S-1/A 1 a2185709zs-1a.htm S-1/A
QuickLinks -- Click here to rapidly navigate through this document

As filed with the Securities and Exchange Commission on August 7, 2008

Registration No. 333-150262



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


AMENDMENT NO. 5
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)

3120 Wall Street, Suite 310
Lexington, Kentucky 40513
(859) 389-6500
(Address, Including Zip Code, and Telephone Number, Including
Area Code, of Registrant's Principal Executive Offices)

Nicholas R. Glancy
3120 Wall Street, Suite 310
Lexington, Kentucky 40513
(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
  G. Michael O'Leary
W. Mark Young
Andrews Kurth LLP
600 Travis
Suite 4200
Houston, Texas 77002
(713) 220-4200

          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 August 7, 2008

PROSPECTUS

10,000,000 Shares

GRAPHIC

Common Stock


        This is our initial public offering. We are offering 6,500,000 shares of common stock and the selling stockholder, Rhino Energy Holdings LLC, is offering 3,500,000 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 $11.00 and $12.00 per share. We have been approved to list our common stock on The New York Stock Exchange under the symbol "RNO."

        Investing in our common stock involves risks. See "Risk Factors" beginning on page 17.


PRICE $            A SHARE


 
  Price to
Public

  Underwriting
Discount and
Commissions

  Proceeds to
Rhino Resources, Inc.

  Proceeds to
the Selling
Stockholder

Per Share   $                   $                   $                   $                
Total   $                   $                   $                   $                

        The selling stockholder has granted the underwriters the right to purchase up to an additional 1,500,000 shares of common stock to cover over-allotments.

        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.

        The underwriters expect to deliver the shares of common stock to purchasers on or about                        , 2008.

Morgan Stanley   Lehman Brothers

  Raymond James  

 

RBC Capital Markets

 

 

Stifel Nicolaus

 

 

Wachovia Securities

 

  Dahlman Rose & Company LLC  

 

Davenport & Company LLC

 

 

Friedman Billings Ramsey

 

 

PNC Capital Markets LLC

 

                        , 2008


LOGO



TABLE OF CONTENTS

 
   
Summary   1
Risk Factors   17
Use of Proceeds   33
Dividend Policy   34
Capitalization   35
Dilution   36
Selected Historical and Pro Forma Consolidated Financial and Operating Data   38
Management's Discussion and Analysis of Financial Condition and Results of Operations   43
The Coal Industry   82
Business   90
Management   121
Security Ownership of Certain Beneficial Owners, Management and the Selling Stockholder   133
Certain Relationships and Related Party Transactions   134
Description of Our Capital Stock   136
Shares Eligible For Future Sale   140
Certain U.S. Federal Tax Considerations For Non-U.S. Holders   142
Underwriting   146
Validity of Our Common Stock   153
Experts   153
Where You Can Find More Information   153
Forward-Looking Statements   155
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.

i



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 17 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. 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 three months ended March 31, 2008, we produced approximately 2.0 million tons of coal and sold approximately 2.1 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. Recently, 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. In May 2008, we entered into a joint venture that acquired the Eagle mining complex located in Central Appalachia and to which we contributed our lease of the nearby Bolt field, which we entered into in February 2008. These recent acquisitions collectively added approximately 39.7 million tons of proven and probable coal reserves and approximately 28.7 million tons of non-reserve coal deposits. We expect to produce approximately 2.1 million tons of coal in 2009 from our recently acquired mining complexes, including approximately 0.3 million tons of metallurgical coal. 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 $232.2 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

1



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 0.4 million tons of coal for the three months ended March 31, 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 200,000 tons of coal for the three months ended March 31, 2008. We also control 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 three months ended March 31, 2008, we generated revenues of approximately $111.0 million and net income of approximately $11.3 million. As of July 19, 2008, we had sales commitments for approximately 97%, 75% and 34% of our estimated coal production of approximately 8.4 million tons, 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

  Three
Months
Ended
March 31,
2008

  Proven &
Provable
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   0.5   36.3   12,808   1.23   Underground and Surface   32.8/3.5   Truck, Barge, Rail (NS)
Rob Fork Complex (KY)   3.3   0.9   34.5   13,341   1.13   Underground and Surface   25.7/8.8   Truck, Barge, Rail (CSX)
Deane Complex (KY)(1)   n/a   0.1   7.2   13,196   1.55   Underground   7.2/—   Rail (CSX)
Eagle Complex (WV)(1)(3)   n/a   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   0.4   17.1   13,026   2.18   Underground   17.1/—   Truck, Barge, Rail (OHC)
Sands Hill Complex (OH)(1)   <0.1   0.1   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   2.0   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.

2



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 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 twelve months ended March 31, 2008, our nonfatal days lost incidence rate was 19.4% 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

3


      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 200,000 tons of coal for the three months ended March 31, 2008. We also control 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 $232.2 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 July 19, 2008, we had sales commitments for approximately 97%, 75% and 34% of our estimated coal production of approximately 8.4 million tons, 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

4


      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 Financial Performance

        Our consolidated financial statements for the second quarter and year to date as of June 30, 2008 are not yet available. Our expectations with respect to our results for the periods discussed below are based upon management estimates. Our actual results may differ from these estimates.

        We expect to report total revenues that were similar to our first quarter 2008 results. We expect that total coal sales volumes remained basically constant for the second quarter and coal prices per ton increased slightly compared to the first quarter of 2008. We expect that produced tons of coal were slightly less than the tons produced in the first quarter of 2008. Net income for the second quarter ended June 30, 2008 is expected to be less than the first quarter of 2008 as our results were adversely impacted by higher cost of sales excluding depreciation, depletion and amortization, primarily due to cost pressures on operating supplies, diesel fuel and steel prices, and higher maintenance costs at our company-operated surface mines.


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;

5


    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

6



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 17 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 77,332,328 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 6,500,000 shares of our common stock, representing 7.7% of our outstanding common stock to the public in this offering. Rhino Energy Holdings LLC, as the selling stockholder, will sell 3,500,000 shares of our common stock, representing 4.2% of our outstanding common stock, to the public in this offering.

        In connection with the closing of this offering, we will issue approximately 423,913 shares of restricted stock and 54,348 shares of unrestricted stock to management under our long-term incentive plan.

7


        After this offering, Rhino Energy Holdings LLC will own approximately 88.0% and the public will own approximately 11.9% 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

GRAPHIC


(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 Rhino Eastern LLC, a joint venture in which Rhino Energy LLC indirectly owns a 51% membership interest.

8


Post-Offering(1)

Shares Held by the Public   11.9 %
Shares Held by Rhino Energy Holdings LLC   88.0 %
Unrestricted shares held by management   0.1 %
   
 
    100.0 %
   
 

GRAPHIC


(1)
This diagram does not include the 54,348 shares of unrestricted stock or the 423,913 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 Rhino Eastern LLC, a joint venture in which Rhino Energy LLC indirectly owns a 51% membership interest.


Principal Executive Offices

        Our principal executive offices are located at 3120 Wall Street, Suite 310, 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.

9



The Offering

Common stock offered by us   6,500,000 shares.

Common stock offered by the selling stockholder

 

3,500,000 shares.

 

 

5,000,000 shares, if the underwriters exercise their option to purchase additional shares in full.

Total common stock offered to the public

 

10,000,000 shares.

 

 

11,500,000 shares, if the underwriters exercise their option to purchase additional shares in full.

Common stock outstanding after this offering(1)

 

83,886,676 shares.

Use of proceeds

 

We estimate that the net proceeds to us from this offering (based on an assumed initial offering price of $11.50 per share), after deducting the estimated underwriting discount and offering expenses payable by us, will be approximately $67.5 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, leaving approximately $13.8 million of outstanding indebtedness under our credit facility and approximately $24.3 million of total indebtedness, on a pro forma basis as of March 31, 2008. Since then, we have incurred an additional $7.7 million of debt under our credit facility primarily as a result of the acquisition of the Eagle mining complex. Please read "Use of Proceeds" for more information. Certain affiliates of Raymond James & Associates, Inc., RBC Capital Markets Corporation, Wachovia Capital Markets, LLC and PNC Capital Markets LLC are lenders under our credit facility and will receive their respective share of any repayment by us of amounts outstanding under the credit facility from the proceeds of this offering. Please read "Underwriting."

 

 

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.

10



Dividend policy

 

We expect to commence a policy of paying quarterly dividends, initially at an annual rate of between $0.02 and $0.04 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 54,348 unrestricted shares to be issued to management in connection with the closing of this offering but excludes (1) 423,913 restricted shares to be issued to management in connection with the closing of this offering and (2) the number of shares equal to 5.0% 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."

11



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 March 31, 2008 and for the three months ended March 31, 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 March 31, 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 three months ended March 31, 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 77,332,328 shares of our common stock;

    the issuance by us to the public of 6,500,000 shares of our common stock;

    the issuance by us to management of 423,913 shares of restricted stock and 54,348 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 March 31, 2008. The unaudited pro forma consolidated statements of operations data for the year ended December 31, 2007 and the three months ended March 31, 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

12



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

 
 
   
   
   
  Three Months Ended March 31,
 
 
   
  Nine Months
Ended
December 31,
2006

   
   
  Three Months
Ended
March 31,
2008

 
 
  Year Ended
March 31,
2006

  Year Ended
December 31,
2007

  Year Ended
December 31,
2007

 
 
  2007
  2008
 
 
  (in thousands, except per share and per ton data)
 
Statement of Operations Data:                                            
Total revenues   $ 363,959.9   $ 300,838.5   $ 403,451.8   $ 101,551.7   $ 111,002.9   $ 403,451.8   $ 111,002.9  
Costs and expenses:                                            
  Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)     291,444.7     238,189.7     318,520.6     80,212.1     84,896.7     318,520.6     84,896.7  
  Freight and handling costs     6,342.5     2,768.1     4,020.7     426.5     2,387.5     4,020.7     2,387.5  
  Depreciation, depletion and amortization     13,744.3     28,471.2     30,749.8     7,068.6     8,292.4     30,749.8     8,292.4  
  Selling, general and administrative     17,129.4     18,573.0     15,370.3     3,502.5     4,189.0     17,596.9     4,591.0  
  (Gain) loss on sale of assets     (377.2 )   745.8     (944.3 )   (674.4 )   (1,501.3 )   (944.3 )   (1,501.3 )
  (Gain) loss on retirement of advance royalties     (236.9 )   2,994.6     (115.3 )   (125.3 )       (115.3 )    
   
 
 
 
 
 
 
 
    Total costs and expenses     328,046.8     291,742.4     367,601.8     90,410.0     98,264.3     369,828.4     98,666.3  
Income from operations     35,913.1     9,096.1     35,850.0     11,141.7     12,738.6     33,623.4     12,336.6  
Interest and other income (expense):                                            
  Interest expense     (4,976.2 )   (6,498.0 )   (5,579.2 )   (1,662.6 )   (1,320.3 )   (1,826.6 )   (518.8 )
  Interest income     412.1     311.7     316.7     68.6     64.1     316.7     64.1  
  Other—net     490.7     272.2             (219.2 )       (219.2 )
   
 
 
 
 
 
 
 
Total interest and other income (expense)     (4,073.4 )   (5,914.1 )   (5,262.5 )   (1,594.0 )   (1,475.4 )   (1,509.9 )   (673.9 )
   
 
 
 
 
 
 
 
Income before income tax expense and cumulative effect of change in accounting principle     31,839.7     3,182.0     30,587.5     9,547.7     11,263.2     32,113.5     11,662.7  
Income tax expense (benefit)(1)     178.4     124.6     (126.3 )   52.7         7,505.9     2,816.1  
   
 
 
 
 
 
 
 
Net income before cumulative effect of change in accounting principles     31,661.3     3,057.4     30,713.8     9,495.0     11,263.2     24,607.6     8,846.6  
Cumulative effect of change in accounting principle—net of taxes                              
   
 
 
 
 
 
 
 
Net income   $ 31,661.3   $ 3,057.4   $ 30,713.8   $ 9,495.0   $ 11,263.2     24,607.6     8,846.6  
Other comprehensive income (loss):                                            
  Change in actuarial gain/(loss) under SFAS No. 158         (901.0 )   1,489.4             1,489.4      
   
 
 
 
 
 
 
 
Net comprehensive income   $ 31,661.3   $ 2,156.4   $ 32,203.2   $ 9,495.0   $ 11,263.2   $ 26,097.0   $ 8,846.6  
   
 
 
 
 
 
 
 
Pro forma earnings per share, basic                                 $ 0.29   $ 0.11  
Pro forma earnings per share, diluted                                 $ 0.29   $ 0.10  
Pro forma weighted average number of shares outstanding, basic                                   83,886.7     83,886.7  
Pro forma weighted average number of shares outstanding, diluted                                   84,310.6     84,310.6  

Statement of Cash Flows Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Net cash provided by (used in):                                            
  Operating activities   $ 32,892.0   $ 36,859.5   $ 52,492.5   $ 11,550.6   $ 15,587.7   $ 46,386.3   $ 13,171.1  
  Investing activities   $ (34,612.6 ) $ (28,827.6 ) $ (28,097.6 ) $ (2,546.6 ) $ (25,428.4 )            
  Financing activities   $ (1,886.9 ) $ (9,140.8 ) $ (21,191.5 ) $ (7,890.9 ) $ 7,471.6              

13



Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
EBITDA(2)   $ 50,560.2   $ 38,151.2   $ 66,916.5   $ 18,278.9   $ 20,875.9   $ 64,689.9   $ 20,473.9  
Total capital expenditures(3)   $ 66,373.3   $ 42,393.4   $ 39,738.1   $ 5,537.3   $ 26,628.5   $ 39,738.1   $ 26,628.5  

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Cash and cash equivalents   $ 1,488.8   $ 380.0   $ 3,583.4   $ 1,493.1   $ 1,214.3         $ 1,214.3  
Property and equipment, net   $ 180,267.0   $ 197,056.1   $ 211,657.1   $ 197,408.6   $ 245,738.3         $ 245,738.3  
Total assets   $ 246,759.3   $ 248,194.5   $ 275,992.2   $ 253,054.9   $ 319,126.4         $ 319,126.4  
Total liabilities   $ 154,028.4   $ 153,307.1   $ 158,151.7   $ 148,672.5   $ 190,028.3         $ 135,055.7  
Total debt   $ 87,764.1   $ 88,570.5   $ 83,953.7   $ 82,281.2   $ 91,823.6         $ 24,306.1  
Members'/stockholders' equity   $ 92,730.9   $ 94,887.4   $ 117,840.5   $ 104,382.4   $ 129,098.0         $ 184,070.7  

Operating Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Tons of coal sold     7,900.3     6,222.9     8,159.0     2,090.4     2,102.2              
Tons of coal produced     7,950.1     6,182.0     7,056.6     1,824.0     2,018.0              
Coal revenues per ton(4)   $ 44.48   $ 47.31   $ 48.30   $ 47.87   $ 50.05              
Cost of operations per ton(5)   $ 36.89   $ 38.28   $ 39.04   $ 38.37   $ 40.39              

(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.

14


    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

 
   
   
   
  Three Months Ended
March 31,

   
  Three
Months
Ended
March 31,
2008

 
   
  Nine Months
Ended
December 31,
2006

   
   
 
  Year Ended
March 31,
2006

  Year Ended
December 31,
2007

  Year Ended
December 31,
2007

 
  2007
  2008
 
  (in thousands)
Reconciliation of EBITDA to net income:                                          
Net income   $ 31,661.3   $ 3,057.4   $ 30,713.8   $ 9,495.0   $ 11,263.2   $ 24,607.6   $ 8,846.6
Plus:                                          
  Depreciation, depletion and amortization     13,744.3     28,471.2     30,749.8     7,068.6     8,292.4     30,749.8     8,292.4
  Interest expense     4,976.2     6,498.0     5,579.2     1,662.6     1,320.3     1,826.6     518.8
  Income tax expense (benefit)     178.4     124.6     (126.3 )   52.7         7,505.9     2,816.1
   
 
 
 
 
 
 
EBITDA   $ 50,560.2   $ 38,151.2   $ 66,916.5   $ 18,278.9   $ 20,875.9   $ 64,689.9   $ 20,473.9
   
 
 
 
 
 
 

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   $ 11,550.6   $ 15,587.7   $ 46,386.3   $ 13,171.1
Plus:                                          
  Increase in net operating assets     16,447.4     892.7     10,552.7     4,962.2     3,259.8     10,552.7     3,259.8
  Decrease in provision for doubtful accounts         282.8     175.2                 175.2    
  Gain on sale of assets     377.2         944.3     674.4     1,501.3     944.3     1,501.3
  Gain on retirement of advance royalties     236.9         115.3     125.3         115.3    
  Interest expense     4,976.2     6,498.0     5,579.2     1,662.6     1,320.3     1,826.6     518.8
  Income tax expense     178.4     124.6         52.7         7,505.9     2,816.1
Less:                                          
  Accretion on interest-free debt     321.2     255.1     359.8     87.7     141.1     359.8     141.1
  Amortization of advance royalties     2,186.8     1,098.5     699.7     221.3     43.1     699.7     43.1
  Increase in provision for doubtful accounts     354.4                        
  Loss on sale of assets         745.8                    
  Loss on retirement of advance royalties         2,994.6                    
  Income tax benefit             126.3                
  Accretion on asset retirement obligations     1,685.5     1,412.4     1,756.9     439.9     609.0     1,756.9     609.0
   
 
 
 
 
 
 
EBITDA   $ 50,560.2   $ 38,151.2   $ 66,916.5   $ 18,278.9   $ 20,875.9   $ 64,689.9   $ 20,473.9
   
 
 
 
 
 
 

15


(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
 
   
   
   
  Three Months Ended
March 31,

 
   
  Nine Months
Ended
December 31,
2006

   
 
  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   $ 4,023.5   $ 11,707.4
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     4,023.5     26,377.1
Plus:                              
  Additions to property, plant and equipment financed through long-term borrowing     29,887.8     9,692.1     6,964.9     1,513.8     251.4
   
 
 
 
 
Total capital expenditures   $ 66,373.3   $ 42,393.4   $ 39,738.1   $ 5,537.3   $ 26,628.5
   
 
 
 
 
(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.

16



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

17



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

18


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

19


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;

20


    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.

        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.

    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 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."

21


    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.

22


    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 July 19, 2008, we had sales commitments for approximately 97%, 75% and 34% of our estimated coal production of approximately 8.4 million tons, 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 March 31, 2008, 24% of our coal supply contracts expire in 2009 and 9% 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 90% of our coal sales volume for the three months ended March 31, 2008. The majority of our sales of steam coal for the year ended December 31, 2007 and for the three months ended March 31, 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 2006. 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 March 31, 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.

23


        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 three months ended March 31, 2008, we derived 69% 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 25% 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 March 31, 2008, 67% of our coal supply contracts, including over 40 coal supply agreements with our top ten customers, expire in 2008, 24% in 2009 and 9% in 2010 and beyond. 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 three months ended March 31, 2008, 17% and 16%, 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

24


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

25


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 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

26


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.

27


        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 March 31, 2008, we had $21.9 million of letters of credit in place, of which $20.5 million served as collateral for reclamation surety bonds and $1.4 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."

28


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 73,832,328 shares of our outstanding common stock, representing approximately 88.0% of our outstanding common stock (or 72,332,328 shares, representing approximately 86.2% 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 Morgan Stanley & Co. Incorporated and Lehman Brothers Inc., on behalf of the underwriters. However, Morgan Stanley & Co. Incorporated and Lehman Brothers Inc., in their 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. 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 73,832,328 shares of our common stock, representing approximately 88.0% of our outstanding common stock (or 72,332,328 shares, representing approximately 86.2% 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.

29


    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.

30


        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 $9.32 per share.

        The assumed initial public offering price of $11.50 per share exceeds pro forma net tangible book value of $2.18 per share. Stockholders will incur immediate and substantial dilution of $9.32 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 88.0% 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;

31


    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.

32



USE OF PROCEEDS

        We estimate that our net proceeds from this offering, assuming an offering price of $11.50 per share, will be approximately $67.5 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, leaving approximately $13.8 million of outstanding indebtedness under our credit facility and approximately $24.3 million of total indebtedness, on a pro forma basis as of March 31, 2008. Since then, we have incurred an additional $7.7 million of debt under our credit facility primarily as a result of the acquisition of the Eagle mining complex.

        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."

        Certain affiliates of Raymond James & Associates, Inc., RBC Capital Markets Corporation, Wachovia Capital Markets, LLC and PNC Capital Markets LLC are lenders under our credit facility and will receive their respective share of any repayment by us of amounts outstanding under the credit facility from the proceeds of this offering. Please read "Underwriting."

        A $1.00 increase or decrease in the assumed initial public offering price of $11.50 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 $6.0 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 $12.50 per share, would increase net proceeds to us from this offering by approximately $17.7 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 $10.50 per share, would decrease the net proceeds to us from this offering by approximately $15.8 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.

33



DIVIDEND POLICY

        We expect to commence a policy of paying quarterly dividends, initially at an annual rate of between $0.02 and $0.04 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.

34



CAPITALIZATION

        The following table shows our capitalization as of March 31, 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 March 31, 2008
 
  Actual
  Pro Forma(3)
 
  (in thousands)
Cash   $ 1,214.3   $ 1,214.3
Debt:            
  Credit facility(1)   $ 81,250.0   $ 13,732.5
  Other debt     10,573.6     10,573.6
   
 
    Total debt     91,823.6     24,306.1
Members' equity     129,098.0      
Stockholder' equity:            
  Common stock, par value $0.01 per share, 500,000,000 shares authorized, 83,886,676 shares issued and outstanding(2)           838.9
  Additional paid-in capital         98,007.3
  Retained earnings         84,636.1
  Accumulated other comprehensive income         588.4
   
 
      Total members'/stockholders' equity     129,098.0     184,070.7
   
 
      Total capitalization   $ 220,921.6   $ 208,376.8
   
 

(1)
Since March 31, 2008, we have incurred an additional $7.7 million of debt under our credit facility primarily as a result of the acquisition of the Eagle mining complex.

(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.

(3)
Each $1.00 increase or decrease in the assumed public offering price of $11.50 per share would increase or decrease, respectively, each of total stockholders' equity and total capitalization by approximately $6.0 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 $12.50 per share, would increase total stockholders' equity and total capitalization by approximately $17.7 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 $10.50 per share, would decrease total stockholders' equity and total capitalization by approximately $15.8 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.

35



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 $11.50 per share, on a pro forma basis as of March 31, 2008, after giving effect to the offering of common stock, our net tangible book value was approximately $182.8 million, or $2.18 per share. The pro forma net book tangible value excludes $1.3 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         $ 11.50
Net tangible book value per share before the offering(1)   $ 1.65      
Increase in net tangible book value per share attributable to purchasers in the offering     0.53      
   
     
Less: Pro forma net tangible book value per share after the offering(2)           2.18
         
Immediate dilution in net tangible book value per share to purchasers in the offering(3)         $ 9.32
         

(1)
Determined by dividing the net tangible book value of the contributed assets and liabilities by the aggregate of 77,332,328 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 $11.50 per share would increase or decrease, respectively, our pro forma net tangible book value by approximately $6.0 million, or approximately $0.07 per share, and dilution per share to investors in this offering by approximately $0.93 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 $12.50 per share, would result in a pro forma net tangible book value of approximately $200.4 million, or $2.36 per share, and dilution per share to investors in this offering would be $10.14 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 $10.50 per share, would result in an pro forma net tangible book value of approximately $166.9 million, or $2.01 per share, and dilution per share to investors in this offering would be $8.49 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.

36


 
  Shares Acquired(1)
  Total Consideration
   
 
  Average Price
Per Share

 
  Number
  Percent
  Amount
  Percent
Rhino Energy Holdings LLC(2)   77,332,328   92.2 %   129,098,020   63.3 % $ 1.67
New investors   6,500,000   7.8 %   74,750,000   36.7 % $ 11.50
   
 
 
 
 
Total   83,832,328   100 % $ 203,848,020   100 % $ 2.43
   
 
 
 
 

(1)
The number of shares disclosed for Rhino Energy Holdings LLC includes the 3,500,000 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 423,913 shares of restricted stock and 54,348 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 March 31, 2008.

37



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 March 31, 2008 and for the three months ended March 31, 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 March 31, 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 three months ended March 31, 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 77,332,328 shares of our common stock;

    the issuance by us to the public of 6,500,000 shares of our common stock;

    the issuance by us to management of 423,913 shares of restricted stock and 54,348 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 March 31, 2008. The unaudited pro forma consolidated statements of operations data for the year ended December 31, 2007 and the three months ended March 31, 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.

38


 
  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,
   
   
 
 
  Three Months
Ended
March 31,
2004

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

   
   
   
 
 
  Year Ended
December 31,
2007

  Year Ended
December 31,
2007

  Three Months
Ended March 31,
2008

 
 
  2005
  2006
  2007
  2008
 
 
  (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   $ 101,551.7   $ 111,002.9   $ 403,451.8   $ 111,002.9  
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     80,212.1     84,896.7     318,520.6     84,896.7  
  Freight and handling costs     578.4     570.1     7,245.3     6,342.5     2,768.1     4,020.7     426.5     2,387.5     4,020.7     2,387.5  
  Depreciation, depletion and amortization     1,715.8     698.3     4,583.4     13,744.3     28,471.2     30,749.8     7,068.6     8,292.4     30,749.8     8,292.4  
  Selling, general and administrative     4,735.7     1,191.0     12,877.5     17,129.4     18,573.0     15,370.3     3,502.5     4,189.0     17,596.9     4,591.0  
  (Gain) loss on sale of assets     (109.9 )   48.3     505.7     (377.2 )   745.8     (944.3 )   (674.4 )   (1,501.3 )   (944.3 )   (1,501.3 )
  (Gain) loss on retirement of advance royalties                 (236.9 )   2,994.6     (115.3 )   (125.3 )       (115.3 )    
   
 
 
 
 
 
 
 
 
 
 
    Total costs and expenses     32,761.3     16,564.1     245,840.6     328,046.8     291,742.4     367,601.8     90,410.0     98,264.3     369,828.4     98,666.3  
   
 
 
 
 
 
 
 
 
 
 
Income (loss) from operations     1,140.1     (339.4 )   34,137.2     35,913.1     9,096.1     35,850.0     11,141.7     12,738.6     33,623.4     12,336.6  
Interest and other income (expense):                                                              
  Interest expense     (565.0 )   (287.9 )   (3,454.7 )   (4,976.2 )   (6,498.0 )   (5,579.2 )   (1,662.6 )   (1,320.3 )   (1,826.6 )   (518.8 )
  Interest income     30.2     13.1     442.3     412.1     311.7     316.7     68.6     64.1     316.7     64.1  
  Other—net     109.8     (6.7 )   (1,296.4 )   490.7     272.2             (219.2 )       (219.2 )
   
 
 
 
 
 
 
 
 
 
 
Total interest and other income (expense)     (425.0 )   (281.5 )   (4,308.8 )   (4,073.4 )   (5,914.1 )   (5,262.5 )   (1,594.0 )   (1,475.4 )   (1,509.9 )   (673.9 )
   
 
 
 
 
 
 
 
 
 
 
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     9,547.7     11,263.2     32,113.5     11,662.7  
Income tax expense (benefit)(1)             73.8     178.4     124.6     (126.3 )   52.7         7,505.9     2,816.1  
   
 
 
 
 
 
 
 
 
 
 
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     9,495.0     11,263.2     24,607.6     8,846.6  
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   $ 9,495.0   $ 11,263.2   $ 24,607.6   $ 8,846.6  
Other comprehensive income (loss):                                                              
  Change in actuarial gain/(loss) under SFAS No. 158                     (901.0 )   1,489.4             1,489.4      
   
 
 
 
 
 
 
 
 
 
 
Net comprehensive income (loss)   $ 715.1   $ (620.9 ) $ 28,098.2   $ 31,661.3   $ 2,156.4   $ 32,203.2   $ 9,495.0   $ 11,263.2   $ 26,097.0   $ 8,846.6  
   
 
 
 
 
 
 
 
 
 
 

39


 
  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,
   
   
 
  Three Months
Ended
March 31,
2004

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

   
   
  Three Months
Ended
March 31,
2008

 
  Year Ended
December 31,
2007

  Year Ended
December 31,
2007

 
  2005
  2006
  2007
  2008
 
  (in thousands, except per share and per ton data)
Pro forma earnings per share, basic                                                   $ 0.29   $ 0.11
Pro forma earnings per share, diluted                                                   $ 0.29   $ 0.10
Pro forma weighted average number of shares outstanding, basic                                                     83,886.7     83,886.7
Pro forma weighted average number of shares outstanding, diluted                                                     84,310.6     84,310.6
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   $ 11,550.6   $ 15,587.7   $ 46,386.3   $ 13,171.1
  Investing activities   $ (20,796.1 ) $ (13,406.2 ) $ (47,182.2 ) $ (34,612.6 ) $ (28,827.6 ) $ (28,097.6 ) $ (2,546.6 ) $ (25,428.4 )          
  Financing activities   $ 21,368.0   $ 14,485.1   $ 19,132.5   $ (1,886.9 ) $ (9,140.8 ) $ (21,191.5 ) $ (7,890.9 ) $ 7,471.6            
Other Financial Data:                                                            
EBITDA(2)   $ 2,995.9   $ 365.3   $ 36,210.0   $ 50,560.2   $ 38,151.2   $ 66,916.5   $ 18,278.9   $ 20,875.9   $ 64,689.9   $ 20,473.9
Total capital expenditures(3)   $ 17,048.1   $ 14,528.8   $ 61,905.0   $ 66,373.3   $ 42,393.4   $ 39,738.1   $ 5,537.3   $ 26,628.5   $ 39,738.1   $ 26,628.5
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   $ 1,493.1   $ 1,214.3         $ 1,214.3
Property and equipment, net   $ 26,805.5   $ 42,818.8   $ 128,407.4   $ 180,267.0   $ 197,056.1   $ 211,657.1   $ 197,408.6   $ 245,738.3         $ 245,738.3
Total assets   $ 41,163.6   $ 59,422.1   $ 181,138.4   $ 246,759.3   $ 248,194.5   $ 275,992.2   $ 253,054.9   $ 319,126.4         $ 319,126.4
Total liabilities   $ 24,568.2   $ 43,644.6   $ 120,068.7   $ 154,028.4   $ 153,307.1   $ 158,151.7   $ 148,672.5   $ 190,028.3         $ 135,055.7
Total debt   $ 16,597.1   $ 31,279.2   $ 61,941.9   $ 87,764.1   $ 88,570.5   $ 83,953.7   $ 82,281.2   $ 91,823.6         $ 24,306.1
Members'/stockholders' equity   $ 16,595.4   $ 15,777.5   $ 61,069.6   $ 92,730.9   $ 94,887.4   $ 117,840.5   $ 104,382.4   $ 129,098.0         $ 184,070.7
Operating Data:                                                            
Tons of coal sold     1,058.6     455.4     7,051.6     7,900.3     6,222.9     8,159.0     2,090.4     2,102.2            
Tons of coal produced     1,122.1     511.5     7,201.6     7,950.1     6,182.0     7,056.6     1,824.0     2,018.0            
Coal revenues per ton(4)   $ 31.25   $ 35.42   $ 38.63   $ 44.48   $ 47.31   $ 48.30   $ 47.87   $ 50.05            
Cost of operations per ton(5)   $ 24.96   $ 32.12   $ 32.32   $ 36.89   $ 38.28   $ 39.04   $ 38.37   $ 40.39            

(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.

40


    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

 
  Period from
April 30, 2003
(date of
inception)
through
December 31,
2003

   
   
   
   
   
   
   
   
   
 
   
   
   
   
   
  Three Months Ended March 31,
   
   
 
  Three Months
Ended
March 31,
2004

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

   
   
  Three Months
Ended
March 31,
2008

 
  Year Ended
December 31,
2007

  Year Ended
December 31,
2007

 
  2005
  2006
  2007
  2008
 
  (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   $ 9,495.0   $ 11,263.2   $ 24,607.6   $ 8,846.6
Plus:                                                            
  Depreciation, depletion and amortization     1,715.8     698.3     4,583.4     13,744.3     28,471.2     30,749.8     7,068.6     8,292.4     30,749.8     8,292.4
  Interest expense     565.0     287.9     3,454.7     4,976.2     6,498.0     5,579.2     1,662.6     1,320.3     1,826.6     518.8
  Income tax expense (benefit)             73.8     178.4     124.6     (126.3 )   52.7         7,505.9     2,816.1
   
 
 
 
 
 
 
 
 
 
EBITDA   $ 2,995.9   $ 365.3   $ 36,210.1   $ 50,560.2   $ 38,151.2   $ 66,916.5   $ 18,278.9   $ 20,875.9   $ 64,689.9   $ 20,473.9
   
 
 
 
 
 
 
 
 
 
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   $ 11,550.6   $ 15,587.7   $ 46,386.3   $ 13,171.1
Plus:                                                            
  Increase in net operating assets     2,889.2     1,676.9     3,176.6     16,447.4     892.7     10,552.7     4,962.2     3,259.8     10,552.7     3,259.8
  Decrease in provision for doubtful accounts                     282.8     175.2                 175.2    
  Gain on sale of assets                 377.2         944.3     674.4     1,501.3     944.3     1,501.3
  Gain on retirement of advance royalties     109.9             236.9         115.3     125.3         115.3    
  Interest expense     565.0     287.9     3,454.7     4,976.2     6,498.0     5,579.2     1,662.6     1,320.3     1,826.6     518.8
  Income tax expense             73.8     178.4     124.6         52.7         7,505.9     2,816.1
Less:                                                            
  Accretion on interest-free debt             473.2     321.2     255.1     359.8     87.7     141.1     359.8     141.1
  Amortization of advance royalties         406.0     1,231.5     2,186.8     1,098.5     699.7     221.3     43.1     699.7     43.1
  Increase in provision for doubtful accounts             103.6     354.4                        
  Loss on sale of assets         48.3     505.7         745.8                    
  Loss on retirement of advance royalties                     2,994.6                    
  Income tax benefit                         126.3                
  Accretion on asset retirement obligations         66.1     1,323.6     1,685.5     1,412.4     1,756.9     439.9     609.0     1,756.9     609.0
   
 
 
 
 
 
 
 
 
 
EBITDA   $ 2,995.9   $ 365.3   $ 36,210.1   $ 50,560.2   $ 38,151.2   $ 66,916.5   $ 18,278.9   $ 20,875.9   $ 64,689.9   $ 20,473.9
   
 
 
 
 
 
 
 
 
 

41


(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

   
   
   
   
  Three Months Ended March 31,
 
  Years Ended March 31,
  Nine Months
Ended
December 31,
2006

   
 
  Year Ended
December 31,
2007

 
  2005
  2006
  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   $ 4,023.5   $ 11,707.4
  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     4,023.5     26,377.1
  Plus:                                                
    Additions to property, plant and equipment financed through long-term borrowing             13,928.9     29,887.8     9,692.1     6,964.9     1,513.8     251.4
   
 
 
 
 
 
 
 
  Total capital expenditures   $ 17,048.1   $ 14,528.8   $ 61,905.0   $ 66,373.3   $ 42,393.4   $ 39,738.1   $ 5,537.3   $ 26,628.5
   
 
 
 
 
 
 
 
(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.

42



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

        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 three months ended March 31, 2008, we produced approximately 2.0 million tons of coal and sold approximately 2.1 million tons of coal. 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 three months ended March 31, 2008, we generated revenues of approximately $111.0 million and net income of approximately $11.3 million. As of July 19, 2008, we had sales commitments for approximately 97%, 75% and 34% of our estimated coal production of approximately 8.4 million tons, 8.7 million tons and 9.2 million tons for the years ending December 31, 2008, 2009 and 2010, respectively.

        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. Recently, 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. In May 2008, we entered into a joint venture that acquired the Eagle mining complex located in Central Appalachia and to which we contributed our lease of the nearby Bolt field, which we entered into in February 2008. These recent acquisitions collectively added approximately 39.7 million tons of proven and probable coal reserves and approximately 28.7 million tons of non-reserve coal deposits. We expect to produce approximately 2.1 million tons of coal in 2009 from our recently acquired mining complexes, including approximately 0.3 million tons of metallurgical coal. 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.

        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 $232.2 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.

        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

43



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 three segments: Central Appalachia, Northern Appalachia 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 March 31, 2008, together included nine underground mines, seven surface mines and three preparation and/or loadout facilities in eastern Kentucky and southern West Virginia. Our Northern Appalachia segment consists of the Hopedale mining complex located in southern Ohio which, as of March 31, 2008, included one underground mine and one preparation plant and loadout facility. For the year ended December 31, 2007 and the three months ended March 31, 2008, our Other segment included the results of our Colorado operations, the Sands Hill mining complex located in southern Ohio (which we acquired in December 2007), which as of March 31, 2008 included two surface mines and a preparation plant, 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

44


      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 June 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:

    Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 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.

45


        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 three months ended March 31, 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 March 31, 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 Legal Structure

        Our operations are currently conducted by a limited liability company, Rhino Energy LLC. Immediately 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.

    Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

        Summary.    For both the three months ended March 31, 2007 and 2008, we sold 2.1 million tons of coal. Our total revenues increased by $9.5 million to $111.0 million, or by 9.3%, for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007, primarily due to higher coal revenues, which increased by $5.1 million, to $105.2 million. Our net income and EBITDA also increased for the three months ended March 31, 2008 as compared to the same period in 2007. Net

46


income increased to $11.3 million from $9.5 million and EBITDA increased to $20.9 million from $18.3 million. Higher revenues primarily contributed to the increases in net income and EBITDA.

        Tons Sold.    The following table presents tons of coal sold by reportable segment for the three months ended March 31, 2007 and 2008:

 
  Three Months Ended March 31, 2007
  Three Months Ended March 31, 2008
   
   
 
 
  Increase/(Decrease)
 
Segment

 
  Tons
  %*
 
 
  (in millions, except %)

 
Central Appalachia   1.7   1.5   (0.2 ) (11.8 )%
Northern Appalachia   0.3   0.4   0.1   23.9 %
Other   0.1   0.2   0.1   182.7 %
   
 
 
     
Total   2.1   2.1      
   
 
 
     

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

        Tons of coal sold for the three months ended March 31, 2008 were the same as for the three months ended March 31, 2007. We sold 0.2 million more tons of coal for the three months ended March 31, 2008 than for the three months ended March 31, 2007 from our recently acquired Sands Hill and Deane mining complexes, offset by 0.2 million fewer tons sold from our Tug River mining complex. Tons of coal purchased increased by 0.1 million tons of coal, to 0.2 million tons of coal for the three months ended March 31, 2008 from 0.1 million tons of coal for the three months ended March 31, 2007.

47


        Revenues.    The following table presents revenues and coal revenues per ton by reportable segment for the three months ended March 31, 2007 and 2008:

 
  Three Months Ended March 31, 2007
  Three Months Ended March 31, 2008
   
   
 
 
  Increase/(Decrease)
 
Segment

 
  Dollars
  %*
 
 
  (in millions, except per ton data and %)

 
Central Appalachia                        
  Coal revenues   $ 86.4   $ 82.0   $ (4.4 ) (5.0 )%
  Freight and handling revenues         0.6     0.6    
  Other revenues     0.2     0.5     0.3   131.9 %
   
 
 
     
  Total revenues   $ 86.6   $ 83.1   $ (3.5 ) (4.0 )%
   
 
 
     
  Coal revenues per ton   $ 50.73   $ 54.66   $ 3.93   7.7 %
Northern Appalachia                        
  Coal revenues   $ 11.4   $ 15.1   $ 3.7   32.6 %
  Freight and handling revenues         0.5     0.5    
  Other revenues     0.8     0.9     0.1   11.6 %
   
 
 
     
  Total revenues   $ 12.2   $ 16.5   $ 4.3   35.4 %
   
 
 
     
  Coal revenues per ton   $ 36.59   $ 39.15   $ 2.56   7.0 %
Other                        
  Coal revenues   $ 2.3   $ 8.0   $ 5.7   253.4 %
  Freight and handling revenues     0.4     1.4     1.0   213.7 %
  Other revenues         1.9     1.9    
   
 
 
     
  Total revenues   $ 2.7   $ 11.3   $ 8.6   316.1 %
   
 
 
     
  Coal revenues per ton   $ 29.88   $ 37.35   $ 7.47   25.0 %
Total                        
  Coal revenues   $ 100.1   $ 105.2   $ 5.1   8.5 %
  Freight and handling revenues     0.4     2.5     2.1   465.1 %
  Other revenues     1.1     3.3     2.2   (3.6 )%
   
 
 
     
  Total revenues   $ 101.6   $ 111.0   $ 9.5   9.3 %
   
 
 
     
  Coal revenues per ton   $ 47.87   $ 50.05   $ 2.18   4.6 %

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

        Our total revenues for the three months ended March 31, 2008 were $111.0 million, an increase of $9.5 million, or 9.3%, as compared to the same period in 2007, primarily due to an increase in coal revenues to $105.2 million from $100.1 million. This increase in coal revenues was due to an increase in coal revenues per ton sold of coal of $2.18, or 4.6%, to $50.05 for the three months ended March 31, 2008 from $47.87 for the same period in 2007, as a result of contract price per ton increases and increased sales of metallurgical coal in our Central Appalachia segment in the three months ended March 31, 2008.

        For our Central Appalachia segment, total revenues decreased slightly for the three months ended March 31, 2008 to $83.1 million from $86.6 million for the same period in 2007, primarily due to a decrease in coal revenues of $4.4 million, offset by increases in freight and handling revenues of $0.6 million and other revenues of $0.3 million. We sold 0.2 million fewer tons for the three months ended March 31, 2008 as compared to the same period in 2007 but generated higher coal revenues per ton of $54.66 for the three months ended March 31, 2008, an increase of $3.93 per ton, or 7.7%, primarily due to overall higher contract prices and strong coal prices. In addition, we sold approximately 0.2 million tons of metallurgical coal at an average price of $78.76 per ton during the

48



three months ended March 31, 2008 compared to approximately 5,000 tons at $65.00 per ton for the three months ended March 31, 2007.

        For our Northern Appalachia segment, total revenues increased by $4.3 million, to $16.5 million for the three months ended March 31, 2008 from $12.2 million for the three months ended March 31, 2007, primarily due to increased coal revenues. Additionally, freight and handling revenues increased by $0.5 million and other revenues increased by $0.1 million for the three months ended March 31, 2008 as compared to the same period in 2007. Coal revenues increased by $3.7 million, or 32.6%, to $15.1 million for the three months ended March 31, 2008, as compared to the same period in 2007 due to increases in tons of coal sold and coal revenues per ton. We sold 0.1 million more tons of coal for the three months ended March 31, 2008 as compared to the same period in 2007 and average coal revenues per ton increased by 7.0%, to $39.15 for the three months ended March 31, 2008 from $36.59 for the three months ended March 31, 2007. The increase in coal revenues per ton was due to a combination of overall higher contract prices and increased coal quality premiums.

        For our Other segment, total revenues increased to $11.3 million for the three months ended March 31, 2008 from $2.7 million for the three months ended March 31, 2007, an increase of $8.6 million, primarily due to an increase in coal revenues of $5.7 million. Freight and handling revenues and other revenues also increased by $1.0 million and $1.9 million, respectively, for the three months ended March 31, 2008 as compared to the same period in 2007. The increase in coal revenues was primarily due to the addition of our Sands Hill mining complex, which we acquired in December 2007 and which generated $5.8 million in coal revenues for the three months ended March 31, 2008. Coal revenues from our Colorado operation declined by $0.1 million for the three months ended March 31, 2008 as compared to the same period in 2007 because of lower production and tons of coal sold. Other revenues increased to $1.9 million for the three months ended March 31, 2008 from none in 2007, primarily due to revenues of $1.8 million from limestone business incidental to our Sands Hill coal mining operation. Coal revenues per ton for the three months ended March 31, 2008 also increased, to $37.35 from $29.88, primarily due to higher coal revenues per ton for our Sands Hill operation, as well as slightly higher contract prices for our Colorado operation for the three months ended March 31, 2008 as compared to the same period in 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 three months ended March 31, 2007 and 2008:

 
  Three Months Ended March 31, 2007
  Three Months Ended March 31, 2008
   
   
 
 
  Increase/(Decrease)
 
 
  Dollars
  %*
 
 
  (in millions, except per ton data and %)

 
Central Appalachia                        
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   $ 69.5   $ 65.8   $ (3.7 ) (5.4 )%
Freight and handling costs         0.7     0.7    
Depreciation, depletion and amortization     5.8     5.8       0.3 %
Selling, general and administrative     2.5     2.7     0.2   8.3 %
Cost of operations per ton   $ 40.82   $ 43.79   $ 2.97   7.3 %
Cost of operations per ton produced   $ 41.03   $ 43.38   $ 2.35   5.7 %

49



Northern Appalachia

 

 

 

 

 

 

 

 

 

 

 

 
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   $ 8.4   $ 9.9   $ 1.5   18.4 %
Freight and handling costs         0.5     0.5    
Depreciation, depletion and amortization     1.0     1.2     0.2   21.6 %
Selling, general and administrative     0.7     0.8     0.1   22.2 %
Cost of operations per ton   $ 26.97   $ 25.76   $ (1.21 ) (4.5 )%
Cost of operations per ton produced   $ 26.97   $ 25.76   $ (1.21 ) (4.5 )%

Other

 

 

 

 

 

 

 

 

 

 

 

 
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   $ 2.3   $ 9.2   $ 6.9   301.1 %
Freight and handling costs     0.4     1.1     0.7   162.6 %
Depreciation, depletion and amortization     0.3     1.3     1.0   304.7 %
Selling, general and administrative     0.3     0.6     0.3   101.5 %
Cost of operations per ton   $ 30.24   $ 42.89   $ 12.65   41.9 %
Cost of operations per ton produced   $ 30.24   $ 42.89   $ 12.65   41.9 %

Total

 

 

 

 

 

 

 

 

 

 

 

 
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   $ 80.2   $ 84.9   $ 4.7   5.8 %
Freight and handling costs     0.4     2.4     2.0   459.8 %
Depreciation, depletion and amortization     7.1     8.3     1.2   17.3 %
Selling, general and administrative     3.5     4.2     0.7   19.6 %
Cost of operations per ton   $ 38.37   $ 40.39   $ 2.02   5.2 %
Cost of operations per ton produced   $ 38.28   $ 39.87   $ 1.59   4.1 %

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

        Cost of Operations.    For the three months ended March 31, 2008, our cost of operations increased by $4.7 million, or 5.8%, to $84.9 million, from $80.2 million for the same period in 2007. On a per ton basis, our cost of operations per ton increased to $40.39 for the three months ended March 31, 2008 from $38.37 for the three months ended March 31, 2007, an increase of $2.02, or 5.2%, similar to cost of operations per ton produced. Labor, operating supplies and maintenance costs per ton increased by $1.63, $1.28 and $1.23, respectively, while coal transportation, employee benefits, contracted services and rental/lease expenses decreased per ton by $1.48, $1.10, $0.51 and $0.34, respectively.

        For our Central Appalachia segment, cost of operations decreased by $3.7 million, to $65.8 million for the three months ended March 31, 2008 from $69.5 million for the three months ended March 31, 2007, primarily due to the sale of 0.2 million fewer tons of coal for the three months ended March 31, 2008. Total benefits cost also decreased by $2.9 million as a result of a decrease in workers' compensation. Transportation cost decreased by $1.3 million as we produced and trucked fewer tons of coal to our preparation plants. Cost of operations per ton for the segment increased to $43.79 for the three months ended March 31, 2008, an increase of $2.97, or 7.3%, from $40.82 for the three months ended March 31, 2007, similar to cost of operations per ton produced. Total benefits, operating supplies and outside services costs per ton decreased by $1.60, $0.07 and $0.13, respectively, while labor, maintenance and utilities costs per ton increased by $0.91, $0.98 and $0.15, respectively.

50


        For our Northern Appalachia segment, cost of operations for the three months ended March 31, 2008 increased by $1.5 million, to $9.9 million, as compared to the same period in 2007, due to the sale of approximately 0.1 million more tons of coal during the three months ended March 31, 2008 than for that same period in 2007. For the three months ended March 31, 2008, labor and benefits costs increased by $0.4 million as a result of more overtime production. For the three months ended March 31, 2008, operating supplies, outside services and maintenance costs also increased by $0.4 million and rental/lease expenses decreased by $0.1 million, due to higher material costs and the purchase of additional equipment instead of leasing such equipment. Cost of operations per ton and cost of operations per ton produced decreased to $25.76 for the three months ended March 31, 2008 from $26.97 for the same period in 2007, a decrease of 4.5%, due to the additional 0.1 million tons of coal sold for the three months ended March 31, 2008, and greater efficiencies from the operation of only one mine for the three month period in 2008 instead of two mines for the same period in 2007. Labor and benefits costs per ton of coal sold decreased by $0.95 and $0.62, respectively, as we sold more tons of coal for the three months ended March 31, 2008 as compared to the same period in 2007. Transportation and utilities costs per ton also decreased by $0.78 and $0.40, respectively, for the three months ended March 31, 2008 compared to the same period in 2007. Offsetting these decreases were increases in outside services cost per ton of $0.73 and in maintenance cost per ton of $0.69, due to the purchase of more equipment instead of leasing such equipment.

        For our Other segment, cost of operations increased to $9.2 million for the three months ended March 31, 2008 from $2.3 million for the three months ended March 31, 2007, an increase of $6.9 million, primarily due to the addition of our Sands Hill operations, which we acquired in December 2007 and which added $6.9 million to the cost of operations. Cost of operations for our Colorado operation decreased slightly, by $0.1 million, for the three months ended March 31, 2008 as compared to the same period in 2007.

        Freight and Handling.    For the three months ended March 31, 2008, freight and handling cost was $2.4 million as compared to $0.4 million for the same period in 2007. The increase was due to the shipment and sale of more coal and associated freight and handling costs. In our Central Appalachia segment, we had more coal sales that incurred freight and handling costs, totaling $0.7 million more for the three months ended March 31, 2008 than for the same period in 2007. Our Sands Hill operation also added $0.5 million to freight and handling cost in our Other segment. Additionally, in June 2007, we entered into a long-term sales contract to deliver coal to a customer from our Hopedale operation that resulted in an additional $0.5 million in freight and handling costs for the three months ended March 31, 2008. The cost for freight and handling at our Colorado operation also increased by $0.2 million for the three months ended March 31, 2008 as compared to the same period 2007 due to an increase in prices in mid-2007.

        Depreciation, Depletion and Amortization.    For the three months ended March, 31, 2008, depreciation, depletion and amortization ("DD&A") expense was $8.3 million, as compared to $7.1 million for the same period in 2007, primarily due to higher asset depreciation cost of $1.2 million resulting from the purchase of additional equipment for our Sands Hill and Hopedale operations. Depletion increased slightly, by less than $0.1 million, due to the production of 0.2 million more tons of coal for the three months ended March 31, 2008 as compared to the same period in 2007.

51


        Selling, General and Administrative.    For the three months ended March 31, 2008, total selling, general and administrative ("SG&A") expense was $4.2 million, as compared to $3.5 million for the same period in 2007, an increase of $0.7 million, or 19.6%. Our Sands Hill and Deane acquisitions added $0.3 million to our SG&A expense. We also incurred $0.2 million more in other SG&A expenses, including operation overhead costs, in three months ended March 31, 2008.

        Interest Expense.    For the three months ended March, 31, 2008, our interest expense was $1.3 million, as compared to $1.7 million for the same period in 2007 due to less average debt outstanding. We experienced lower interest rates due to our credit facility having a variable interest rate which is primarily driven by LIBOR rates. On average, our interest rate was 2.1% lower for our credit facility for the three months ended March 31, 2008 than for the same period in 2007.

        Income Tax Expense/Benefit.    For the three months ended March 31, 2008, we incurred no state or local income taxes, as compared to $50,000 for the three months ended March 31, 2007.

        Net Income/Loss.    The following table presents net income/loss by reportable segment for the three months ended March 31, 2007 and 2008:

 
  Three Months Ended March 31, 2007
  Three Months Ended March 31, 2008
   
   
 
 
  Increase/(Decrease)
 
Segment

 
  Dollars
  %*
 
 
  (in millions, except %)

 
Central Appalachia   $ 7.8   $ 8.2   $ 0.4   5.4 %
Northern Appalachia     1.6     3.6     2.0   121.2 %
Other     0.1     (0.5 )   (0.6 ) n/a  
   
 
 
     
Total   $ 9.5   $ 11.3   $ 1.8   18.6 %
   
 
 
     

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

        For the three months ended March 31, 2008, our net income increased by $1.8 million, or 18.6%, as compared to the same period in 2007, to $11.3 million from $9.5 million, as a result of increased revenue that was not offset by increases in cost of operations. Purchasing coal, instead of producing the purchased tons of coal, had the effect of decreasing total net income by approximately $1.1 million and $0.2 million for the three months ended March 31, 2008 and March 31, 2007, respectively, for the entire company. Net income for our Central Appalachia segment increased by $0.4 million for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007, despite lower tons of coal sold and lower revenues, as a result of higher coal revenues per ton that offset an increase in cost of operations per ton. Purchasing coal, rather than producing the purchased tons of coal, had the effect of decreasing net income by $0.6 million and increasing net income by $0.4 million for our Central Appalachia segment for the three months ended March 31, 2008 and March 31, 2007, respectively. Net income for our Northern Appalachia segment more than doubled, to $3.6 million for the three months ended March 31, 2008 from $1.6 million for the same period in 2007, due to more tons of coal sold and higher coal revenues per ton. Additionally, cost of operations per ton decreased in that segment due to greater efficiencies from the operation of only one mine for the three months ended March 31, 2008 instead of two mines for the same period in 2007. For our Other segment, we incurred a net loss of $0.5 million for the three months ended March 31, 2008 as compared to net income of $0.1 million for the same period in 2007, primarily due to a net loss at our Sands Hill operation of $1.2 million for the three months ended March 31, 2008, offset by net income of $0.7 million from sales of limestone for the same period.

52


        EBITDA.    The following table presents EBITDA by reportable segment for the three months ended March 31, 2007 and 2008:

 
  Three Months Ended March 31, 2007
  Three Months Ended March 31, 2008
   
   
 
 
  Increase/(Decrease)
 
Segment

 
  Dollars
  %*
 
 
  (in millions, except %)

 
Central Appalachia   $ 14.9   $ 14.9   $    
Northern Appalachia     2.8     4.9     2.1   74.7 %
Other     0.6     1.1     0.5   96.9 %
   
 
 
     
  Total   $ 18.3   $ 20.9   $ 2.6   14.2 %
   
 
 
     

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

        For the three months ended March 31, 2008, our EBITDA increased by $2.6 million, or 14.2%, to $20.9 million from $18.3 million for the same period in 2007. This increase was primarily a result of higher revenues and higher coal revenues per ton, which were not offset by increases in cost of operations. In addition, DD&A expense increased by $1.2 million and our interest expense declined by $0.3 million. EBITDA for our Central Appalachia segment remained stable at $14.9 million, with the increase in revenues offset by an increase in interest expense. EBITDA for our Northern Appalachia segment increased more than 74%, to $4.9 million from $2.8 million, for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007, primarily as a result of an increase in revenues of $4.3 million, due to more tons of coal sold, higher coal revenues per ton and lower cost of operations per ton. For our Other segment, EBITDA doubled, to $1.1 million for the three months ended March 31, 2008 from $0.6 million for the same three months in 2007 primarily due to the addition of limestone sales at our recently acquired Sands Hill operation.

    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.

53



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.

    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,

54


    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 net income 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)

 
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 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

 
  Tons
  %*
 
 
  (in millions, except %)

 
Central Appalachia   6.5   6.6   0.1   1.6 %
Northern Appalachia   1.6   1.3   (0.3 ) (18.8 )%
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 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

55



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

 
  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 %
Other                        
  Coal revenues   $ 7.6   $ 8.0   $ 0.4   5.6 %
  Freight and handling revenues     1.6     1.7     0.1   6.4 %
  Other revenues     0.1     0.8     0.7   842.1 %
   
 
 
     
  Total revenues   $ 9.3   $ 10.5   $ 1.2   13.2 %
   
 
 
     
  Coal revenues per ton   $ 28.96   $ 30.26   $ 1.30   4.5 %
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 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

56


for coal sold that was above the specification under the supply contracts. For our Other segment, coal revenues increased by $0.4 million, or 5.6%, to $8.0 million from $7.6 million for the year ended December 31, 2006. Coal revenues per ton for our Other segment were $30.26 for the year ended December 31, 2007, an increase of $1.30, or 4.5%, 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

 
  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   $ 1.70   7.0 %
Cost of operations per ton produced   $ 24.39   $ 26.08   $ 1.70   7.0 %
Other                        
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   $ 11.1   $ 11.6   $ 0.5   4.5 %
Freight and handling costs     1.6     1.7     0.1   2.2 %
Depreciation, depletion and amortization     0.9     2.1     1.2   122.8 %
Selling, general and administrative     1.0     1.2     0.2   19.8 %
Cost of operations per ton   $ 42.57   $ 44.04   $ 1.47   3.4 %
Cost of operations per ton produced   $ 42.57   $ 44.04   $ 1.47   3.4 %
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 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.

57


        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.

        The increase in cost of operations in our Other segment for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily due to the increase in cost of operations in our ancillary businesses.

        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.

58


        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

 
 
  Dollars
  %*
 
 
  (in millions, except %)

 
Central Appalachia   $ 7.9   $ 23.1   $ 15.2   192.0 %
Northern Appalachia     6.7     9.1     2.4   36.1 %
Other     (2.5 )   (1.4 )   1.1   42.8 %
   
 
 
     
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. 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. For our Other segment, net loss decreased by $1.1 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

 
 
  Dollars
  %*
 
 
  (in millions, except %)
 
Central Appalachia   $ 42.7   $ 51.6   $ 8.9   20.8 %
Northern Appalachia     11.6     14.0     2.4   20.2 %
Other     (0.6 )   1.3     2.0   n/a  
   
 
 
     
Total   $ 53.7   $ 66.9   $ 13.3   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 $13.3 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

59



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. 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
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 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 Colorado.

60


        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

 
  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 %

Other

 

 

 

 

 

 

 

 

 

 

 

 
Coal revenues   $ 6.2   $ 8.0            
Freight and handling revenues     1.3     1.7            
Other revenues     0.1     0.8            
   
 
           
Total revenues   $ 7.6   $ 10.5            
   
 
           
Coal revenues per ton   $ 29.02   $ 30.26   $ 1.24   4.3 %

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 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 compare