is fully and unconditionally, jointly and severally guaranteed by the Company and substantially all of its wholly owned subsidiaries. Borrowings on the line of credit with PNC are collateralized by the unsecured assets of the Company and substantially all of its wholly owned subsidiaries. See Note 7 for a more complete discussion of the Company's debt obligations.

The Company is owned by a collection of investment funds managed by Wexford Capital LLC ("Wexford"). These funds fully and unconditionally guarantee the Company's obligations under its outstanding surety bonds with third parties to secure reclamation and other performance commitments.

Employment Agreements—The Company has employment agreements with key executive officers which expire between December 2008 and May 2011. In addition to a base salary, the agreements provide for bonuses based on net income. No maximum compensation limit exists. Total salary and bonus expenses of $2,111,712, $3,263,190 and $4,385,735 were recognized under the employment agreements for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively.

10. MAJOR CUSTOMERS

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

	March 31, 2006 Receivable Balance		Year Ended March 31, 2006 Sales		December 31, 2006 Receivable Balance		Nine Months Ended December 31, 2006 Sales		December 31, 2007 Receivable Balance		Year Ended December 31, 2007 Sales
Customer A		n/a		n/a	$	6,980,467	$	59,270,453	$	6,112,034	$	97,930,807
Customer B	$	3,654,547	$	61,612,564		n/a		n/a	$	1,805,892	$	57,110,321
Customer C		n/a		n/a		n/a		n/a	$	5,662,044	$	68,011,968
Customer D		n/a		n/a	$	6,299,003	$	71,709,624	$	3,597,077	$	52,746,859

F-43

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

11. 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 Company's debt instruments and notes receivable approximate fair value since effective rates for these instruments are comparable to market at year-end.

12. RELATED PARTY TRANSACTIONS

From time to time, employees from Wexford perform legal, consulting, and advisory services to the Company. The Company incurred expenses of approximately $70,186, $146,254 and $165,719 for year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively, for legal, consulting, and advisory services performed by Wexford.

During the year ended December 31, 2007, the Company made cash distributions to members of $9,250,000.

During the year ended March 31, 2006, the Company had borrowings under a note payable to Callidus Investors, an equity fund managed by Wexford. The Company had no outstanding borrowings under this note as of December 31, 2006 and 2007. The Company made payments of $855,000 on notes payable for the year ended March 31, 2006. The Company recorded interest expense of $75,755 for the year ended March 31, 2006.

13. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash payments for interest were $4,654,978, $5,416,373 and $4,958,231 for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, respectively.

The statement of cash flows for the year ended March 31, 2006, is exclusive of (1) $29,887,861 property additions financed through long-term debt borrowings and other assumed liabilities,; and (2) $5,228,681 of non-cash additions to asset retirement obligations and mineral rights.

The statement of cash flows for the nine months ended December 31, 2006, is exclusive of (1) $9,692,093 of property additions financed through long-term debt borrowings and other assumed liabilities; and (2) $5,058,623 of non-cash additions to asset retirement obligations and mineral rights.

The statement of cash flows for the year ended December 31, 2007, is exclusive of (1) $6,964,948 of property additions financed through long-term debt borrowings and other assumed liabilities; and (2) $9,841,870 of non-cash additions to asset retirement obligations and mineral rights.

14. SEGMENT INFORMATION (RESTATED)

The Company produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Colorado. The Company sells primarily to electric utilities in the United States. The Company has four reporting segments: Central Appalachia (comprised of both surface and underground mines located in eastern Kentucky and southern West Virginia); Northern Appalachia (comprised of an underground mine located in Ohio); the Sands Hill segment (which includes surface

F-44

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

14. SEGMENT INFORMATION (RESTATED) (Continued)

mines in southern Ohio and was acquired in December 2007) and the Other segment (which includes the mines located in Colorado that do not meet the aggregation criteria and that do not exceed the quantitative thresholds requiring separate disclosure as a reportable segment). The Company has not provided disclosure of total expenditures by segment for long-lived assets, as the Company does not maintain discrete financial information concerning segment expenditures for long-lived assets, and accordingly such information is not provided to the Company's chief operating decision maker. The Other segment includes the Company's Colorado, Illinois, and other ancillary businesses, NYMEX coal trading activities (the year ended March 31, 2006 and the nine months ended December 31, 2006 only), and corporate overhead expenses.

Reportable segment financial condition and results of operations as of and for the year ended March 31, 2006 are as follows:

	Central Appalachia		Northern Appalachia		Other			Total Segments
Total assets	$	128,233,238	$	25,184,758	$	93,341,314		$	246,759,310
Total revenues	$	307,138,637	$	48,954,497	$	7,866,778		$	363,959,912
Depreciation, depletion and amortization	$	10,966,108	$	2,503,562	$	274,581		$	13,744,251
Interest expense	$	4,184,664	$	636,179	$	155,332		$	4,976,175
Net income (loss)	$	29,022,453	$	2,672,537	$	(33,669	)	$	31,661,320

Reportable segment financial condition and results of operations as of and for the nine months ended December 31, 2006 are as follows:

	Central Appalachia			Northern Appalachia		Other			Total Segments
Total assets	$	117,249,310		$	29,770,697	$	101,174,445		$	248,194,452
Total revenues	$	247,810,356		$	45,461,601	$	7,566,580		$	300,838,537
Depreciation, depletion and amortization	$	24,628,214		$	3,122,627	$	720,367		$	28,471,208
Interest expense	$	4,568,804		$	906,115	$	1,023,039		$	6,497,958
Net income (loss)	$	(227,016	)	$	5,212,089	$	(1,927,578	)	$	3,057,495

The Company wrote off $5,032,089 and $4,954,425 of mineral rights and mine development costs rights, respectively, due to shortened mine lives in the Central Appalachia segment for the nine months ended December 31, 2006. The Other segment includes revenue, depreciation, depletion and amortization, interest and net income from the Company's Colorado operation and other ancillary businesses. Total assets in the Other segment consists of intercompany receivables and payables between the Company and its subsidiaries, and assets related to the Company's Colorado operation and other ancillary businesses.

F-45

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

14. SEGMENT INFORMATION (RESTATED) (Continued)

Subsequent to the original issuance of the Company's 2007 financial statements, the Company's management determined that the Company's Sands Hill operating segment should have been presented as a separate reportable segment, as its assets exceeded 10% of the combined assets of all operating segments as of December 31, 2007. As a result, the 2007 segment information has been restated from the amounts previously reported to present Sands Hill as a reportable segment, separate from the Other segment.

Reportable segment financial condition and results of operations as of and for the year ended December 31, 2007 are as follows:

					As Restated
	Central Appalachia		Northern Appalachia		As Restated						Total Segments
	Central Appalachia		Northern Appalachia		Sands Hill			Other			Total Segments
Total assets	$	127,547,348	$	28,963,615	$	29,831,722		$	89,649,549		$	275,992,234
Total revenues	$	339,592,714	$	53,420,917	$	1,032,679		$	9,405,487		$	403,451,797
Depreciation, depletion and amortization	$	24,488,240	$	4,162,778	$	125,107		$	1,973,648		$	30,749,773
Interest expense	$	4,165,825	$	712,527	$	9,986		$	690,886		$	5,579,224
Net income (loss)	$	23,091,612	$	9,038,762	$	(160,184	)	$	(1,256,426	)	$	30,713,764

The Other segment includes revenue, depreciation, depletion and amortization, interest and net income from the Company's operations in Colorado, Illinois and other ancillary businesses. Total assets in the Other segment consists of intercompany receivables and payables between the Company and its subsidiaries, and assets related to the Company's operations in Colorado and other ancillary businesses.

15. CHANGE IN FISCAL YEAR (UNAUDITED)

Effective April 1, 2006, the Company changed its fiscal year end from March 31 to December 31. Condensed consolidated financial information as of and for the nine months ended December 31, 2005 and 2006 is as follows:

	As of and For the Nine Months Ended December 31,
	2005			2006
Total assets	$	222,595,575		$	248,194,452
Total liabilities	$	139,573,344		$	153,307,094
Total revenues	$	255,329,872		$	300,838,537
Total costs and expenses	$	230,118,248		$	291,742,373
Net income	$	21,952,648		$	3,057,495
Cash provided by operating activities	$	33,145,694		$	36,859,479
Cash (used) in investing activities	$	(53,507,347	)	$	(28,827,572	)
Cash provided by (used in) financing activities	$	15,426,270		$	(9,140,791	)

F-46

RHINO ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

AS OF DECEMBER 31, 2006 AND 2007

AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006

AND THE YEAR ENDED DECEMBER 31, 2007

16. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of our quarterly operating results for the nine months ended December 31, 2006 and the year ended 2007 is as follows:

	Quarter Ended
	June 30, 2006		September 30, 2006		December 31, 2006
Total revenues	$	104,757,843	$	100,627,081	$	95,453,613
Income (loss) from operations	$	8,317,649	$	7,827,049	$	(7,048,534	)
Net income (loss)	$	6,854,623	$	5,489,087	$	(9,286,215	)

	Quarter Ended
	March 31, 2007		June 30, 2007		September 30, 2007		December 31, 2007
Total revenues	$	101,551,710	$	91,949,329	$	100,311,791	$	109,638,967
Income from operations	$	11,141,725	$	8,444,387	$	10,415,680	$	5,848,178
Net income	$	9,495,000	$	7,274,296	$	9,101,359	$	4,843,109

For the quarter ended December 31, 2006, the Company wrote off $5,032,089 and $4,954,425 of mineral rights and mine development costs, respectively, due to shortened mine lives in the Central Appalachia segment. There were no other write-offs as a result of asset impairments.

17. SUBSEQUENT EVENT

In February 2008, the Company acquired the coal operations of Deane mining complex, located in Kentucky. This acquisition included several underground mines, surface property, a preparation plant and a unit train load-out. The Company allocated the purchase price to assets and liabilities acquired based upon an initial determination, which is subject to adjustment, of their respective fair values in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations. The recorded value of the assets and (liabilities) were:

Property, plant and equipment	$	31,493,404
Property taxes		(5,014	)
Asset retirement obligations		(16,823,731	)

Net assets acquired	$	14,664,659

Pro forma results of operations that give effect to the Deane mining complex acquisition as if it had occurred at the beginning of the period have not been provided, as the Deane mining complex acquisition would not have had a significant impact on the Company's results of operations for the year ended December 31, 2007.

18. UNAUDITED PRO FORMA EARNINGS PER SHARE

Unaudited pro forma earnings per share reflect the provision for income taxes under Rhino Resources, Inc.'s new corporate holding company structure, divided by the common stock to be issued to Rhino Energy Holdings LLC and certain Wexford Funds in exchange for the contribution of their ownership interests in the Company to Rhino Resources Inc., each of which will occur upon Rhino Resources, Inc.'s initial public offering.

F-47

RHINO RESOURCE PARTNERS, L.P.

UNAUDITED STATEMENT OF FINANCIAL POSITION

AS OF JUNE 30, 2008

		June 30, 2008
Assets		$	—

Liabilities		$	—

Partners' equity
	Limited partner's equity		980
	General partner's equity		20
	Receivable from partners		(1,000	)

Total partners' equity			—

Total liabilities and partners' equity		$	—

See notes to statement of financial position.

F-48

RHINO RESOURCE PARTNERS, L.P.

NOTES TO THE UNAUDITED STATEMENT OF FINANCIAL POSITION

1. ORGANIZATION AND OPERATIONS

Rhino Resource Partners, L.P. (the "Partnership") is a Delaware limited partnership formed on January 11, 2006 to acquire the assets of Rhino Energy LLC, an entity engaged primarily in the mining and sale of coal. In connection with an initial public offering, the Partnership intends to convert into a corporation named Rhino Resources, Inc., which entity will own and operate the acquired assets through a wholly owned operating company.

Rhino GP LLC, as the general partner, has committed to contribute $20 to the Partnership. Rhino Energy Holdings LLC, an entity owned by Wexford Funds, has committed to contribute $980 to the Partnership. These contributions receivable are reflected as a reduction to partners' equity.

The Partnership had no operations during the period from January 11, 2006 (date of formation) to December 31, 2006, for the year ended December 31, 2007 or for the six months ended June 30, 2008.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recent Accounting Pronouncements—In June 2006, the Financial Accounting Standards Board ("FASB") issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since we are not a taxable entity for federal and state income tax purposes, our adoption of FIN 48 on January 1, 2007 did not have a material impact on our consolidated financial statements.

3. SUBSEQUENT EVENT

On July 23, 2008, the Partnership converted into a corporation and changed its name to Rhino Resources, Inc. In connection with the conversion, Rhino Energy Holdings LLC was issued 1,000 shares of common stock in redemption of its 98% limited partner interest in the Partnership and the 2% general partner interest held by Rhino GP LLC was cancelled.

F-49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Rhino Resource Partners, L.P.:

We have audited the accompanying statements of financial position of Rhino Resource Partners, L.P. (the "Partnership") as of December 31, 2006 and 2007. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit 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 audit provides a reasonable basis for our opinion.

In our opinion, such statements of financial position present fairly, in all material respects, the financial position of the Partnership at December 31, 2006 and 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Cincinnati, OH
July 16, 2008

F-50

RHINO RESOURCE PARTNERS, L.P.

STATEMENTS OF FINANCIAL POSITION

AS OF DECEMBER 31, 2006 AND 2007

		December 31, 2006			December 31, 2007
Assets		$	—		$	—

Liabilities		$	—		$	—

Partners' equity
	Limited partner's equity		980			980
	General partner's equity		20			20
	Receivable from partners		(1,000	)		(1,000	)

Total partners' equity			—			—

Total liabilities and partners' equity		$	—		$	—

See notes to statements of financial position.

F-51

RHINO RESOURCE PARTNERS, L.P.

NOTES TO THE STATEMENTS OF FINANCIAL POSITION

1. ORGANIZATION AND OPERATIONS

Rhino Resource Partners, L.P. (the "Partnership") is a Delaware limited partnership formed on January 11, 2006. In connection with an initial public offering, the Partnership intends to convert into a corporation named Rhino Resources, Inc., which entity will acquire and operate the assets of Rhino Energy LLC, an entity engaged primarily in the mining and sale of coal, through a wholly owned operating company.

The Partnership had no operations during the period from January 11, 2006 (date of formation) to December 31, 2006 or for the year ended December 31, 2007.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recent Accounting Pronouncements—In June 2006, the Financial Accounting Standards Board ("FASB") issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. Since we are not a taxable entity for federal and state income tax purposes, our adoption of FIN 48 on January 1, 2007 did not have a material impact on our consolidated financial statements.

F-52

APPENDIX A

Glossary of Terms

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.

GAAP: Generally accepted accounting principles in the United States.

limestone: A rock predominantly composed of the mineral calcite (calcium carbonate (CaCO₂)).

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.

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.

probable (indicated) reserves: Reserves for which quantity and grade and/or quality are computed form information similar to that used for proven (measure) 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.

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.

A-1

PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than the underwriting discount) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and The New York Stock Exchange listing fee, the amounts set forth below are estimates.

SEC registration fee	$	18,078
FINRA filing fee		46,500
The New York Stock Exchange listing fee		150,000
Printing and engraving expenses		350,000
Fees and expenses of legal counsel		750,000
Accounting fees and expenses		200,000
Transfer agent fees		3,500
Miscellaneous		481,922

Total	$	2,000,000

Item 14. Indemnification of Directors and Officers.

Section 145 of the Delaware General Corporation Law ("DGCL") provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Section 145 further provides that a corporation similarly may indemnify any such person serving in any such capacity who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys' fees) actually and reasonably incurred in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Delaware Court of Chancery or such other court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all of the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper. Our certificate of incorporation and bylaws provide that indemnification shall be to the fullest extent permitted by the DGCL for all our current or former directors or officers. As permitted by the DGCL, our certificate of incorporation provides that we will indemnify our directors against liability to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director's duty of loyalty to us or our stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or

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knowing violation of law, (3) under Section 174 of the DGCL or (4) for any transaction from which a director derived an improper personal benefit.

We have also entered into indemnification agreements with all of our directors and all of our named executive officers and employment agreements with all of our named executive officers. These indemnification agreements and employment agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the DGCL. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.

The indemnification agreements and the employment agreements cover expenses (including attorneys' fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his or her capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements and the employment agreements generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements and the employment agreements also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements and the employment agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.

We are not obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:

•: us, except for:
•: claims regarding the indemnitee's rights under the indemnification agreement;
•: claims to enforce a right to indemnification under any statute or law; and
•: counter-claims against us in a proceeding brought by us against the indemnitee; or
•: any other person, except for claims approved by our board of directors.

We have obtained director and officer liability insurance for the benefit of each of the above indemnitees. These policies include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnitees are named as an insured under such policies and provided with the same rights and benefits as are accorded to the most favorably insured of our directors and officers.

Item 15. Recent Sales of Unregistered Securities.

Other than as described in this Item, there have been no other sales of unregistered securities within the past three years.

On January 11, 2006, in connection with the formation of the partnership, Rhino Resource Partners, L.P. issued (1) to Rhino GP LLC the 2% general partner interest in the partnership for $20 and (2) to Rhino Energy Holdings LLC the 98% limited partner interest in the partnership for $980.

On July 23, 2008, in connection with the conversion of Rhino Resource Partners, L.P. into Rhino Resources, Inc., a Delaware corporation, Rhino Energy Holdings LLC was issued 1,000 shares of common stock in redemption of its 98% limited partnership interest in Rhino Resource Partners, L.P.

Each of the issuances described above was made without registration in reliance upon Section 4(2) of the Securities Act of 1933.

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Item 16. Exhibits and Financial Statement Schedules.

(a): The following documents are filed as exhibits to this registration statement:

Exhibit Number		Description
1.1	***	—	Form of Underwriting Agreement
3.1	**	—	Form of Restated Certificate of Incorporation of Rhino Resources, Inc.
3.2	**	—	Form of Amended and Restated Bylaws of Rhino Resources, Inc.
4.1	**	—	Specimen of Common Stock Certificate
5.1	***	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
10.1	**	—	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
10.2	**	—	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
10.3	**	—	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
10.4	**	—	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
10.5	**	—	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
10.6	**	—	Form of Fifth Amendment to the Credit Agreement
10.7	**	—	Form of Rhino Resources, Inc. Long-Term Incentive Plan
10.8	**	—	Form of Long-Term Incentive Plan Grant Agreement
10.9	**	—	Form of Employment Agreement of Nicholas R. Glancy
10.10	**	—	Form of Employment Agreement of Richard A. Boone
10.11	**	—	Form of Employment Agreement of David Zatezalo
10.12	**	—	Form of Employment Agreement of Christopher N. Moravec

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10.13	**	—	Form of Employment Agreement of Thomas Hanley
10.14	**	—	Form of Registration Rights Agreement
10.15	**	—	Form of Administrative Services Agreement
10.16	**	—	Form of Contribution Agreement
10.17	**	—	Director Compensation Information
21.1	**	—	List of Subsidiaries of Rhino Resources, Inc.
23.1	*	—	Consents of Deloitte & Touche LLP
23.2	*	—	Consent of Deloitte & Touche LLP
23.3	*	—	Consent of Marshall Miller & Associates, Inc.
23.4	*	—	Consent of John T. Boyd Company
23.5	***	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
24.1	**	—	Powers of Attorney (included on the signature page)
99.1	**	—	Consent of John P. McCarty, Director Nominee
99.2	**	—	Consent of Eugene D. Aimone, Director Nominee
99.3	**	—	Consent of Joseph M. Jacobs, Director Nominee
99.4	*	—	Consent of Mark L. Plaumann, Director Nominee

*

Filed herewith.

Previously filed.

***

To be filed by amendment.

(b): Financial Statements Schedules.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of
Rhino Energy LLC
Lexington, Kentucky

We have audited the consolidated financial statements of Rhino Energy LLC (the "Company") as of December 31, 2007 and 2006, and for the year ended March 31, 2006, the nine months ended December 31, 2006 and the year ended December 31, 2007, and have issued our report thereon dated April 10, 2008 (September 10, 2008 as to Note 14) (which report expresses an unqualified opinion and includes explanatory paragraphs concerning the adoption of SFAS No. 158, Employer's Accounting for Defined Benefit Pension and other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R), and a change in the Company's fiscal year end), included elsewhere in this Registration Statement. Our audits also included the consolidated financial statement schedule appearing in Item 16(b) of this Registration Statement. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio
April 10, 2008

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	Balance at Beginning of Period		Additions		Deductions		Balance at End of Period
For the year ended December 31, 2007
Allowance for doubtful accounts	$	175,242	$	—	$	175,242	$	—
For the nine months ended December 31, 2006
Allowance for doubtful accounts	$	458,000	$	175,242	$	458,031	$	175,242
For the year ended March 31, 2006
Allowance for doubtful accounts	$	104,000	$	458,000	$	104,000	$	458,000

Item 17. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1): For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this registration statement as of the time it was declared effective.
(2): For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on September 10, 2008.

		RHINO RESOURCES, INC.
		By:	/s/ NICHOLAS R. GLANCY Nicholas R. Glancy President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities indicated on September 10, 2008.

Signature		Title

/s/ NICHOLAS R. GLANCY Nicholas R. Glancy		President and Chief Executive Officer and Director (Principal Executive Officer)
* Richard A. Boone		Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
* Mark D. Zand		Chairman of the Board
* Jay L. Maymudes		Director
* Arthur H. Amron		Director
* Kenneth A. Rubin		Director

*By:

/s/ NICHOLAS R. GLANCY

Nicholas R. Glancy

Attorney-in-fact

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EXHIBIT INDEX

Exhibit Number	Description
1.1***	—	Form of Underwriting Agreement
3.1**	—	Form of Restated Certificate of Incorporation of Rhino Resources, Inc.
3.2**	—	Form of Amended and Restated Bylaws of Rhino Resources, Inc.
4.1**	—	Specimen of Common Stock Certificate
5.1***	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
10.1**	—	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
10.2**	—	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
10.3**	—	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
10.4**	—	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
10.5**	—	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
10.6**	—	Form of Fifth Amendment to the Credit Agreement
10.7**	—	Form of Rhino Resources, Inc. Long-Term Incentive Plan
10.8**	—	Form of Long-Term Incentive Plan Grant Agreement
10.9**	—	Form of Employment Agreement of Nicholas R. Glancy
10.10**	—	Form of Employment Agreement of Richard A. Boone
10.11**	—	Form of Employment Agreement of David Zatezalo
10.12**	—	Form of Employment Agreement of Christopher N. Moravec
10.13**	—	Form of Employment Agreement of Thomas Hanley
10.14**	—	Form of Registration Rights Agreement
10.15**	—	Form of Administrative Services Agreement

10.16**	—	Form of Contribution Agreement
10.17**	—	Director Compensation Information
21.1**	—	List of Subsidiaries of Rhino Resources, Inc.
23.1*	—	Consents of Deloitte & Touche LLP
23.2*	—	Consent of Deloitte & Touche LLP
23.3*	—	Consent of Marshall Miller & Associates, Inc.
23.4*	—	Consent of John T. Boyd Company
23.5***	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
24.1**	—	Powers of Attorney (included on the signature page)
99.1**	—	Consent of John P. McCarty, Director Nominee
99.2**	—	Consent of Eugene D. Aimone, Director Nominee
99.3**	—	Consent of Joseph M. Jacobs, Director Nominee
99.4*	—	Consent of Mark L. Plaumann, Director Nominee

*: Filed herewith.
**: Previously filed.
***: To be filed by amendment.

QuickLinks

TABLE OF CONTENTS
SUMMARY
Rhino Resources, Inc.
Business Strategies
Recent Coal Market Conditions and Trends
Summary of Risk Factors
Transactions and Organizational Structure
Principal Executive Offices
The Offering
Summary Historical and Pro Forma Consolidated Financial and Operating Data
RISK FACTORS
USE OF PROCEEDS
DIVIDEND POLICY
CAPITALIZATION
DILUTION
SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL AND OPERATING DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THE COAL INDUSTRY
BUSINESS
MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND THE SELLING STOCKHOLDER
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
DESCRIPTION OF OUR CAPITAL STOCK
SHARES ELIGIBLE FOR FUTURE SALE
CERTAIN U.S. FEDERAL TAX CONSIDERATIONS FOR NON-U.S. HOLDERS
UNDERWRITING
VALIDITY OF OUR COMMON STOCK
EXPERTS
WHERE YOU CAN FIND MORE INFORMATION
FORWARD-LOOKING STATEMENTS
INDEX TO FINANCIAL STATEMENTS
RHINO RESOURCES, INC. UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
RHINO RESOURCES, INC. UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF FINANCIAL POSITION AS OF JUNE 30, 2008
RHINO RESOURCES, INC. UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2008
RHINO RESOURCES, INC. UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2007
RHINO RESOURCES, INC. NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2007 AND AS OF AND FOR THE SIX MONTHS ENDED JUNE 30, 2008
RHINO ENERGY LLC UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AS OF JUNE 30, 2008
RHINO ENERGY LLC UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008
RHINO ENERGY LLC UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008
RHINO ENERGY LLC NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AS OF JUNE 30, 2008 AND FOR THE SIX MONTHS ENDED JUNE 30, 2007 AND 2008
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
RHINO ENERGY LLC CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AS OF DECEMBER 31, 2006 AND 2007
RHINO ENERGY LLC CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006 AND THE YEAR ENDED DECEMBER 31, 2007
RHINO ENERGY LLC CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006 AND THE YEAR ENDED DECEMBER 31, 2007
RHINO ENERGY LLC CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006 AND THE YEAR ENDED DECEMBER 31, 2007
RHINO ENERGY LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 2006 AND 2007 AND FOR THE YEAR ENDED MARCH 31, 2006, THE NINE MONTHS ENDED DECEMBER 31, 2006 AND THE YEAR ENDED DECEMBER 31, 2007
RHINO RESOURCE PARTNERS, L.P. UNAUDITED STATEMENT OF FINANCIAL POSITION AS OF JUNE 30, 2008
RHINO RESOURCE PARTNERS, L.P. NOTES TO THE UNAUDITED STATEMENT OF FINANCIAL POSITION
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
RHINO RESOURCE PARTNERS, L.P. STATEMENTS OF FINANCIAL POSITION AS OF DECEMBER 31, 2006 AND 2007
RHINO RESOURCE PARTNERS, L.P. NOTES TO THE STATEMENTS OF FINANCIAL POSITION
APPENDIX A Glossary of Terms
PART II INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Item 14. Indemnification of Directors and Officers.

Item 15. Recent Sales of Unregistered Securities.

Item 16. Exhibits and Financial Statement Schedules.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Item 17. Undertakings.

SIGNATURES
EXHIBIT INDEX